As filed with the Securities and Exchange Commission on October 30, 2006

Registration No. 333-135537

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Ascent Energy Inc.

(Exact name of registrant as specified in its charter)


Delaware	1311	72-1493233
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

4965 Preston Park Blvd., Suite 800

Plano, Texas 75093

(972) 543-3900

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Terry W. Carter

Chief Executive Officer and President

Ascent Energy Inc.

4965 Preston Park Blvd., Suite 800

Plano, Texas 75093

(972) 543-3900

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:


T. Mark Kelly		J. Michael Chambers
Caroline B. Blitzer		Akin Gump Strauss Hauer & Feld LLP
Vinson & Elkins L.L.P.		1111 Louisiana Street, 44th Floor
2300 First City Tower		Houston, Texas 77002
1001 Fannin		(713) 220-5800
Houston, Texas 77002-6760
(713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated October 30, 2006

PROSPECTUS

Shares

LOGO

Common Stock

This is the initial public offering by Ascent Energy Inc. We are offering shares of our common stock for which no public market currently exists. We currently expect the initial public offering price to be between $ and $ per share. We have applied to list our common stock on The Nasdaq Global Market under the symbol “ASNT.”

Investing in our common stock involves risks. Please read “ Risk Factors” beginning on page 14.


	Per Share	Total

Public offering price	$	$

Underwriting discount	$	$

Proceeds (before expenses) to Ascent Energy Inc.	$	$

We have granted the underwriters a 30-day option to purchase up to an additional shares of our common stock from us on the same terms and conditions as set forth above if the underwriters sell more than shares of our common stock in this offering.

We intend to use a portion of the net proceeds of this offering to repay certain indebtedness outstanding under our credit facility, our senior notes and our senior subordinated notes. Certain of the underwriters and their affiliates are lenders under our credit facility or holders of our senior notes and/or our senior subordinated notes and therefore will receive a portion of those proceeds. In addition, our executive officers will receive a portion of those proceeds in the form of cash bonuses representing a part of the consideration in connection with the termination of an existing incentive plan.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the shares of common stock on or about , 2006.

LEHMAN BROTHERS

JEFFERIES & COMPANY


MORGAN KEEGAN & COMPANY, INC.				PETRIE PARKMAN & CO.


CAPITAL ONE SOUTHCOAST		FORTIS SECURITIES LLC		KEYBANC CAPITAL MARKETS

, 2006

LOGO

TABLE OF CONTENTS


Summary		1
Risk Factors		14
Cautionary Statement Concerning Forward-Looking Statements		25
Use of Proceeds		26
Dividend Policy		27
Recapitalization and Incentive Issuance		27
Capitalization		33
Dilution		34
Unaudited Pro Forma Condensed Consolidated Financial Statements		36
Selected Consolidated Historical Financial Information		45
Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
Business and Properties		77
Management		96
Related Party Transactions		108
Principal Stockholders		116
Description of Capital Stock		121


U.S. Federal Tax Considerations for Non-U.S. Holders		126
Shares Eligible for Future Sale		129
Underwriting		131
Legal Matters		136
Experts		136
Where You Can Find More Information		137
Index to Consolidated Financial Statements		F-1
Glossary of Natural Gas and Oil Terms		A-1
Report of Netherland, Sewell & Associates, Inc., Reserve Engineering Firm as of December 31, 2005		B-1
Report of LaRoche Petroleum Consultants, Ltd., Reserve Engineering Firm as of December 31, 2005		C-1
Report of Netherland, Sewell & Associates, Inc., Reserve Engineering Firm as of June 30, 2006		D-1
Report of LaRoche Petroleum Consultants, Ltd., Reserve Engineering Firm as of June 30, 2006		E-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

Non-GAAP Financial Measures

The body of accounting principles generally accepted in the United States is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or SEC, as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so excluded or included in the most comparable GAAP measure. In this prospectus, we disclose EBITDAX, which is, and PV-10, which may be, a non-GAAP financial measure. See note 3 to “Summary—Summary Consolidated Historical and Pro Forma Financial Information,” note 3 to “Summary—Summary Historical Reserve and Operating Data” and note 2 to the table in “Business and Properties—Our Areas of Operations.”

Natural Gas and Oil Information

We have provided definitions for the natural gas and oil terms used in this prospectus in the “Glossary of Natural Gas and Oil Terms” included as Appendix A. Unless otherwise indicated, all natural gas and oil statistics with respect to our proved reserves as of December 31, 2005 and as of June 30, 2006 set forth in this prospectus are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and LaRoche Petroleum Consultants, Ltd., independent reserve engineering firms. A summary of Netherland, Sewell & Associates, Inc.’s report on our proved reserves as of December 31, 2005 is attached to this prospectus as Appendix B and a

summary of Netherland, Sewell & Associates, Inc.’s report on our proved reserves as of June 30, 2006 is attached to this prospectus as Appendix D. A summary of LaRoche Petroleum Consultants, Ltd.’s report on our proved reserves as of December 31, 2005 is attached to this prospectus as Appendix C and a summary of LaRoche Petroleum Consultants, Ltd.’s report on our proved reserves as of June 30, 2006 is attached to this prospectus as Appendix E.

Our Investors

Unless the context requires otherwise, references in this prospectus to “The Jefferies Investors” means Jefferies & Company, Inc. and certain of its affiliated funds and employees, all of which are our securityholders, and “The TCW Funds” refers to certain affiliated funds that are our securityholders. On September 27, 2006, certain of The TCW Funds transferred their securities in us to an unaffiliated third party pursuant to the liquidation of such funds’ portfolios.

Our Financial Statements

The consolidated financial statements of Ascent Energy Inc. as of December 31, 2004 and December 31, 2005, and for each of the three years in the period ended December 31, 2005, appearing elsewhere in this prospectus and registration statement, have been audited by Ernst & Young LLP. In May 2006, Ernst & Young LLP informed us that the India member firm of E&Y Global had a business arrangement with an affiliate of Jefferies Group, Inc. in the United Kingdom that was not in accordance with the SEC’s auditor independence rules regarding Ernst & Young’s independence in its performance of audit services for us because Jefferies & Company, Inc., which is another affiliate of Jefferies Group, Inc., is a substantial shareholder of us. We have been advised by Ernst & Young LLP and Jefferies Group, Inc. that this business arrangement was terminated in June 2006. Please read “Experts” for additional information.

SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in our common stock. You should read this entire prospectus carefully, including “Risk Factors” and our consolidated financial statements and the notes to those financial statements included elsewhere in this prospectus, as well as the exhibits to the registration statement of which this prospectus forms a part. See “Where You Can Find More Information.” Some of the statements in this prospectus are forward-looking statements. See “Cautionary Statement Concerning Forward-Looking Statements.”

Unless otherwise indicated, the information contained in this prospectus (i) assumes that the underwriters do not exercise their option to purchase additional shares of our common stock and (ii) gives effect to the 1-for- reverse stock split of our common stock expected to be effected in connection with this offering. Unless the context requires otherwise, references in this prospectus to (i) ”Ascent,” “we,” “us” and “our” refer to Ascent Energy Inc., its Parent and its subsidiaries, and (ii) “Parent” or “SLPH” refers to South Louisiana Property Holdings, Inc., formerly known as Forman Petroleum Corporation, which holds approximately 83% of the outstanding common stock (on a non-diluted basis) of Ascent Energy Inc. prior to the consummation of this offering, the Recapitalization and the Incentive Issuance, each as further described below.

Overview

We are a growth-oriented, independent natural gas and oil company engaged in the acquisition, exploration and development of both conventional and unconventional natural gas and oil properties in Texas, Oklahoma, Louisiana and the Appalachian region. Our growth efforts are directed primarily at finding and developing natural gas reserves in unconventional shale gas areas and in known tight gas areas. We operate substantially all of our properties.

Since joining us in mid-2003, our senior management team has embarked on a strategy to acquire and develop a risk-balanced inventory of high growth opportunities, predominately in shale gas. In order to implement this strategy, our new management initially devoted a substantial portion of its efforts to improving our operational efficiency and increasing our liquidity. Since 2004, our management has successfully added unconventional shale gas acreage in four large shale gas exploration areas and entered the prospective tight gas areas of the Cotton Valley trend in east Texas.

Our unconventional shale gas acreage acquired through September 30, 2006 consists of approximately 160,471 gross acres (99,083 net acres) located in the Woodford/Barnett shale in west Texas, the Barnett shale in north Texas, the Woodford shale and the Caney shale in Oklahoma and the Devonian shale in the Appalachian region. We have employed a strategy to acquire a meaningful position in several prospective shale gas areas to diversify risk while providing exposure to significant potential reserves.

As of September 30, 2006, most of our current production was from our approximate 63,136 gross acres (38,102 net acres) of conventional natural gas and oil properties in Texas, Oklahoma and Louisiana, which includes our acreage in the tight gas sands of the Cotton Valley trend in east Texas and the Vicksburg and Wilcox trends in south Texas. Each of these fields is characterized by established production profiles and numerous producing wells. We plan to expand our production and reserves from such conventional areas by further developing our current properties as well as acquiring additional properties that we believe can generate near-term production and cash flow.

producing and 10.5% were proved developed non-producing and 60.3% were oil and NGLs. As of September 30, 2006, we had interests in approximately 137,185 net acres, including approximately 113,765 net undeveloped acres. As of December 31, 2005 and June 30, 2006, the PV-10 of our proved reserves was $371.3 million and $340.0 million, respectively. Our 2005 reserve reports do not reflect any reserves attributable to our unconventional shale gas acreage.

The following table provides certain information regarding our proved reserves as of December 31, 2005 and our September 2006 average net daily production:


Area	Bcfe (1)	MMBoe (1)	% Gas		PV-10 (2) (in millions)		September 2006 Average Net Daily Production (MMcfe/d)	September 2006 Average Net Daily Production (MBoe/d)	Reserve Life (in years) (3)
Oklahoma	62.8	10.5	17.1	%	$	204.3	9.7	1.6	17.7
Texas	31.0	5.2	76.3	%		105.2	11.5	1.9	7.4
Louisiana	12.2	2.0	62.4	%		61.8	2.7	0.4	12.4

Total	106.1	17.7	39.7	%	$	371.3	23.9	3.9	12.2

(1)

As of June 30, 2006, our estimated net proved reserves were 100.8 Bcfe (16.8 MMBoe), which was determined using June 30, 2006 posted prices, in accordance with SEC guidelines, of $6.04 per MMBtu of natural gas and $70.50 per Bbl of oil and includes 61.5 Bcfe (10.3 MMBoe) attributable to our Oklahoma properties, 27.7 Bcfe (4.6 MMBoe) attributable to our Texas properties and 11.6 Bcfe (1.9 MMBoe) attributable to our Louisiana properties. See note 3 to “—Summary Historical Reserve and Operating Data” for additional information regarding adjustments to posted prices. Our June 30, 2006 reserve estimates are based on reserve reports prepared by our independent reserve engineers. See “Business and Properties—Proved Reserves.”

(2)

PV-10 represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production expenses, discounted at 10% per annum to reflect timing of future cash flows and using December 31, 2005 posted prices for natural gas and oil. See note 3 to “—Summary Historical Reserve and Operating Data” for additional information about our computation of PV-10 and its reconciliation to the standardized measure of discounted future net cash flows, which is its most comparable GAAP financial measure as well as price sensitivity analysis related to PV-10.

(3)	Reserve life is calculated by dividing our proved reserves as of December 31, 2005 by our annualized September 2006 average net daily production.

We have a 2006 capital expenditure budget of approximately $80.3 million, of which $59.7 million is targeted for drilling and workovers and $17.8 million is targeted for leasehold acquisitions. Approximately 41% of our 2006 capital expenditure budget is allocated to the acquisition, exploration and development of unconventional shale gas properties, and approximately 59% is allocated to exploration and development of our conventional resource properties, including our tight gas sands. From January 1, 2006 through June 30, 2006, we spent approximately $24.9 million on the drilling of 28 gross wells and the completion of 16 producing wells. Eight of the wells were pending completion and evaluation and three wells were pending pipeline connections as of June 30, 2006. During the year ending December 31, 2006, we anticipate drilling 50 to 60 wells.

Unconventional Shale Gas

Our growth strategy is primarily directed at acquiring opportunities for reserve growth in long-lived reservoirs in unconventional shale gas areas. Unlike with most conventional reservoirs, the determination whether the development of our unconventional shale gas acreage is economically viable could take one to two years from the time we assemble a significant leasehold position. Our unconventional shale gas properties are

located in regions that have experienced significant increases in industry leasing and drilling activity in the past several years. The following is a brief description of our unconventional shale gas acreage:

West Texas Woodford/Barnett Shale. As of September 30, 2006, we had acquired leasehold interests in approximately 80,078 gross (55,498 net) acres in this region, primarily located in Brewster County. We are currently drilling our initial test wells in this region. We are the operator of this acreage with an average working interest of approximately 75%.

North Texas Barnett Shale. As of September 30, 2006, we had acquired leasehold interests in approximately 21,200 gross (20,396 net) acres in this region. We expect to drill our initial test wells on a portion of this acreage in the first half of 2007. We are the operator of this acreage with a 100% working interest.

Oklahoma Woodford Shale and Caney Shale. As of September 30, 2006, we had acquired leasehold interests in approximately 9,134 gross (2,351 net) acres in the Woodford shale and approximately 3,848 gross (2,850 net) acres in the Caney shale. We have drilled and completed our first vertical test well in the Woodford shale. Based on the initial production results of approximately 411 Mcf/d from this well, we plan to drill six additional wells in the Woodford shale during the remainder of 2006. We have also drilled our initial horizontal well in the Caney shale. We are the operator of our Woodford shale acreage and our Caney shale acreage with working interests in each ranging from 50% to 80%.

Appalachian Devonian Shale. As of September 30, 2006, we had acquired leasehold interests in approximately 46,210 gross (17,987 net) acres in this region. We have initiated a five-well drilling program to test for natural gas and gather data that will help us determine the most appropriate drilling and completion strategy. We are the operator of this acreage with a 42% working interest. During September 2006, we entered into an agreement to acquire the outside 58% working interest in this region, which would bring our working interest to 100%. This agreement is subject to the negotiation of definitive documentation satisfactory to all parties, and consummation will be subject to customary closing conditions.

East Texas Tight Gas

Our growth strategy also includes acquiring property in tight gas sand areas in east Texas that has existing infrastructure to transport natural gas to market. This area is characterized by lower exploration and development risk than many of our other projects. We believe there are several offset opportunities that can be enhanced with the use of modern completion and stimulation techniques. We began acquiring leasehold interests and drilling in this area in the fourth quarter of 2005. As of June 30, 2006, we had drilled nine wells in this area with a 100% success rate. As of September 30, 2006, we had acquired leasehold interests in approximately 7,119 gross (4,958 net) acres in the tight gas sands of the Cotton Valley trend in east Texas. We are the operator of this acreage with working interests ranging from 38% to 100%. Our year-end December 31, 2005 proved reserves from this acreage are associated with 12 proved undeveloped and proved developed producing locations.

South Texas Natural Gas

We are continuously seeking to expand our acreage in south Texas, including the Vicksburg and Wilcox trends, by acquiring property located in mature producing areas that we believe can generate near-term production and cash flow. As of September 30, 2006, we owned leasehold interests in approximately 4,228 gross (3,337 net) acres in the Vicksburg trend and approximately 3,385 gross (2,989 net) acres in the Wilcox trend, including producing acreage in the region. From January 1, 2006 to June 30, 2006, we drilled three wells in this area with a 100% success rate. We are the operator of this acreage with working interests ranging from 75% to

100%. As of June 30, 2006, we had 34 producing wells in this region. Our year-end December 31, 2005 proved reserves from this acreage are associated with 49 proved undeveloped and proved developed producing locations.

Our Strengths

High Quality Asset Base in Mature Producing Basins. Our producing properties, consisting of approximately 36,951 gross acres (23,420 net acres) as of September 30, 2006, are located in prolific producing areas of south and east Texas, Oklahoma and Louisiana, with long histories of natural gas and oil production. We support our unconventional shale gas exploration with the cash flow generated from these mature properties.

Significant Growth Opportunities. We believe our approximate two-year inventory of conventional and tight gas drilling projects will generate near-term production growth and cash flow. In addition, we have acquired acreage positions in several unconventional shale gas areas where industry drilling and production activity has increased in the past several years. If our initial unconventional shale gas drilling projects are successful, we expect to increase significantly our long-term reserves, production and drilling inventory.

Effective Risk Management. Our areas of operation provide us with geographic, geological and operational diversity. Our diversified inventory of conventional and unconventional resource drilling locations ranges from lower risk development locations to higher risk exploration locations, including most of our unconventional shale gas acreage, that expose us to opportunities for greater reserve and production growth.

Experienced, Incentivized Management Team with Strong Technical Capability. Our senior management team has on average more than 28 years of industry experience and has considerable technical expertise in engineering, geoscience and field operations. Our in-house technical personnel have extensive experience in geology, geophysics, engineering and drilling and completion technology, including horizontal drilling and fracturing technology. Our officers will beneficially own approximately % of our common stock after the consummation of this offering, the Recapitalization and the Incentive Issuance.

Our Business Strategy

Drive Growth Through the Drillbit. We intend to create near-term reserve and production growth from our approximate two-year inventory of drilling opportunities. We anticipate most of our cash flow in the next several years will be generated from our existing producing properties and proved reserves as well as our lower-risk drilling opportunities, exploration and development. We intend to allocate a significant portion of our exploration budget to our higher-risk unconventional shale gas exploration and our tight gas sands exploration.

Focus on Growing Our Inventory of Shale Gas Opportunities. We intend to continue expanding our acreage positions in multiple shale gas areas. As of September 30, 2006, we had leasehold interests in approximately 160,471 gross (99,083 net) acres of prospective shale gas property over four areas. We have budgeted approximately $14.0 million to acquire shale gas acreage in 2006.

Pursue Tight Gas Sand Opportunities. We are pursuing multiple tight gas sand opportunities. We believe that our tight gas sand areas have significant potential reserves that have not been depleted by the use of past drilling and completion techniques. We typically pursue opportunities in known tight gas sand areas that have existing infrastructure to transport natural gas to the market. We have budgeted approximately $36.3 million to drill 16 wells in our tight gas sand operations in south and east Texas by the end of 2006.

risk as well as the cost of exploration and development drilling and ongoing operations. We believe that in the competitive market for drilling rigs it is advantageous to be in a position to make longer term commitments to drilling rig operators in order to secure service.

Seek Acquisitions that Complement Our Exploration and Development Plans. We pursue acquisitions that add efficiency to our existing operations or represent attractive additions to our exploration and development prospect inventory in large, mature producing regions. We maintain a disciplined acquisition process to help ensure that acquisitions fit our strategic and financial objectives.

Recapitalization and Incentive Issuance

Immediately prior to the sale of our shares in this offering, we intend to consummate a corporate recapitalization involving the following transactions:

•

we will effect a 1-for- reverse stock split of our Parent’s common stock and corresponding payment of cash in lieu of fractional shares;

•

our Parent will become a wholly owned subsidiary of Ascent Energy Inc. in a tax-free transaction that we refer to as the “Parent Merger;”

•

we will issue shares of our common stock in repayment of our senior subordinated notes that are not repaid with the net proceeds of this offering in a transaction that we refer to as the “Debt Exchange;” and

•

we will issue shares of our common stock in exchange for our outstanding Series A preferred stock (including accrued but unpaid dividends thereon) and warrants in a transaction that we refer to as the “Preferred Exchange.”

We refer to our Parent’s reverse stock split, the Parent Merger, the Debt Exchange and the Preferred Exchange, collectively, as the “Recapitalization.”

In addition, we intend to terminate our Amended and Restated Equity Incentive Plan, or 2005 Incentive Plan, and the awards granted thereunder. Participants in the 2005 Incentive Plan will receive cash bonuses and awards of restricted stock, which vest over a three year period, in exchange for terminating their rights under the 2005 Incentive Plan. We refer to this exchange as the “Incentive Issuance.” The Incentive Issuance is contingent on the consummation of this offering and the Recapitalization and the consent of each of the holders of awards under our 2005 Incentive Plan.

For additional information about the Recapitalization and the Incentive Issuance, please see “Recapitalization and Incentive Issuance” and “Use of Proceeds.”

The Jefferies Investors, including Jefferies & Company, Inc., one of the underwriters in this offering, and certain of its affiliates, and The TCW Funds are the principal holders of our securities, and will receive cash and

shares of our common stock in this offering and the Recapitalization. In addition, our executive officers are expected to participate in the Incentive Issuance and to receive cash and shares of our common stock in this offering and the Incentive Issuance. Please see “Related Party Transactions,” “Principal Stockholders” and “Management.”

Our Company

Ascent Energy Inc. is a Delaware corporation formed in 2001. Our principal executive offices are located at 4965 Preston Park Blvd., Suite 800, Plano, Texas 75093. Our telephone number at that address is (972) 543-3900. We maintain a web site at www.ascentenergy.info and after this offering will maintain a web site at www.ascentenergy.com. These web sites contain or will contain information about us. Our web sites and the information contained on them and connected to them are not a part of, and will not be deemed incorporated by reference into, this prospectus.

THE OFFERING

Common stock offered

Underwriters’ option to purchase additional shares

Common stock outstanding immediately after the completion this offering, the Recapitalization and the Incentive Issuance (1)

Use of proceeds

We estimate that the net proceeds from this offering, after deducting underwriting discounts and estimated offering expenses payable by us, will be approximately $ million, based on an initial public offering price of $ per share. We intend to use the net proceeds of this offering to repay a portion of the indebtedness outstanding under our credit facility, all of our senior notes and a portion of our senior subordinated notes, to pay $ million of cash bonuses to employees participating in the Incentive Issuance, to pay cash in lieu of fractional shares pursuant to a reverse stock split of the Parent’s common stock to be effected in connection with the Parent Merger and for general corporate purposes, which could include refinancing some of our derivative arrangements. See “Use of Proceeds.”

The Jefferies Investors, including Jefferies & Company, Inc., one of the underwriters in this offering, are holders of our senior notes and our senior subordinated notes and therefore are expected to receive a portion of the net proceeds of this offering and shares of common stock in connection with this offering and the Recapitalization. In addition, affiliates of certain of the underwriters in this offering are lenders under our credit facility and accordingly are expected to receive a portion of the net proceeds of this offering. See “Use of Proceeds,” “Related Party Transactions—Recapitalization,” “Principal Stockholders,” and “Underwriting.”

Our executive officers are expected to participate in the Incentive Issuance and to receive a portion of the net proceeds of this offering and shares of our common stock in connection with this offering and the Incentive Issuance. See “Use of Proceeds,” “Management—Termination of 2005 Incentive Plan,” “Related Party Transactions—Termination of 2005 Incentive Plan” and “Principal Stockholders.”

Nasdaq Global Market symbol

“ASNT”

Risk factors

See “Risk Factors” beginning on page 14 and the other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our common stock.

(1)	Excludes shares reserved for issuance under our 2006 Long-Term Incentive Plan, none of which shares are subject to options outstanding at the time of this offering.

SUMMARY CONSOLIDATED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION

The following tables present our summary consolidated historical and pro forma condensed consolidated financial information for the periods presented. The summary consolidated historical financial information as of and for each of the three years ended December 31, 2005 has been derived from our audited consolidated financial statements and related notes. The audited consolidated financial statements and related notes as of December 31, 2004 and December 31, 2005 and for each of the three years ended December 31, 2005 are included elsewhere in this prospectus. The summary consolidated historical financial information as of June 30, 2006 and for the six months ended June 30, 2005 and June 30, 2006 has been derived from our unaudited consolidated financial statements and related notes included elsewhere in this prospectus which, in the opinion of management, have been prepared on the same basis as our audited consolidated financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information.

The summary pro forma condensed consolidated balance sheet data as of June 30, 2006 assumes that the Recapitalization, this offering and the application of the net proceeds from this offering occurred on June 30, 2006. The summary pro forma condensed consolidated statement of operations for the year ended December 31, 2005 and for the six months ended June 30, 2005 and June 30, 2006 assumes that the Recapitalization, this offering and the application of the net proceeds from this offering occurred on January 1, 2005, but does not give effect to approximately $ million of compensation expense to be recognized immediately upon the payment of cash bonuses in the Incentive Issuance with a portion of the net proceeds of this offering. Except for the adjustments to cash and accumulated deficit on the summary pro forma condensed consolidated balance sheet for the use of a portion of the net proceeds of this offering to pay cash bonuses in connection with the Incentive Issuance, the summary pro forma condensed consolidated financial information does not give effect to the Incentive Issuance. We expect to recognize approximately $ million of compensation expense immediately upon payment of cash bonuses in the Incentive Issuance and approximately $ million of compensation expense over a three-year vesting period related to the issuance of shares of restricted stock in the Incentive Issuance. See “Recapitalization and Incentive Issuance.” Unless otherwise indicated, the summary pro forma condensed consolidated financial information has been derived from our unaudited pro forma condensed consolidated financial statements and related notes included elsewhere in this prospectus and gives pro forma effect to the Recapitalization, this offering and the application of the net proceeds of this offering as described in “Use of Proceeds.” See “Unaudited Pro Forma Condensed Consolidated Financial Statements” for further discussion.

This information is only a summary and you should read it in conjunction with the material contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with the historical and pro forma condensed consolidated financial statements and related notes included elsewhere in this prospectus.

Our historical consolidated financial statements for the years ending prior to December 31, 2005 have been restated to reflect our conversion to the successful efforts method of accounting for our investment in natural gas and oil properties and to correct our previously recorded income tax provision. Our audited historical consolidated financial statements for the years ended December 31, 2003 and December 31, 2004 have been restated to reflect our previously understated asset retirement obligation.

Prior to the Spring of 2003, we focused on the exploration and development of the reserves we acquired in connection with our formation in 2001. Since joining us in 2003, our senior management team has embarked on a strategy to acquire and develop a risk-balanced inventory of high growth opportunities. In order to implement this strategy, our management initially devoted a substantial portion of its efforts to increasing our liquidity and improving our operational efficiency. In July 2004, we completed a financial restructuring that allowed the operating subsidiaries of Ascent Energy Inc., as borrowers, to enter into a new credit facility and reduced our debt service obligations by permitting us to pay in kind certain interest obligations.

For the foregoing reasons, our summary consolidated historical and pro forma condensed consolidated financial information may not be meaningful or indicative of our future results.


	Historical															Pro Forma
	Year Ended December 31,									Six Months Ended June 30,						Year Ended December 31,	Six Months Ended June 30,	Six Months Ended June 30,
	2003			2004			2005			2005			2006			2005	2005	2006
	(Restated)			(Restated)						(Unaudited)						(Unaudited)	(Unaudited)	(Unaudited)
	(in thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil	$	20,377		$	25,431		$	33,228		$	15,694		$	19,631
Natural gas		24,553			22,021			36,634			14,848			16,271
NGLs		2,027			3,257			3,714			1,776			1,713

Total		46,957			50,709			73,576			32,318			37,615
Expenses:
Production and ad valorem taxes		4,307			3,091			3,332			1,731			2,231
Lease operating expenses		11,915			12,018			11,594			5,487			6,398
General and administrative expenses		10,388			8,272			8,436			3,851			5,548
Exploration expenses		5,630			854			3,460			444			818
Depreciation, depletion and amortization		21,539			31,207			20,771			10,623			10,393
Property impairments		3,802			20,711			1,254			—			—
Derivative loss		—			6,604			33,851			17,983			6,725

Total operating expenses		57,581			82,757			82,698			40,119			32,113

Income (loss) from operations		(10,624	)		(32,048	)		(9,122	)		(7,801	)		5,502
Interest and other income		7			203			561			78			110
Interest expense		(13,661	)		(16,958	)		(19,496	)		(9,286	)		(11,266	)

Loss before income taxes		(24,278	)		(48,803	)		(28,057	)		(17,009	)		(5,654	)
Income tax benefit (expense)		8,624			12,472			209			127			(317	)

Loss before cumulative effect of change in accounting principle		(15,654	)		(36,331	)		(27,848	)		(16,882	)		(5,971	)
Cumulative effect of change in accounting principle, net of income tax of $273 in 2003 (1)		262			—			—			—			—

Net loss		(15,392	)		(36,331	)		(27,848	)		(16,882	)		(5,971	)
Preferred stock dividends (2)		(3,976	)		(3,367	)		(3,358	)		(1,665	)		(1,665	)

Net loss attributable to common shares	$	(19,368	)	$	(39,698	)	$	(31,206	)	$	(18,547	)	$	(7,636	)

Net loss per common share:
Basic and diluted net loss per common share	$	(3.63	)	$	(6.67	)	$	(5.25	)	$	(3.12	)	$	(1.28	)
Basic and diluted net loss per common share (pro forma for reverse stock split)
Selected Cash Flow and Other Financial Data:
Net cash provided by operating activities	$	16,935		$	17,369		$	31,475		$	14,671		$	18,281
Net cash used in investing activities		(39,121	)		(22,584	)		(35,019	)		(17,316	)		(36,490	)
Net cash provided by financing activities		26,236			1,650			4,108			4,550			18,425
Capital expenditures		39,121			22,985			34,588			16,296			36,554
EBITDAX (3)		20,354			28,658			37,342			17,351			18,766


	Historical															Pro Forma
	As of December 31,									As of June 30,						As of June 30,
	2003			2004			2005			2005			2006			2006
	(Restated)			(Restated)						(Unaudited)						(Unaudited)
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	4,081		$	516		$	1,080		$	2,421		$	1,296
Total assets		200,374			169,267			187,221			179,360			215,059
Long-term debt (4)		141,493			164,954			185,223			174,498			212,429
Preferred stock (including accrued but unpaid dividends) (5)		46,265			9,577			12,865			11,208			14,496
Stockholders’ deficit		(40,587	)		(36,060	)		(67,196	)		(54,572	)		(74,796	)
Total liabilities and stockholders’ equity		200,374			169,267			187,221			179,360			215,059

(1)	Reflects adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), effective January 1, 2003.

(2)

Represents accrued but unpaid dividends on our Series A preferred stock and Series B preferred stock. In August 2003, all outstanding shares of the Series B preferred stock were converted into an aggregate of one million shares of our common stock ( shares of our common stock pro forma for the reverse stock split), and all accrued but unpaid dividends thereon were declared and paid in cash.

(3)

EBITDAX is a non-GAAP financial measure. EBITDAX represents earnings before interest expense, income tax (expense) benefit, depreciation, depletion and amortization, property impairments, exploration expenses, non-cash hedging and derivative losses and cumulative effect of change in accounting principle. The following table shows our calculation of EBITDAX and reconciles it to net cash provided by operating activities, which we believe is the most comparable GAAP financial measure. EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flow as determined in accordance with GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and the historical costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We also believe EBITDAX assists investors in comparing a company’s liquidity on a consistent basis without regard to depreciation, depletion and amortization, property impairment and exploration expenses, which can vary significantly depending upon accounting methods. Our credit facility requires that, as of the last day of each fiscal quarter, our ratio of total debt to EBITDAX for the preceding four fiscal quarters be not greater than 2.5 to 1.0 and that our ratio of EBITDAX to cash interest expense (plus certain subsidiary dividends) for the preceding four fiscal quarters be not less than 2.5 to 1.0. As of June 26, 2006, our credit facility defines EBITDAX consistently with the definition of EBITDAX used and presented by us in this prospectus. As of June 30, 2006, our total debt to EBITDAX ratio was approximately 1.8 to 1.0 and our EBITDAX to cash interest expense ratio was approximately 9.0 to 1.0.


	Year Ended December 31,									Six Months Ended June 30,
	2003			2004			2005			2005			2006
	(Restated)			(Restated)						(Unaudited)
	(in thousands)
Net loss	$	(15,392	)	$	(36,331	)	$	(27,848	)	$	(16,882	)	$	(5,971	)
Interest expense		13,661			16,958			19,496			9,286			11,266
Income tax (benefit) expense		(8,624	)		(12,472	)		(209	)		(127	)		317
Depreciation, depletion and amortization		21,539			31,207			20,771			10,623			10,393
Property impairments		3,802			20,711			1,254			—			—
Exploration expenses		5,630			854			3,460			444			818
Non-cash hedging and derivative losses		—			7,731			20,418			14,007			1,943
Cumulative effect of change in accounting principle		(262	)		—			—			—			—

EBITDAX		20,354			28,658			37,342			17,351			18,766
Exploration expenses		(4,604	)		(854	)		(3,460	)		(444	)		(514	)
Interest expense		(13,003	)		(2,303	)		(3,392	)		(1,488	)		(2,447	)
Gain on sale of assets		—			(200	)		(658	)		(51	)		(71	)
Other non-cash gains		(52	)		21			6			—			17
Income tax expense		—			—			(98	)		(33	)		(156	)
Changes in assets and liabilities		14,240			(7,953	)		1,735			(664	)		2,686

Net cash provided by operating activities	$	16,935		$	17,369		$	31,475		$	14,671		$	18,281

(4)	All periods include borrowings under our credit facility and the aggregate principal amount of outstanding senior notes and senior subordinated notes, and all periods, except the year ended December 31, 2003, include long-term accrued interest on our senior notes and senior subordinated notes.

(5)

The amounts for the year ended December 31, 2003 represent the book value of our Series A preferred stock plus all accrued but unpaid dividends thereon. The amounts for all other periods represent only accrued but unpaid dividends on the Series A preferred stock. In December 2004, the terms of the Series A preferred stock were amended to eliminate our requirement to redeem the outstanding shares of Series A preferred stock on a specified date. The amendment resulted in a balance sheet reclassification of the book value of the Series A preferred stock to stockholders’ deficit.

SUMMARY HISTORICAL RESERVE AND OPERATING DATA

The following tables present summary historical operating information for the years ended December 31, 2003, December 31, 2004 and December 31, 2005 and for the six months ended June 30, 2005 and June 30, 2006. The following tables also present summary historical information regarding our estimated net proved natural gas and oil reserves as of December 31, 2003, 2004 and 2005. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC and, except as otherwise indicated, give no effect to federal or state income taxes. For additional information about our reserves, please read “Business and Properties—Proved Reserves” and the information regarding our oil and gas activities beginning on page F-32.

Upon joining us in mid-2003, our senior management team undertook a detailed review and analysis of our proved natural gas and oil reserves, which resulted in a downward revision of our estimates of proved natural gas and oil reserves by a total of 37.7 Bcfe (6.3 MMBoe) for the year ended December 31, 2003 and by an additional 62.9 Bcfe (10.5 MMBoe) during the year ended December 31, 2004. The 2003 revision included approximately 22.3 Bcfe (3.7 MMBoe) of proved non-producing and proved undeveloped reserves plus a subsequent 15.4 Bcfe (2.6 MMBoe) reduction in underperforming producing properties. The 2004 revision included approximately 28.5 Bcfe (4.8 MMBoe) of proved non-producing reserves and 34.4 Bcfe (5.7 MMBoe) of proved undeveloped reserves. As a result of the events leading up to our July 2004 financial restructuring, we were forced to delay our 2004 capital expenditure program which resulted in a decline in our natural gas and oil production for the year ended December 31, 2004, because we were unable to offset natural production declines with new production. We had further production declines for the year ended December 31, 2005 resulting from a reduction in our capital expenditure program due to rig delays and the impact of Hurricanes Katrina and Rita. Our September 2006 production from our South Louisiana properties was 2.7 MMcfe/d (0.4 MBoe/d), which is approximately 69% of our average daily pre-hurricane production from these properties during February 2005 through July 2005. We continue to see some post-hurricane improvement in production from our South Louisiana properties; however, it is common for production from mature water-drive wells not to return to pre-shut-in production rates after being shut-in. We do not expect that all of these wells will return completely to pre-hurricane production rates. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” including “—Overview—Reserve Write Down.”

For the foregoing reasons, our summary historical reserve and operating data may not be meaningful or indicative of our future reserve and operating data.


	Year Ended December 31,						Six Months Ended June 30,
	2003		2004		2005		2005		2006
	(Restated)		(Restated)
Production data:
Oil (MBbls)		688		625		598		309		298
Natural gas (MMcf)		6,545		5,158		4,592		2,348		2,324
NGLs (MBbls)		107		120		107		60		43
Combined volumes (MMcfe)		11,318		9,630		8,826		4,560		4,370
Combined volumes (MBoe)		1,886		1,605		1,471		760		728
Average prices (net of hedging):
Oil (per Bbl)	$	29.60	$	40.66	$	55.55	$	50.79	$	65.95
Natural gas (per Mcf)		3.75		4.27		7.98		6.32		7.00
NGLs (per Bbl)		21.37		27.15		34.56		29.76		39.41
Combined (per Mcfe)		4.17		5.27		8.34		7.09		8.61
Combined (per Boe)		25.03		31.59		50.02		42.52		51.64


	Year Ended December 31,						Six Months Ended June 30,
	2003		2004		2005		2005		2006
	(Restated)		(Restated)
Average expenses (per Mcfe):
Production and ad valorem taxes	$	0.38	$	0.32	$	0.38	$	0.38	$	0.51
Lease operating expenses		1.05		1.25		1.31		1.20		1.46
General and administrative expenses		0.92		0.86		0.96		0.84		1.27
Exploration expenses		0.50		0.09		0.39		0.10		0.19
Depreciation, depletion and amortization		1.90		3.24		2.35		2.33		2.38
Property impairments		0.34		2.15		0.14		—		—
Derivative loss		—		0.69		3.84		3.94		1.54
Average expenses (per Boe):
Production and ad valorem taxes	$	2.28	$	1.93	$	2.26	$	2.28	$	3.06
Lease operating expenses		6.32		7.49		7.88		7.22		8.78
General and administrative expenses		5.51		5.15		5.73		5.07		7.62
Exploration expenses		2.98		0.53		2.35		0.58		1.12
Depreciation, depletion and amortization		11.42		19.44		14.08		13.98		14.27
Property impairments		2.02		12.90		0.85		—		—
Derivative loss		—		4.11		23.01		23.66		9.23


	As of December 31,
	2003		2004		2005
	(dollars in thousands)
Estimated net proved reserves (1):
Oil (MBbls)		13,620		9,578		9,572
Natural gas (MMcf)		80,423		37,311		42,066
NGLs (MBbls) (2)		—		1,119		1,098
Total (MMcfe)		162,141		101,491		106,089
Total (MBoe)		27,024		16,915		17,681
PV-10 (3)	$	379,494	$	239,632	$	371,303
Standardized measure of discounted future net cash flows (3)	$	271,715	$	190,322	$	280,928

(1)	In accordance with SEC requirements, our estimated net proved reserves, PV-10 and the standardized measure of discounted future net cash flows were determined using the following year-end posted prices for natural gas and oil:


	Year Ended December 31,
	2003		2004		2005
Natural gas (per MMBtu)	$	5.97	$	5.74	$	8.17
Oil (per Bbl)		29.25		40.00		57.75

(2)	Oil reserve data as of December 31, 2003 includes NGLs.

(3)

PV-10 may be considered a non-GAAP financial measure; therefore, the following table reconciles our calculation of PV-10 to the standardized measure of discounted future net cash flows, which is the most comparable GAAP financial measure. PV-10 is the computation of the standardized measure of discounted future net cash flows on a pre-tax basis. In order to calculate our natural gas reserve estimates, the posted natural gas prices in note 1 above were adjusted lease by lease to reflect adjustments for energy composition, quality, gathering and transportation fees, marketing fees and regional price differentials. In order to calculate our oil reserve estimates, the posted oil prices in note 1 above were adjusted lease by lease to reflect adjustments for gravity, crude quality, transportation fees, marketing fees and regional price differentials. These adjustments to the year-end posted prices resulted in the following average prices:


	Year Ended December 31,						Six Months Ended June 30, 2006
	2003		2004		2005		Six Months Ended June 30, 2006
Natural gas (per MMBtu)	$	6.12	$	5.96	$	8.76	$	6.02
Oil and NGLs (per Bbl)		30.79		41.30		57.94		70.33

We estimate that if natural gas prices declined by $0.25 per Mcf from the price used in determining our proved reserves as of December 31, 2005, the PV-10 of our proved reserves as of December 31, 2005 would decrease from $371.3 million to $364.9 million and the quantity of our reserves would decline by 825 MMcf of natural gas and 40,000 Bbls of oil and NGLs. We estimate that if oil prices declined by $1.00 per Bbl from the price used in determining our proved reserves as of December 31, 2005, then the PV-10 of our proved reserves as of December 31, 2005 would decrease from $371.3 million to $366.5 million and the quantity of our reserves would decline by 43 MMcf of natural gas and 44,300 Bbls of oil and NGLs. We estimate that if natural gas prices declined by $0.25 per Mcf from the price used in determining our proved reserves as of June 30, 2006, the PV-10 of our proved reserves as of June 30, 2006 would decrease from $340.0 million to $334.3 million and the quantity of our reserves would decline by 101.9 MMcf of natural gas and 6,200 Bbls of oil and NGLs. We estimate that if oil prices declined by $1.00 per Bbl from the price used in determining our proved reserves as of June 30, 2006, then the PV-10 of our proved reserves as of June 30, 2006 would decrease from $340.0 million to $335.7 million and the quantity of our reserves would decline by 33.7 MMcf of natural gas and 16,800 Bbls of oil and NGLs. Estimates of PV-10 of reserves and the quantity of reserves would likely decline at a rate proportionately greater than specified above if natural gas and oil prices decline significantly from those used in calculating such estimates. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating natural gas and oil companies. Management also believes that PV-10 is relevant and useful for evaluating the relative monetary significance of our natural gas and oil properties. Further, professional analysts and sophisticated investors may use the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Management also uses this pre-tax measure when assessing the potential return on investment related to our natural gas and oil properties and in evaluating acquisition candidates. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating us. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated natural gas and oil reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.


	Year Ended December 31,
	2003			2004			2005
	(in thousands)
Future cash inflows	$	911,612		$	664,223		$	986,683
Less: Future production costs		(235,308	)		(199,622	)		(276,962	)
Less: Future development costs		(56,733	)		(48,002	)		(56,042	)

Future net cash flows		619,571			416,599			653,679
Less: 10% discount factor		(240,077	)		(176,967	)		(282,376	)

PV-10		379,494			239,632			371,303
Less: Undiscounted income taxes		(187,825	)		(102,131	)		(179,732	)
Plus: 10% discount factor		80,046			52,821			89,357

Discounted income taxes		(107,779	)		(49,310	)		(90,375	)

Standardized measure of discounted future net cash flows	$	271,715		$	190,322		$	280,928

Our independent reserve engineers also prepared reports of our estimated net proved natural gas and oil reserves as of June 30, 2006. As of June 30, 2006, our estimated net proved reserves were 100.8 Bcfe (16.8 MMBoe), which included 37,401 MMcf of natural gas and 10,569 MBbls of oil and NGLs. These estimates were determined using a price of $6.04 per MMBtu of natural gas and $70.50 per Bbl of oil as compared to our December 31, 2005 year-end pricing of $8.17 per MMBtu of natural gas and $57.75 per Bbl of oil. As of June 30, 2006, the PV-10 of our proved reserves was $340.0 million.

RISK F ACTORS

An investment in our common stock involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common stock.

Risks Related to Our Business and Our Industry

Natural gas and oil prices are volatile and a decline in natural gas and oil prices could materially and adversely affect our financial results and impede our growth.

Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. Moreover, changes in natural gas and oil prices have a significant impact on the value of our reserves. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Prices for natural gas and oil may fluctuate widely in response to a variety of additional factors that are beyond our control, such as:

•

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

•

commodity processing, gathering and transportation availability;

•

domestic and global political and economic conditions;

•

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

•

weather conditions, including hurricanes;

•

technological advances affecting energy consumption;

•

domestic and foreign governmental regulations; and

•

the price and availability of alternative fuels.

Lower natural gas and oil prices may not only decrease our revenue on a per share basis, but also may reduce the amount of natural gas and oil that we can produce economically. This reduction may result in our having to make substantial downward adjustments to our estimated proved reserves.

Our natural gas and oil reserves and future production and, therefore, our future cash flow and revenue, are highly dependent on our successfully developing our undeveloped leasehold acreage, including our unconventional shale gas acreage.

Approximately 82% of our net leasehold acreage as of June 30, 2006, which includes our unconventional shale gas acreage, was undeveloped. Our business strategy involves using a significant amount of our operational and financial resources and cash flow for acquiring, exploring and developing our unconventional shale gas acreage. Unconventional shale gas acreage requires greater amounts of time and capital to develop, and to determine whether commercially productive reserves exist, than conventional acreage. As a result, we may not successfully develop our undeveloped acreage on the schedule we have established, at the costs we have budgeted, or at all. Our future natural gas and oil reserves and production and, therefore, our future cash flow and revenue are highly dependent on our successfully developing our undeveloped leasehold acreage. If we are unsuccessful in developing our undeveloped acreage as we have anticipated, our future cash flow and revenues could be materially and adversely affected.

Unless we replace our natural gas and oil reserves, our reserves and production will decline, which would materially and adversely affect our business, financial condition and results of operations.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Thus, our future natural gas and oil reserves and

production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently developing our current reserves and acquiring additional recoverable reserves, including additional recoverable reserves within our unconventional shale gas acreage. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected. Our combined natural gas, oil and NGL production has declined in each of the last two years from 11,318 MMcfe (1,886 MBoe) in 2003 to 9,630 MMcfe (1,605 MBoe) in 2004 to 8,826 MMcfe (1,471 MBoe) in 2005. In addition, our combined production for the nine months ended September 30, 2006 declined to 6,626 MMcfe (1,104 MBoe) as compared to combined production for the nine months ended September 30, 2005 of 6,731 MMcfe (1,122 MBoe). Our independent reserve engineers have estimated that our natural gas and oil production in 2006 from our proved developed producing reserves as of December 31, 2005 will decline by approximately 18.6% from our production from those reserves for the year ended December 31, 2005.

If natural gas or oil prices decrease, we may be required to write down the capitalized cost of individual natural gas and oil properties.

Effective January 1, 2005, we changed our accounting method for our natural gas and oil properties from the full cost method to the successful efforts method. Under the successful efforts method of accounting, we capitalize all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. All costs related to unsuccessful exploratory wells are expensed once the well is determined to be unsuccessful. Other exploratory costs, including geological and geophysical costs, are expensed as incurred.

The capitalized costs of our natural gas and oil properties, on a field-by-field basis, may exceed the estimated undiscounted future net cash flows of that field. This may occur when natural gas or oil prices are low or if we have substantial downward adjustments to our estimated proved reserves or increases in our estimates of development costs. In such event, we would be required to record impairment charges to reduce the capitalized costs of each such field to our estimate of the field’s fair market value. Any impairment reduces our earnings and stockholders’ equity. Once incurred, an impairment charge cannot be reversed at a later date even if we experience increases in the price of natural gas or oil, or both, or increases in the amount of our estimated proved reserves. For the years ended December 31, 2005, 2004 and 2003, we recorded impairment charges of approximately $1.3 million, $20.7 million and $3.8 million, respectively, to reduce the capitalized costs of our fields to estimated fair market value.

The marketability of our production depends on gathering systems, transportation facilities and processing facilities that we do not control or that may not currently exist. If these systems and facilities become unavailable or are otherwise unable to provide services, or are not developed in areas without current infrastructure, our business, financial condition and results of operations could be materially and adversely affected.

The marketability of our natural gas and oil production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation barges and processing facilities owned by third parties. We do not control most of these facilities and they may not be available to us in the future. Alternative delivery methods could either be prohibitively expensive or available only after a period of delay, if at all, at certain well sites. We may be required to shut in wells for lack of a market or because access to natural gas pipelines, gathering system capacity or processing facilities may be limited or unavailable. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market. As a result, if one or more transportation, gathering or processing facilities that we depend on became unavailable or otherwise unable to provide services, our revenues and, in turn, our business, financial condition and results of operations could be materially and adversely affected. In addition, most of the unconventional shale gas and tight gas areas in which we own acreage do not currently contain gathering systems, transportation facilities or processing facilities. If our drilling efforts are successful within these areas,

we will need access to transportation and gathering facilities to deliver our production to market. Until such facilities are available, we would be unable to realize revenue from such production and, as a result, our business, financial condition and results of operations could be materially and adversely affected.

Any significant inaccuracies in our reserve estimates, or the underlying assumptions on which such estimates were based, could materially affect the quantities and present value of our reserves.

On several occasions, inaccurate estimates of our proved reserves have required downward revisions in our estimates of our proved reserves. Any further significant inaccuracies in the interpretations, assumptions or projections used to develop our natural gas and oil reserves could materially affect the estimated quantities and present value of our reserves as shown in this prospectus. In addition, actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves as shown in this prospectus.

The present values referred to in this prospectus may not represent the current market value of our estimated natural gas and oil reserves. The timing of our production and the expenses related to the development of our natural gas and oil properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 estimates are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimates. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the 10% discount factor we use when calculating our PV-10 estimates may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. For example, if natural gas prices decline by $0.25 per Mcf, the PV-10 of our total proved reserves as of December 31, 2005 would decrease from approximately $371.3 million to $364.9 million, and if oil prices decline by $1.00 per Bbl, the PV-10 of our total proved reserves as of December 31, 2005 would decrease from approximately $371.3 million to $366.5 million. If natural gas prices decline by $0.25 per Mcf, the PV-10 of our total proved reserves as of June 30, 2006 would decrease from $340.0 million to $334.3 million, and if oil prices decline by $1.00 per Bbl, the PV-10 of our total proved reserves as of June 30, 2006 would decrease from $340.0 million to $335.7 million.

The unavailability or high cost of drilling rigs, equipment, supplies or personnel could adversely affect our ability to execute our exploration and development plans.

The natural gas and oil industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may be substantially increased and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our business, financial condition and results of operations could be materially and adversely affected.

We depend on a limited number of key personnel who would be difficult to replace.

We depend on the performance of our executive officers and other key employees. The loss of any member of our senior management or other key employee, including Terry W. Carter, our President and Chief Executive Officer, Eddie M. LeBlanc, III, our Chief Financial Officer, or David L. McCabe, our Chief Operating Officer and Executive Vice President of Exploration and Development, could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on any of our executive officers or key employees.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

Significant growth in the size and scope of our operations could place a strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative,

operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the natural gas and oil industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plans.

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

As part of our growth strategy, our management has identified drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of June 30, 2006, we had identified over 865 gross drilling locations, only 83 of which were attributable to proved undeveloped reserves. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled on our anticipated schedule, or at all, or if we will be able to produce natural gas or oil from these locations in commercially viable quantities. As such, our actual drilling activities may differ materially from those presently identified, which could materially and adversely affect our business, financial condition and results of operations.

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

A prospect is a property on which we have identified what our geoscientists and engineers believe, based on available seismic, geological and engineering information, to be indications of commercial quantities of natural gas or oil. However, the use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of natural gas or oil exist, we may damage the reservoir or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. From January 1, 2003 through June 30, 2006, 14% of the development wells we drilled were dry holes and 33% of the exploration wells we drilled were dry holes. If we drill wells that we identify as dry holes in our current and future prospects, our drilling success rate may decline and it may materially and adversely affect our business, financial condition and results of operations.

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

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling natural gas and oil. Many of these risks and hazards are beyond our control and unavoidable under certain circumstances. Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. These risks and hazards include:

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unusual or unexpected geological formations;

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pressures, blowouts or fires;

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cratering and explosions;

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loss of drilling fluid circulation;

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title problems;

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facility or equipment malfunctions;

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unexpected operational events;

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pipeline accidents and failures or casing collapses;

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uncontrollable flows of natural gas, oil, brine or well fluids;

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compliance with environmental and other governmental requirements; and

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adverse weather conditions.

If any of these risks is realized, our business, financial condition and results of operations could be materially and adversely affected.

Losses and liabilities from uninsured or underinsured drilling and operating activities could materially and adversely affect our business, financial condition and operations.

Insurance against every operational risk is not available at economic rates. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Insurance expenses have increased due to recent hurricane activity in the Gulf of Mexico. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could materially and adversely affect our business, financial condition and results of operations.

We may be unable to successfully acquire additional leasehold interests or other natural gas and oil properties, and acquisitions that we do acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities, which may inhibit our ability to grow our production and replace our reserves.

We expect that acquisitions will continue to contribute to our future growth. However, suitable acquisitions may not be available in the future on reasonable terms. If we are successfully able to acquire additional properties, these acquisitions will require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future natural gas and oil prices, operating costs and potential environmental and other liabilities. These assessments are inexact and their accuracy is inherently uncertain. Moreover, our review of properties to be acquired will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not be able to negotiate contractual indemnification for pre-closing liabilities, including environmental liabilities. We may also acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result, we may ultimately acquire natural gas and oil properties that do not contain economically recoverable reserves, which, in turn, may materially and adversely affect our business, financial condition and results of operations.

We may not effectively consolidate and integrate acquired operations, which may materially and adversely affect our business, financial condition and results of operations.

Acquisitions present operational and administrative challenges that may prove more difficult than anticipated. The failure to consolidate functions and integrate procedures, personnel and operations in an effective and timely manner may adversely affect our business, financial condition and results of operations, at least temporarily. Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. To the extent that we acquire properties substantially different from the properties in our operating areas or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as originally anticipated.

Our derivative arrangements could result in financial losses or could materially and adversely affect our business, financial condition and results of operations.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we currently, and may in the future, enter into derivative arrangements for a portion of our

natural gas and oil production. Derivative arrangements for a portion of our natural gas and oil production expose us to the risk of financial loss in some circumstances, including when:

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production is less than expected;

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the counter-party to the derivative arrangement defaults on its contract obligations; or

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

In addition, our derivative arrangements limit the benefit we would receive from increases in the prices for natural gas and oil and may expose us to cash margin requirements. These financial losses and other lost benefits could materially and adversely affect our business, financial condition and results of operations.

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

The natural gas and oil industry is intensely competitive, and we compete with companies that have greater resources than we do. Many of these companies not only explore for and produce natural gas and oil, but also have refining, processing and gathering operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas and oil market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can. Our ability to acquire additional properties and discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Some of our competitors have been operating in Texas, Oklahoma, Louisiana and the Appalachian region much longer than we have and have demonstrated the ability to operate through industry cycles. Any of these competitive disadvantages could adversely affect our business, financial condition and results of operations.

We are subject to complex federal, state, local and other laws and regulations that could materially and adversely affect our business, financial condition and results of operations.

Our natural gas and oil exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. These costs could have a material and adverse effect on our business, financial condition and results of operations. Moreover, our failure to comply with these laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations.

Our operations may expose us to substantial costs and liabilities with respect to environmental, health and safety matters.

We may incur substantial costs and liabilities as a result of environmental, health and safety requirements applicable to our natural gas and oil exploration, production and other activities. These costs and liabilities could arise under a wide range of environmental and safety laws, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with environmental laws or regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, or the issuance of orders enjoining or limiting our current or future operations.

Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

Strict, joint and several liability to remediate contamination may be imposed under certain environmental laws, which could cause us to become liable for, among other things, the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. As a result, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred as a result of any violations of these laws or regulations may materially and adversely affect our business, financial condition and results of operations.

Properties in which we have interests may have title defects which materially impair their value.

We may suffer monetary losses from title defects relating to properties that we drill or acquire. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a monetary loss.

We may continue to incur net losses.

We realized net losses of approximately $6.0 million for the six months ended June 30, 2006 and approximately $27.8 million, $36.3 million and $15.4 million for the years ended December 31, 2005, 2004 and 2003, respectively. We may continue to incur net losses over the next several years. Our failure to achieve profitability in the future could adversely affect our ability to repay indebtedness under our credit facility and our ability to raise additional capital and, accordingly, our ability to grow our business.

Covenants in our credit facility impose significant restrictions and requirements on us.

Our credit facility contains a number of covenants imposing various significant restrictions on Ascent Energy Inc., its operating subsidiaries and our Parent, including restrictions on the repurchase of capital stock and limitations on the ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens. In addition, our credit facility contains restrictions on the payment of dividends by the operating subsidiaries of Ascent Energy Inc. and by our Parent. Our operating subsidiaries and our Parent are only permitted to pay cash dividends if certain financial tests are satisfied, our then outstanding borrowings do not exceed our borrowing base and no default under our credit facility exists or is anticipated as a result of payment of the dividend. Because Ascent Energy Inc. is a holding company and depends on its subsidiaries for cash flow, the restrictions in our credit facility on our subsidiaries’ ability to pay dividends may, in turn, limit the ability of Ascent Energy Inc. to pay dividends on its capital stock. All of these restrictions under our credit facility may affect our ability to operate our business to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial condition and results of operations.

Our credit facility also requires us to achieve and maintain certain financial ratio tests. We may not be able to achieve and maintain compliance with these prescribed financial ratio tests or other requirements under our credit facility. Failure to achieve or maintain compliance with the financial ratio tests or other requirements under our credit facility would result in a default and could lead to the acceleration of our obligations under our credit facility.

The stock of Ascent Oil and Gas Inc., the direct wholly owned subsidiary of Ascent Energy Inc., and substantially all of the assets of the subsidiaries of Ascent Energy Inc. are pledged to secure the obligations of

the borrowers under our credit facility. Our lack of unencumbered collateral could materially and adversely affect our ability to obtain, or increase the cost of obtaining, additional financing in the future.

The failure of one or more of our customers or counterparties to meet their contractual obligations may materially and adversely affect our business, financial condition and results of operations.

Substantially all of our accounts receivable for natural gas and oil sales result from billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our natural gas and oil derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. In the event one or more of our customers or counterparties fails to meet its contractual obligations, our business, financial condition and results of operations could be materially and adversely affected.

Our exploration and development operations require substantial capital and we may be unable to obtain needed capital on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development and acquisition of natural gas and oil reserves. Our cash flow from operations and access to capital are subject to a number of variables, including:

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our proved reserves;

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the level of natural gas and oil we are able to produce from existing wells;

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the prices at which natural gas and oil are sold; and

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our ability to acquire, locate and produce new reserves.

If our revenue decreases as a result of lower natural gas and oil prices, operating difficulties, declines in reserves or for any other reason, we may have insufficient cash flow or access to capital to sustain our operations at current or planned levels. As of October 20, 2006, we had $1.6 million available for additional borrowings under our revolving credit facility and $13.6 million available for additional borrowings under our acquisition facility. Therefore, prior to the consummation of this offering and the application of the net proceeds therefrom, we are limited in our ability to use our credit facility and must rely almost entirely on our cash flow from operations to meet our additional capital expenditure requirements. Additionally, a decline in the condition of the capital markets, a substantial rise in interest rates or other factors could adversely affect the availability or terms of additional financing. If cash generated by operations is not sufficient to meet our capital requirements, our failure to obtain additional financing could require us to curtail our exploration and development activities, which in turn could lead to a possible loss of properties and a decline in our natural gas and oil reserves.

Our failure to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business, financial condition and results of operations and/or result in a loss of investor confidence in our financial reports, which could have a material adverse effect on us and our stock price.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. Under the current rules, we will be required to comply with Section 404 for the year ending December 31, 2007. However, the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations could be greater than currently anticipated. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company

Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. In addition, failure to comply with Section 404 or the reporting of a material weakness may cause investors to lose confidence in our consolidated financial statements, and our stock price may be adversely affected as a result. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our stock price may be adversely affected.

Risks Related to this Offering and Our Common Stock

The Jefferies Investors have relationships with us that present conflicts of interest.

In connection with this offering and the Recapitalization, The Jefferies Investors anticipate receiving approximately $ million of the net proceeds of this offering and shares of our common stock in exchange for the cancellation of certain indebtedness and securities held by them. Jefferies & Company, Inc. is an underwriter participating in this offering and, in such capacity, will receive an underwriting discount with respect to shares purchased by it from us in this offering. In addition, persons associated with The Jefferies Investors are serving as our directors. These circumstances present conflicts of interest because The Jefferies Investors have an interest in the successful completion of this offering and the Recapitalization in addition to the underwriting discounts Jefferies & Company Inc. expects to receive. Please read “Use of Proceeds,” “Recapitalization and Incentive Issuance,” “Principal Stockholders” and “Related Party Transactions” for a more complete description of the interests of The Jefferies Investors in this offering and the Recapitalization.

We have significant stockholders with the ability to influence our actions.

On a pro forma as adjusted basis giving effect to this offering, the application of the net proceeds therefrom, the Recapitalization and the Incentive Issuance, The Jefferies Investors will beneficially own % of our common stock. The interests of The Jefferies Investors may differ from other stockholders, and The Jefferies Investors may vote their interests in a manner that may adversely affect other stockholders. In addition, of our directors are affiliated with The Jefferies Investors. Through their direct and indirect interests in us, The Jefferies Investors will be in a position to influence the outcome of matters requiring a stockholder vote. This concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control.

We will renounce any interest in specified business opportunities, and our non-employee directors generally will have no obligation to offer us those opportunities.

Our amended and restated certificate of incorporation will provide that if an opportunity in our line of business is presented to any of our non-employee directors:

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they will have no obligation to communicate or present the opportunity to us;

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they will not breach any fiduciary duty to us merely because they or their affiliates pursue or acquire the opportunity; and

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they and their affiliates may pursue the opportunity as that entity or individual sees fit,

unless it was presented to such director solely in that person’s capacity as our director or is identified by such director or such director’s affiliates solely through the disclosure of information by or on behalf of us.

Our amended and restated certificate of incorporation also will permit our non-employee directors and their affiliates to engage or invest in businesses that compete with ours. Accordingly, these persons may, and in some cases of which we are aware, do engage in business activities with or invest in competing companies. We will renounce any interest in any such business activities or ventures.

These provisions of our amended and restated certificate of incorporation will be permitted to be amended only by an affirmative vote of holders of at least a majority of our total voting power. As a result of these provisions, conflicts of interest could arise between us and our significant stockholders, such as The Jefferies Investors, who are affiliated with our non-employee directors, concerning competitive business activities or business opportunities, and these conflicts could materially and adversely affect our future competitive position and growth potential.

There has been no active trading market for our common stock, and an active trading market may not develop.

Prior to this offering, there has been no public market for our common stock. An active trading market may not develop for our common stock, which may make it more difficult for you to sell your shares. As described in the section of this prospectus entitled “Underwriting,” negotiations between the underwriters and us will determine the initial public offering price, which may not be indicative of the price at which our common stock will trade following the completion of this offering. You may not be able to resell your shares at or above the initial public offering price.

If our stock price fluctuates after the initial public offering, you could lose a significant part of your investment.

The stock market has experienced extreme price and volume fluctuations that have had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. The market price of our common stock could similarly be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

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changes in securities analysts’ recommendations and their estimates of our future financial performance;

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fluctuations in broader stock market prices and volumes, particularly among securities of natural gas and oil exploration and development companies;

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additions or departures of personnel, including key personnel;

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commencement of, or our involvement in, significant litigation;

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announcements by us or our competitors of significant business developments;

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future issuances of our common stock;

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supplies and prices of and demand for natural gas and oil; and

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general market and economic factors.

The realization of any of these risks and other factors, whether beyond or within our control, could cause the market price of our common stock to decline significantly.

Provisions in our amended and restated certificate of incorporation, amended and restated bylaws and Delaware law may delay or prevent our acquisition by a third party.

Certain provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will have the effect of discouraging, delaying or preventing transactions that involve an actual or threatened change in control of our company. For example, our amended and restated certificate of incorporation and bylaws will include provisions for a staggered board of directors, board authority to fill vacancies on our board of directors and to issue preferred stock, and advance notice provisions for stockholders

to nominate directors or propose business to be considered at a stockholders’ meeting. In addition, our amended and restated certificate of incorporation and amended and restated bylaws will not permit our stockholders to call a special meeting of stockholders or to remove directors except for cause.

Future sales of substantial shares of our common stock may affect its market price.

After this offering and the consummation of the Recapitalization and the Incentive Issuance, we will have outstanding shares of common stock. Of these shares, shares (or shares if the underwriters exercise in full their option to purchase additional shares of our common stock) will be freely tradable without restriction under the Securities Act, except for any shares purchased, acquired or held by our “affiliates” as defined in Rule 144 under the Securities Act. All of the other shares outstanding (a total of shares) are “restricted securities” within the meaning of Rule 144 under the Securities Act. Holders of shares of our common stock have agreed not to sell shares of our common stock for a period of 180 days after this offering. However, the representatives of our underwriters may waive this restriction to allow sales of any number of shares at any time. Certain holders of our shares will also have demand registration rights for four separate registrations beginning 185 days after the registration of our common stock under the Exchange Act and specified piggyback registration rights, in each case in accordance with a registration rights agreement that we have entered into with these holders. See “Related Party Transactions—Registration Rights.”

Sales of a substantial number of shares of our common stock in the public market after this offering or the perception that these sales may occur could cause the market price of our common stock to decline. See “Shares Eligible for Future Sale” for a more detailed description of possible future sales of common stock.

We do not intend to pay, and are effectively limited in our ability to pay, dividends on our common stock.

We expect to retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any dividends on our common stock in the foreseeable future. Our credit facility contains restrictions on the payment of dividends by the operating subsidiaries of Ascent Energy Inc. and by our Parent. Our operating subsidiaries and our Parent are only permitted to pay cash dividends if certain financial tests are satisfied, our then outstanding borrowings do not exceed our borrowing base and no default under our credit facility exists or is anticipated as a result of payment of the dividend. Because Ascent Energy Inc. is a holding company and depends on its subsidiaries for cash flow, the restrictions in our credit facility on our subsidiaries’ ability to pay dividends may, in turn, limit the ability of Ascent Energy Inc. to pay dividends on its capital stock. Therefore, our ability to declare and pay dividends on our common stock is effectively limited by the terms of our credit facility and may be restricted by other loan agreements we may enter into from time to time, and is subject to the provisions of Delaware law. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors after taking into account many factors, including our operating results, financial condition and cash needs. As a result, any return on your investment in shares of our common stock will depend on the market price of our common stock.

You will be immediately diluted by $ per share of common stock you purchase in this offering.

Our net tangible book value as of June 30, 2006, after giving effect to adjustments relating to this offering, the Recapitalization and the Incentive Issuance, would have been approximately $ million, or $ per share of common stock. Based on our net tangible book value and the initial public offering price of $ per share, you will experience an immediate dilution of $ for each share of common stock that you purchase in this offering. Please read “Dilution.”

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

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business and financial strategy;

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drilling prospects, inventories, projects and programs;

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natural gas and oil reserves;

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technology;

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realized natural gas and oil prices;

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production;

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lease operating expenses, general and administrative expenses and exploration and other expenses;

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capital expenditures;

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acquisitions;

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marketing of natural gas and oil;

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competition and government regulation;

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general economic conditions;

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future operating results; and

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plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business and Properties” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and such statements may not be realized and the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date on the front cover of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

USE OF PROCEEDS

We estimate that the net proceeds from this offering, after deducting underwriting discounts and estimated offering expenses payable by us, will be approximately $ million ($ million if the underwriters’ option to purchase additional shares of our common stock is fully exercised), based on an assumed initial public offering price of $ per share. A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) the net proceeds to us from the offering by $ million, assuming no change in the number of shares offered by us as set forth on the front cover of this prospectus and after deducting underwriting discounts and estimated offering expenses payable by us. We intend to use the net proceeds of this offering:

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to repay $ million of indebtedness outstanding under our credit facility;

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to repay in full $ million of principal and accrued interest outstanding under our senior notes;

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to repay $ million of principal and accrued interest outstanding under our senior subordinated notes;

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to pay $ million of cash bonuses to employees participating in the Incentive Issuance, as further described in “Recapitalization and Incentive Issuance;”

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to pay $ million in cash in lieu of fractional shares pursuant to a reverse stock split of the Parent’s common stock to be effected in connection with the Parent Merger, as further described in “Recapitalization and Incentive Issuance;” and

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$ million for general corporate purposes, which could include refinancing some of our derivative arrangements.

The Jefferies Investors, including Jefferies & Company, Inc., one of the underwriters in this offering, are holders of our senior notes and our senior subordinated notes and therefore are expected to receive a portion of the net proceeds of this offering and shares of common stock in connection with this offering and the Recapitalization. In addition, affiliates of certain of the underwriters in this offering are lenders under our credit facility and accordingly are expected to receive a portion of the net proceeds of this offering. See “Principal Stockholders,” “Related Party Transactions—Recapitalization” and “Underwriting.”

As of September 30, 2006, we had approximately $79.6 million outstanding under our credit facility, including borrowings under our acquisition facility, and the interest rate on the outstanding borrowings as of June 30, 2006 was 8.85%. The borrowings outstanding under our credit facility mature in November 2009.

As of September 30, 2006, we had outstanding approximately $38.5 million of principal and accrued interest under our senior notes. The senior notes bear interest at a rate of 16% per annum, which is payable in the form of additional senior notes. The senior notes are due and payable on February 1, 2011 unless automatically extended in accordance with their terms, but in no event later than February 1, 2015. The indebtedness under the senior notes was incurred in November 2005 in exchange for other senior notes that had been issued in connection with our 2004 financial restructuring. Those senior notes were issued in exchange for certain promissory notes issued in 2003 for short term liquidity needs.

As of September 30, 2006, we had outstanding approximately $110.3 million of principal and accrued interest under our senior subordinated notes. The senior subordinated notes bear interest at a rate of 11³/4% per annum, which is payable in the form of additional senior subordinated notes. The senior subordinated notes are due and payable on May 1, 2011 unless automatically extended in accordance with their terms, but in no event later than May 1, 2015. The indebtedness under the senior subordinated notes was incurred in November 2005 in exchange for other senior subordinated notes that had been issued in connection with our 2004 financial restructuring. Those senior subordinated notes were issued in exchange for certain senior notes issued in 2001 in connection with the acquisition of our south Texas properties.

We have granted the underwriters an option to purchase up to an additional shares of common stock within 30 days following the date of this prospectus. The holders of our senior subordinated notes have agreed that we may delay the issuance in the Debt Exchange of up to shares of our common stock, which is % of the number of shares subject to the underwriters’ option to purchase additional shares of our common stock, until the expiration of the underwriters’ 30-day option period. If the underwriters exercise their option to purchase additional shares of our common stock, then the number of shares issued in the Debt Exchange will be correspondingly reduced by a number of shares equal to the net proceeds to us from the underwriters’ exercise of their option to purchase additional shares of our common stock divided by the per share price offered to the public.

Our executive officers are expected to participate in the Incentive Issuance and to receive a portion of the net proceeds of this offering and shares of our common stock in connection with this offering and the Incentive Issuance. See “Management—Termination of 2005 Incentive Plan,” “Related Party Transactions—Termination of 2005 Incentive Plan” and “Principal Stockholders.”

DIVIDEND POLICY

We do not expect to declare or pay cash dividends or make any other distributions on our common stock in the foreseeable future. We expect to retain our future earnings, if any, for use in the operation and expansion of our business, including exploration, development and acquisition activities. Any future determination to pay dividends will be at the discretion of our board of directors and will depend on our financial condition, results of operations, capital requirements and such other factors as our board of directors deems relevant. In addition, our credit facility contains restrictions on the payment of dividends by the operating subsidiaries of Ascent Energy Inc. and our Parent. Our operating subsidiaries and our Parent are only permitted to pay cash dividends if certain financial tests are satisfied, our then outstanding borrowings do not exceed our borrowing base and no default under our credit facility exists or is anticipated as a result of payment of the dividend. Because Ascent Energy Inc. is a holding company and depends on its subsidiaries for cash flow, the restrictions in our credit facility on our operating subsidiaries’ ability to pay dividends may, in turn, limit the ability of Ascent Energy Inc. to pay dividends on its capital stock. Therefore, our ability to declare and pay future dividends on our common stock is effectively limited by our credit facility, may be restricted by other loan agreements we may enter into from time to time, and is subject to the provisions of Delaware law.

RECAPITALIZATION AND INCENTIVE ISSUANCE

Recapitalization

Immediately prior to the sale of our shares in this offering, we intend to consummate a corporate recapitalization involving the following transactions, which we refer to collectively as the “Recapitalization”:

Parent Merger. We will merge an indirect wholly owned subsidiary of Ascent Energy Inc. with and into our Parent, with our Parent surviving the Parent Merger, in a tax-free transaction. Upon consummation of the Parent Merger, our Parent will be a wholly owned subsidiary of Ascent Energy Inc. In the Parent Merger:

•

each share of common stock of the Parent outstanding prior to the Parent Merger will be converted into shares of our common stock, or an aggregate of shares of our common stock; and

•

each warrant to purchase shares of common stock of our Parent outstanding prior to the Parent Merger will be converted into a warrant to purchase shares of our common stock, based on the ratio at which shares of the Parent common stock are converted into shares of our common stock. We refer to these converted warrants as the “Merger Warrants.” In connection with the Recapitalization, certain of the Merger Warrants will be surrendered to Ascent Energy Inc. and cancelled in exchange for an aggregate cash payment of $ . Any Merger Warrants not so surrendered will expire on January 14, 2007, unless earlier exercised by the holders thereof.

Immediately prior to the consummation of the Parent Merger, our Parent will effect a 1-for- reverse stock split of its common stock. We intend to use a portion of the net proceeds of this offering to pay cash in lieu of fractional shares to holders of our Parent’s common stock in connection with this reverse stock split. See “Use of Proceeds.”

The primary purpose of the Parent Merger is to simplify our capital structure with the result that Ascent Energy Inc., the issuer in this offering, will become our parent company. In July 2001, our Parent contributed to Ascent Energy Inc. substantially all of its assets and liabilities. The contribution was accounted for using reorganization accounting for entities under common control which requires retroactive restatement of all periods presented as if the contribution had occurred at the beginning of the earliest period. Our financial information presented in this prospectus therefore includes the assets and liabilities of the Parent prior to the contribution. As of October 20, 2006, the shares of common stock of Ascent Energy Inc. held by our Parent constituted substantially all of our Parent’s assets.

A copy of the agreement and plan of merger pursuant to which we expect to consummate the Parent Merger is filed as an exhibit to the registration statement of which this prospectus forms a part.

The following chart shows our simplified organizational structure before the Parent Merger:

LOGO

The following chart shows our simplified organizational structure immediately following the Parent Merger:

LOGO

Debt Exchange. We intend to issue an aggregate of up to shares of our common stock (subject to reduction as discussed below), at the per share price offered to the public, in repayment of approximately $ million of our senior subordinated notes in a transaction we refer to as the “Debt Exchange.” However, we intend to use the net proceeds, if any, of the underwriters’ exercise of their option to purchase additional shares of our common stock to repay indebtedness under our senior subordinated notes in lieu of issuing shares of our common stock in the Debt Exchange. The holders of our senior subordinated notes have agreed that we may delay the issuance in the Debt Exchange of up to shares of our common stock, which is % of the number of shares subject to the underwriters’ option to purchase additional shares of our common stock, until the expiration of the underwriters’ 30-day option period. If the underwriters exercise their option to purchase additional shares of our common stock, then the number of shares issued in the Debt Exchange will be correspondingly reduced by a number of shares equal to the net proceeds to us from the underwriters’ exercise of their option to purchase additional shares of our common stock divided by the per share price offered to the public. As a result of the repayment of a portion of our senior subordinated notes in cash with a portion of the net proceeds of this offering and the satisfaction in shares of common stock of the remainder of our senior subordinated notes in the Debt Exchange, all of our senior subordinated notes will be extinguished.

Preferred Exchange. The holders of our outstanding warrants to purchase shares of Series A preferred stock will exercise those warrants in a net share exercise (or by tendering shares of our common stock) in exchange for shares of Series A preferred stock and warrants to purchase shares of our common stock at a purchase price of $ per share. Thereafter, we will issue an aggregate of shares of our common stock in exchange for all of our outstanding shares of Series A preferred stock (including accrued but unpaid dividends thereon) and all of our outstanding warrants to purchase shares of our common stock (other than the Merger Warrants) at an exchange ratio of shares of our common stock for each $1,000 of Series A preferred stock (including accrued but unpaid dividends thereon) in a transaction we refer to as the “Preferred Exchange.” All such warrants to purchase shares of our common stock are substantially out-of-the-money and will be cancelled in connection with the Preferred Exchange.

Upon the consummation of this offering, the application of the net proceeds of this offering as described in “Use of Proceeds” and the consummation of the Recapitalization, all of our senior notes and senior subordinated notes will be extinguished and our outstanding long-term indebtedness will consist solely of approximately $ million of borrowings under our credit facility which mature November 1, 2009. The following table shows our capitalization as of June 30, 2006 on an actual basis and on a pro forma as adjusted basis giving effect to the Recapitalization and this offering as further described in “Use of Proceeds:”


	As of June 30, 2006
	Actual			Pro Forma As Adjusted
	(in thousands)
Long-term debt and accrued dividends:
Credit facility	$	68,215		$
Senior notes		36,053			—
Senior subordinated notes		105,141
Series A preferred stock accrued dividends		14,496			—
Interest payable (1)		3,020

Total long-term debt and accrued dividends	$	226,925		$
Stockholders’ (deficit) equity:
Series A preferred stock		40,160			—
Common stock		6
Additional paid-in capital (2)		23,610
Accumulated deficit		(138,572	)

Total stockholders’ (deficit) equity (2)		(74,796	)

Total capitalization (2)	$	153,425		$

(1)	Represents accrued but unpaid interest on the senior notes and the senior subordinated notes, which interest is payable in the form of additional notes.

(2)

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) each of cash and cash equivalents, additional paid-in capital, total stockholders’ (deficit) equity and total capitalization by $ million, assuming no change in the number of shares offered by us as set forth on the front cover of this prospectus and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

You should read this information in conjunction with “Selected Consolidated Historical Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and pro forma consolidated financial statements and the related notes appearing elsewhere in this prospectus.

The Jefferies Investors and The TCW Funds are the principal holders of our securities and are expected to receive cash and shares of our common stock in connection with this offering and the Recapitalization. Please see “Use of Proceeds,” “Related Party Transactions” and “Principal Stockholders.”

We have entered into an agreement with the holders of our outstanding senior subordinated notes, Series A preferred stock, warrants to purchase shares of our common stock and warrants to purchase shares of Series A preferred stock and certain holders of outstanding warrants to purchase shares of common stock of our Parent pursuant to which certain transactions contemplated by the Recapitalization will be consummated. A copy of the recapitalization agreement is filed as an exhibit to the registration statement of which this prospectus forms a part. The parties to the recapitalization agreement have agreed that all payments of cash by Ascent Energy Inc. and all deliveries of common stock or other securities of Ascent Energy Inc. in satisfaction of or in respect of the securities of Ascent Energy Inc. or our Parent that are being repaid, satisfied, exchanged or surrendered in connection with this offering or pursuant to the recapitalization agreement, including, without limitation, the senior notes, senior subordinated notes, Series A preferred stock, common stock warrants, preferred stock warrants and Merger Warrants shall be made in accordance with the relative rankings, preferences and priorities of such securities and in no event shall the holders of our common stock immediately prior to the consummation of this offering and the transactions contemplated by the recapitalization agreement own, immediately after the consummation of this offering and the transactions contemplated by the recapitalization agreement, less than a de minimis amount of our outstanding common stock. The consummation of the transactions contemplated by the recapitalization agreement are conditioned on the consummation of this offering and the other closing conditions set forth in the recapitalization agreement.

Incentive Issuance

In May 2005, we adopted our 2005 Incentive Plan, which provides for aggregate awards of up to 13.5% of the amount by which the present value of the consideration payable to Ascent or its securityholders in connection with a defined sale of our company exceeds our consolidated funded debt, as defined in the plan. As of October 26, 2006, awards providing for approximately 12.8% of that amount had been granted under the plan. As of October 26, 2006, no amounts were payable to the participants under the 2005 Incentive Plan, which provides for awards under the plan to become payable only upon a “Sale of Ascent.” This offering does not meet the definition of a Sale of Ascent under the 2005 Incentive Plan and, therefore, will not trigger the payment of awards under the plan. In connection with and immediately prior to the closing of this offering, we intend to terminate our 2005 Incentive Plan and issue awards under a new long-term incentive plan. We believe the new plan will better enable us to retain key employees and encourage performance results. Participants in the 2005 Incentive Plan will receive cash bonuses and awards of restricted stock, which vest over a three-year period, in exchange for terminating their rights under the 2005 Incentive Plan. We refer to this exchange as the “Incentive Issuance.” The cash bonuses and awards of restricted stock issuable pursuant to the Incentive Issuance are not necessarily indicative of the amounts or form of consideration that holders of awards under the 2005 Incentive Plan would have received had a defined Sale of Ascent occurred under the 2005 Incentive Plan. The value of the awards payable under the 2005 Incentive Plan would be determined at the time of a defined Sale of Ascent under the 2005 Incentive Plan, if and when such sale occurred. The terms of the Incentive Issuance are the result of negotiations between our management and principal investors and will enable us to put in place a plan more typical for a public company. The aggregate amount of cash and restricted stock to be issued under the 2006 Long-Term Incentive Plan will be determined in accordance with the following formula:

[(IPO Price × Post-Deal Shares) - Adjusted Net Debt] × Awards

where:

•

IPO Price = initial public offering price per share

•

Post-Deal Shares = number of shares of common stock outstanding immediately after the initial public offering, the Recapitalization and the Incentive Issuance

•

Adjusted Net Debt = Pre-Deal Net Debt less Post-Deal Net Debt

•

Pre-Deal Net Debt = amount outstanding under our bank credit facility, senior notes and senior subordinated notes, including accrued but unpaid interest thereon, less cash on hand, in each case immediately prior to the initial public offering, the Recapitalization and the Incentive Issuance

•

Post-Deal Net Debt = amount outstanding under our bank credit facility less cash on hand, in each case immediately after the initial public offering, the Recapitalization, the Incentive Issuance and the application of the net proceeds of this offering as described in “Use of Proceeds,” including refinancing of derivative arrangements currently contemplated to use approximately $15.0 million of net proceeds

•

Awards = percentage of Total Enterprise Value (as defined under the 2005 Incentive Plan) subject to outstanding awards under the 2005 Incentive Plan immediately prior to the initial public offering, or 12.8% as of October 26, 2006

At the mid-point of the proposed offering range, the Incentive Issuance will be $ million in the aggregate, of which $ million will be in the form of cash bonuses and $ million in the form of restricted stock awarded under our 2006 Long-Term Incentive Plan ( shares valued at the mid-point of the proposed offering range). The entire $ million Incentive Issuance is expected to be taxable to the recipients in this tax year. The cash bonus portion of the Incentive Issuance is intended to approximate the recipients’ related income tax liability. Because the entire Incentive Issuance is a taxable transaction, the recipients will not have income tax liability in the future merely as a result of the vesting of the restricted stock and will therefore not have to consider selling their shares to pay income taxes upon vesting. The terms of the

2005 Incentive Plan prohibit us from canceling or modifying an existing award without the consent of the affected holder; therefore, each of the holders of awards under our 2005 Incentive Plan must consent to this exchange in order to terminate all prior awards under our 2005 Incentive Plan. We have received the consent of [each] of the participants in the 2005 Incentive Plan. The Incentive Issuance is contingent on the consummation of this offering and the Recapitalization and the consent of each of the holders of awards under our 2005 Incentive Plan.

Our executive officers are expected to participate in the Incentive Issuance and to receive a portion of the net proceeds of this offering and shares of our common stock in connection with this offering and the Incentive Issuance. See “Management—Termination of 2005 Incentive Plan,” “Related Party Transactions—Termination of 2005 Incentive Plan” and “Principal Stockholders.”

CAPITALIZATION

The following table sets forth our cash and capitalization as of June 30, 2006:

•

on an actual basis, other than share amounts which give pro forma effect to the reverse stock split; and

•

on a pro forma as adjusted basis giving effect to the Recapitalization, the sale of the shares of our common stock in this offering at an assumed initial public offering price of $ per share and the anticipated use of the net proceeds therefrom as described under “Use of Proceeds.”


	As of June 30, 2006
	Actual			Pro Forma As Adjusted
	(in thousands)
Cash and cash equivalents (1)	$	1,296		$
Long-term debt and accrued dividends:
Credit facility	$	68,215		$
Senior notes		36,053			—
Senior subordinated notes		105,141
Series A preferred stock accrued dividends		14,496			—
Interest payable (2)		3,020

Total long-term debt and accrued dividends	$	226,925		$
Stockholders’ (deficit) equity:
Series A preferred stock, $0.001 par value; 44,100 shares authorized, shares issued and outstanding pro forma for the reverse stock split; no shares issued and outstanding, pro forma as adjusted		40,160			—
Common stock, $0.001 par value; 20,000,000 shares authorized, shares issued and outstanding pro forma for the reverse stock split; shares authorized, shares issued and outstanding, pro forma as adjusted		6
Additional paid-in capital (1)		23,610
Accumulated deficit		(138,572	)

Total stockholders’ (deficit) equity (1)		(74,796	)

Total capitalization (1)	$	153,425		$

(1)

(2)	Represents accrued but unpaid interest on the senior notes and the senior subordinated notes, which interest is payable in the form of additional notes.

DILUTION

The net tangible book value per share of our common stock is the difference between our tangible assets and our liabilities, divided by the number of shares of our common stock outstanding. For investors in our common stock, dilution is the per share difference between the initial public offering price of the common stock in this offering and the net tangible book value of our common stock immediately after completing this offering, the Recapitalization and the Incentive Issuance. Dilution results from the fact that the per share offering price of the common stock is substantially in excess of the book value per share attributable to our existing stockholders prior to this offering, the Recapitalization and the Incentive Issuance.

As of June 30, 2006, our net tangible book value was approximately $ million, or $ per share of common stock, based on shares of common stock outstanding.

After giving effect to the sale of common stock offered by this prospectus, the receipt of the estimated net proceeds, after deducting underwriting discounts and estimated offering expenses payable by us, the Recapitalization and the Incentive Issuance, our net tangible book value as of June 30, 2006 would have been $ per share of common stock. This represents an immediate and substantial increase in the net tangible book value of $ per share to existing stockholders and an immediate dilution of $ per share, resulting from the difference between the initial public offering price and the net tangible book value after this offering, the Recapitalization and the Incentive Issuance, to new investors purchasing common stock in this offering. The following table illustrates the per share dilution to new investors purchasing common stock in this offering:


Assumed initial public offering price per share of common stock		$

Net tangible book value per share of common stock as of June 30, 2006
Increase in pro forma net tangible book value per share of common stock attributable to investors in this offering
Net tangible book value per share of common stock after this offering, the Recapitalization and the Incentive Issuance

Dilution per share to new investors		$

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) our net tangible book value by $ million, the net tangible book value per share, after giving effect to this offering, the Recapitalization and the Incentive Issuance, by $ per share and the dilution in net tangible book value per share to new investors in this offering by $ per share, assuming no change in the number of shares offered by us as set forth on the front cover of this prospectus, and after deducting the estimated underwriting discounts and estimated offering expenses payable by us.

The following table summarizes, as of June 30, 2006, the differences between existing stockholders and the new investors with respect to the number of shares of common stock purchased from us, the total consideration paid and the average price per share paid before deducting the underwriting discounts and our estimated offering expenses payable by us, assuming an initial public offering price of $ per share.

Shares Purchased

Total Consideration

Average Price
per Share

Number

Percent

Amount

Percent

Existing stockholders

New investors

Total

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) total consideration paid by new investors, total consideration paid by all stockholders and the average price per share paid by all stockholders by $ million, $ million and $ million, respectively, assuming no change in the number of shares offered by us as set forth on the front cover of this prospectus, and without deducting underwriting discounts and estimated offering expenses payable by us.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma condensed consolidated financial statements give effect to the Recapitalization, this offering and the application of the net proceeds of this offering as described under “Use of Proceeds” unless otherwise indicated. The unaudited pro forma condensed consolidated balance sheet as of June 30, 2006 assumes that the Recapitalization, this offering and the application of the net proceeds from this offering occurred on June 30, 2006. The unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2005 and for the six months ended June 30, 2005 and June 30, 2006 assumes that the Recapitalization, this offering and the application of the net proceeds from this offering occurred on January 1, 2005, but does not give effect to approximately $ million of compensation expense to be recognized immediately upon the payment of cash bonuses in the Incentive Issuance with a portion of the net proceeds of this offering. Except for the adjustments to cash and accumulated deficit on the pro forma condensed consolidated balance sheet for the use of a portion of the net proceeds of this offering to pay cash bonuses in connection with the Incentive Issuance, the pro forma condensed consolidated financial statements do not give effect to the Incentive Issuance. We expect to recognize approximately $ million of compensation expense immediately upon payment of cash bonuses in the Incentive Issuance and approximately $ million of compensation expense over a three-year vesting period related to the issuance of shares of restricted stock in the Incentive Issuance. See “Recapitalization and Incentive Issuance.” Adjustments for the Recapitalization and this offering are described in the accompanying notes to the unaudited pro forma condensed consolidated financial statements. Please read the accompanying notes to the unaudited pro forma condensed consolidated financial statements for further explanation.

The unaudited pro forma condensed consolidated financial statements and accompanying notes should be read together with our historical consolidated financial statements and related notes included elsewhere in this prospectus. The unaudited pro forma condensed consolidated financial statements were derived by adjusting our historical consolidated financial statements. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, the actual effects of the Recapitalization, the Incentive Issuance and this offering may differ from the effects reflected in the unaudited pro forma condensed consolidated financial statements. However, management believes that the assumptions used provide a reasonable basis for presenting the significant effects of the Recapitalization and this offering and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed consolidated financial statements.

The unaudited pro forma condensed consolidated financial statements do not purport to present our financial position or results of operations had the Recapitalization and this offering actually occurred as of the dates indicated. Moreover, they do not project our financial position or results of operations for any future date or period.

Immediately prior to the sale of our shares in this offering, we intend to consummate the Recapitalization, which includes the following transactions:

•

we will effect a 1-for- reverse stock split of our Parent’s common stock and corresponding payment of cash in lieu of fractional shares;

•

our Parent will become a wholly owned subsidiary of Ascent Energy Inc. in a tax-free transaction;

•

we will issue shares of our common stock in repayment of our senior subordinated notes that are not repaid with the net proceeds of this offering; and

•

we will issue shares of our common stock in exchange for our outstanding Series A preferred stock (including accrued but unpaid dividends thereon) and warrants.

Although not included in the pro forma condensed consolidated financial statements, we intend to consummate the Incentive Issuance. In connection therewith, we intend to terminate our 2005 Incentive Plan and

the awards granted thereunder. The 2005 Incentive Plan provides for awards under the plan to become payable to the holders thereof only upon a defined “Sale of Ascent.” Because the 2005 Incentive Plan does not contemplate an initial public offering, this offering does not meet the definition of a Sale of Ascent under the 2005 Incentive Plan and does not trigger the payment of awards under the 2005 Incentive Plan. Therefore, this offering caused management to negotiate a new set of terms for the outstanding awards. Under the new terms, participants in the 2005 Incentive Plan will receive cash bonuses and awards of restricted stock, which vest over a three-year period, in exchange for terminating their rights under the 2005 Incentive Plan. The Incentive Issuance is contingent on the consummation of this offering and the Recapitalization and the consent of each of the holders of awards under our 2005 Incentive Plan. In connection with the Incentive Issuance, we expect to pay $ million of cash bonuses and to grant million shares of restricted stock under our 2006 Long-Term Incentive Plan and recognize approximately $ million of compensation expense immediately upon payment of cash bonuses in the Incentive Issuance and approximately $ million of compensation expense over a three-year vesting period related to the issuance of shares of restricted stock in the Incentive Issuance. See “Recapitalization and Incentive Issuance.” The unaudited pro forma condensed consolidated financial statements do not give effect to the Incentive Issuance except for the adjustments to cash and accumulated deficit on the pro forma condensed consolidated balance sheet for the use of a portion of the net proceeds of this offering to pay cash bonuses in connection with the Incentive Issuance.

Ascent Energy Inc.

Unaudited Pro Forma Condensed Consolidated Balance Sheet

As of June 30, 2006

(in thousands)


	Historical			Adjustments	Pro Forma
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,296		$	$
Oil and gas revenue receivable		7,482
Joint interest and other receivables		1,892
Prepaid expenses		496
Fair value of derivatives		1,178
Inventory and other assets		1,273

TOTAL CURRENT ASSETS		13,617

PROPERTY AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		358,922
Unevaluated oil and gas properties		21,330
Other property and equipment		6,286

		386,538
Less—accumulated depreciation, depletion and amortization		(186,525	)

Net property and equipment		200,013

OTHER ASSETS:
Deferred financing costs		722
Fair value of derivatives		50
Escrowed and restricted funds		657

TOTAL ASSETS	$	215,059		$	$


LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY

CURRENT LIABILITIES:
Accounts payable	$	4,404		$	$
Accrued liabilities		8,562
Undistributed oil and gas proceeds		4,588
Interest payable		476
Accrued abandonment cost		1,325
Fair value of derivatives		13,182

TOTAL CURRENT LIABILITIES		32,537

LONG-TERM LIABILITIES:
Bank credit facility		68,215
Senior notes		36,053
Senior subordinated notes		105,141
Interest payable		3,020
Fair value of derivatives		18,139
Accrued abandonment cost		9,898
Deferred income taxes		2,026
Series A preferred stock accrued dividends		14,496
Commitments and contingencies		330

TOTAL LONG-TERM LIABILITIES		257,318

STOCKHOLDERS’ (DEFICIT) EQUITY:
Series A preferred stock, par value $0.001 per share		40,160
Common stock, par value $0.001 per share		6
Additional paid-in capital		23,610
Accumulated deficit		(138,572	)


TOTAL STOCKHOLDERS’ DEFICIT		(74,796	)

TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	215,059		$	$

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Ascent Energy Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the Six Months Ended June 30, 2005

(in thousands, except per share data)


	Historical			Adjustments	Pro Forma
REVENUES:
Oil	$	15,694		$	$
Natural gas		14,848
NGLs		1,776

TOTAL REVENUES		32,318

COSTS AND EXPENSES:
Production and ad valorem taxes		1,731
Lease operating expenses		5,487
General and administrative expenses		3,851
Exploration expenses		444
Depreciation, depletion, and amortization		10,623
Property impairments		—
Derivative loss		17,983

TOTAL OPERATING EXPENSES		40,119

INCOME FROM OPERATIONS		(7,801	)
INTEREST AND OTHER INCOME		78
INTEREST EXPENSE		(9,286	)

LOSS BEFORE INCOME TAXES		(17,009	)
INCOME TAX BENEFIT		127

NET LOSS		(16,882	)
PREFERRED STOCK DIVIDENDS		(1,665	)

NET LOSS ATTRIBUTABLE TO COMMON SHARES	$	(18,547	)	$	$

NET LOSS PER COMMON SHARE:
Basic and diluted net loss per common share	$	(3.12	)		$
Basic and diluted net loss per common share, pro forma for reverse stock split	$				$

Weighted average shares		5,949
Weighted average shares pro forma for reverse stock split

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Ascent Energy Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the Six Months Ended June 30, 2006

(in thousands, except per share data)


	Historical			Adjustments	Pro Forma
REVENUES:
Oil	$	19,631		$	$
Natural gas		16,271
NGLs		1,713

TOTAL REVENUES		37,615

COSTS AND EXPENSES:
Production and ad valorem taxes		2,231
Lease operating expenses		6,398
General and administrative expenses		5,548
Exploration expenses		818
Depreciation, depletion, and amortization		10,393
Property impairments		—
Derivative loss		6,725

TOTAL OPERATING EXPENSES		32,113

LOSS FROM OPERATIONS		5,502
INTEREST AND OTHER INCOME		110
INTEREST EXPENSE		(11,266	)

LOSS BEFORE INCOME TAXES		(5,654	)
INCOME TAX EXPENSE		(317	)

NET LOSS		(5,971	)
PREFERRED STOCK DIVIDENDS		(1,665	)

NET LOSS ATTRIBUTABLE TO COMMON SHARES	$	(7,636	)	$	$

NET LOSS PER COMMON SHARE:
Basic and diluted net loss per common share	$	(1.28	)		$
Basic and diluted net loss per common share, pro forma for reverse stock split	$				$

Weighted average shares		5,949
Weighted average shares pro forma for reverse stock split

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Ascent Energy Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the Year Ended December 31, 2005

(in thousands, except per share data)


	Historical			Adjustments	Pro Forma
REVENUES:
Oil	$	33,228		$	$
Natural gas		36,634
NGLs		3,714

TOTAL REVENUES		73,576

COSTS AND EXPENSES:
Production and ad valorem taxes		3,332
Lease operating expenses		11,594
General and administrative expenses		8,436
Exploration expenses		3,460
Depreciation, depletion, and amortization		20,771
Property impairments		1,254
Derivative loss		33,851

TOTAL OPERATING EXPENSES		82,698

LOSS FROM OPERATIONS		(9,122	)
INTEREST AND OTHER INCOME		561
INTEREST EXPENSE		(19,496	)

LOSS BEFORE INCOME TAXES		(28,057	)
INCOME TAX BENEFIT		209

NET LOSS		(27,848	)
PREFERRED STOCK DIVIDENDS		(3,358	)

NET LOSS ATTRIBUTABLE TO COMMON SHARES	$	(31,206	)	$	$

NET LOSS PER COMMON SHARE:
Basic and diluted net loss per common share	$	(5.25	)		$
Basic and diluted net loss per common share, pro forma for reverse stock split	$				$

Weighted average shares		5,949
Weighted average shares pro forma for reverse stock split

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

Ascent Energy Inc.

Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

Note 1: Basis of Presentation, the Offering and the Recapitalization

The historical financial information is derived from our historical consolidated financial statements. The unaudited pro forma condensed consolidated financial statements adjust our historical consolidated financial statements to give effect to the following:

•

A 1-for- reverse stock split of our common stock.

•

The issuance of shares of our common stock to the public at the initial public offering price of $ per share resulting in aggregate gross proceeds to us of $ million.

•

The payment of estimated underwriting discounts and offering expenses payable by us of $ million.

•

The repayment of $ million of borrowings under our credit facility with a portion of the net proceeds of this offering.

•

The repayment of all $ million of our outstanding senior notes with a portion of the net proceeds of this offering.

•

The repayment of $ million of our senior subordinated notes with a portion of the net proceeds of this offering.

•

The issuance of shares of our common stock in connection with the merger of our Parent with a wholly owned subsidiary of Ascent Energy Inc. in a tax-free reorganization that we refer to as the “Parent Merger” and the conversion of warrants to purchase shares of common stock of our Parent into warrants to purchase shares of our common stock in connection with the Parent Merger. We refer to these converted warrants as the “Merger Warrants.”

•

The issuance of shares of our common stock in exchange for $ million of indebtedness under our senior subordinated notes in a transaction that we refer to as the “Debt Exchange.” The number of shares of our common stock issued in the Debt Exchange is subject to reduction as described below.

•

The issuance of shares of our Series A preferred stock and warrants to purchase shares of our common stock upon the net share exercise (or tender of shares of our common stock as consideration for the exercise price) of warrants to purchase shares of Series A preferred stock at an exercise price of $ per share.

•

The issuance of shares of our common stock in exchange for all outstanding shares of our Series A preferred stock (including accrued but unpaid dividends thereon) and all outstanding warrants to purchase shares of our common stock (other than the Merger Warrants) at an exchange ratio of shares of our common stock for each $1,000 of Series A preferred stock (including accrued but unpaid dividends thereon) in a transaction that we refer to as the “Preferred Exchange.” All such warrants to purchase shares of our common stock are substantially out-of-the-money and will be cancelled in connection with the Preferred Exchange.

•

The payment of $ in exchange for Merger Warrants to purchase shares of our common stock at an exercise price of $ per share.

Additionally, the unaudited pro forma condensed consolidated balance sheet as of June 30, 2006 gives effect to the issuance of cash bonuses in connection with the surrender of outstanding awards under the 2005 Incentive Plan in the Incentive Issuance.

We intend to use the net proceeds, if any, of the underwriters’ exercise of their option to purchase additional shares of our common stock to repay indebtedness under our senior subordinated notes in lieu of issuing shares of our common stock in the Debt Exchange. The holders of our senior subordinated notes have agreed that we

may delay the issuance in the Debt Exchange of up to shares of our common stock, which is % of the number of shares subject to the underwriters’ option to purchase additional shares of our common stock, until the expiration of the underwriters’ 30-day option period. If the underwriters exercise their option to purchase additional shares of our common stock, then the number of shares issued in the Debt Exchange will be correspondingly reduced by a number of shares equal to the net proceeds to us from the underwriters’ exercise of their option to purchase additional shares of our common stock divided by the per share price offered to the public.

In addition, subsequent to this offering, we anticipate incurring incremental expenses during the year ended December 31, 2007 of $ million and subsequently at an annual rate of approximately $ million related to being a public company, including our compliance with the Exchange Act and the Sarbanes-Oxley Act of 2002. The unaudited pro forma condensed consolidated financial statements do not include any adjustment for these estimated incremental costs.

Note 2: Pro Forma Adjustments and Assumptions

(a) Reflects estimated gross proceeds of $ million from the issuance and sale of million shares of our common stock to the public, assuming the underwriters do not exercise their option to purchase additional shares of our common stock, at the initial public offering price of $ per share. Also reflects estimated underwriting discounts and other offering expenses of approximately $ million and the application of a portion of the net proceeds of this offering to repay approximately $ million of indebtedness under our credit facility, all $ million of principal and accrued interest under our senior notes and $ million of principal and accrued interest under our senior subordinated notes and to pay approximately $ million of cash bonuses in connection with the surrender of outstanding awards under the 2005 Incentive Plan pursuant to the Incentive Issuance.

(b) Reflects the issuance of shares of Series A preferred stock and warrants to purchase an aggregate of shares of our common stock at a purchase price of $ per share upon the exercise of warrants to purchase shares of our Series A preferred stock at an exercise price of $ per share.

(c) Reflects the issuance of shares of our common stock in the Preferred Exchange in exchange for $ million of Series A preferred stock (including accrued but unpaid dividends thereon) and all outstanding warrants to purchase shares of our common stock (other than the Merger Warrants) at an exchange ratio of shares of our common stock for each $1,000 of Series A preferred stock (including accrued but unpaid dividends thereon) and the cancellation of such warrants, which are substantially out-of-the-money.

(d) Reflects the repayment of $ million of principal and accrued interest under our senior subordinated notes with a portion of the net proceeds of this offering and the issuance of million shares of our common stock in exchange for $ million of principal and accrued interest under our senior subordinated notes in the Debt Exchange at the exchange ratio of $ per share. If the underwriters exercise their option to purchase additional shares of our common stock, then the number of shares issued in exchange for our senior subordinated notes in the Debt Exchange will be correspondingly reduced by a number of shares equal to the net proceeds to us from the underwriters’ exercise of their option to purchase additional shares of our common stock divided by the per share price offered to the public, and the net proceeds from any exercise of such option will be used to repay indebtedness under our senior subordinated notes.

(e) Reflects the change in interest expense resulting from the repayment of $ million under our credit facility and the repayment or exchange for common stock of all $ million of our outstanding senior notes and $ million of our senior subordinated notes in connection with this offering and the Debt Exchange. Interest expense on our credit facility assumes a rate of %.

(f) Reflects the reduction of deferred financing costs resulting from the repayment or exchange for common stock of all $ million of our outstanding senior notes and $ million of our senior subordinated notes in connection with this offering and the Debt Exchange.

(g) Reflects the payment of $ in exchange for Merger Warrants to purchase shares of our common stock at an exercise price of $ per share.

(h) Reflects compensation expense related to cash bonuses issued in connection with the surrender of outstanding awards under the 2005 Incentive Plan pursuant to the Incentive Issuance.

(i) Reflects income tax expense calculated at the statutory rate in effect during the period presented.

SELECTED CONSOLIDATED HISTORICAL FINANCIAL INFORMATION

The following table presents our selected consolidated historical financial information for the periods presented. The selected consolidated historical financial information as of and for each of the five years ended December 31, 2005 has been derived from our audited consolidated financial statements and related notes. The audited consolidated financial statements and related notes as of December 31, 2004 and December 31, 2005 and for each of the three years ended December 31, 2005 are included elsewhere in this prospectus. The selected consolidated historical financial information as of June 30, 2006 and for the six months ended June 30, 2005 and June 30, 2006 has been derived from our unaudited consolidated financial statements and related notes included elsewhere in this prospectus which, in the opinion of management, have been prepared on the same basis as our audited consolidated financial statements and include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of this information.

In July 2001, the Parent contributed to Ascent Energy Inc. substantially all of its assets and liabilities. The contribution was accounted for using reorganization accounting for entities under common control which requires retroactive restatement of all periods presented as if the contribution had occurred at the beginning of the earliest period. The information presented below therefore includes the assets and liabilities of the Parent prior to the contribution.

This information is only a summary and you should read it in conjunction with the material contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with the financial statements and related notes included elsewhere in this prospectus.

Our audited consolidated financial statements for the years ending prior to December 31, 2005 have been restated to reflect our conversion to the successful efforts method of accounting for our investment in natural gas and oil properties and to correct our previously recorded income tax provision. Our audited consolidated financial statements for the years ended December 31, 2003 and December 31, 2004 have been restated to reflect our previously understated asset retirement obligation.

Prior to the Spring of 2003, we focused on the exploration and development of the reserves we acquired in connection with our formation in 2001. Since joining us in mid-2003, our senior management team has embarked on a strategy to acquire and develop a risk-balanced inventory of high growth opportunities. In order to implement this strategy, our new management initially devoted a substantial portion of its efforts to increasing our liquidity and improving our operational efficiency. In July 2004, we completed a financial restructuring that allowed the operating subsidiaries of Ascent Energy Inc., as borrowers, to enter into a new credit facility and reduced our debt service obligations by permitting us to pay in kind certain interest obligations.

For the foregoing reasons, our selected consolidated historical financial information may not be meaningful or indicative of our future results.


	Year Ended December 31,															Six Months Ended June 30,
	2001			2002			2003			2004			2005			2005			2006
	(Restated)			(Restated)			(Restated)			(Restated)						(Unaudited)
	(in thousands, except per share amounts)
Statement of Operations Data:
Revenues:
Oil	$	9,884		$	15,924		$	20,377		$	25,431		$	33,228		$	15,694		$	19,631
Natural gas		11,746			25,486			24,553			22,021			36,634			14,848			16,271
NGLs		(13	)		1,664			2,027			3,257			3,714			1,776			1,713

Total		21,617			43,074			46,957			50,709			73,576			32,318			37,615
Expenses:
Production and ad valorem taxes		1,422			3,508			4,307			3,091			3,332			1,731			2,231
Lease operating expenses		5,492			10,939			11,915			12,018			11,594			5,487			6,398
General and administrative expenses		5,290			4,152			10,388			8,272			8,436			3,851			5,548
Exploration expenses		100			1,370			5,630			854			3,460			444			818
Depreciation, depletion and amortization		6,922			13,039			21,539			31,207			20,771			10,623			10,393
Property impairments		58,829			21			3,802			20,711			1,254			—			—
Derivative loss		—			—			—			6,604			33,851			17,983			6,725

Total operating expenses		78,055			33,029			57,581			82,757			82,698			40,119			32,113

Income (loss) from operations		(56,438	)		10,045			(10,624	)		(32,048	)		(9,122	)		(7,801	)		5,502
Interest and other income		182			438			7			203			561			78			110
Interest expense		(3,707	)		(11,437	)		(13,661	)		(16,958	)		(19,496	)		(9,286	)		(11,266	)

Loss before income taxes		(59,963	)		(954	)		(24,278	)		(48,803	)		(28,057	)		(17,009	)		(5,654	)
Income tax benefit (expense)		21,163			1,495			8,624			12,472			209			127			(317	)

Income (loss) before cumulative effect of change in accounting principle		(38,800	)		541			(15,654	)		(36,331	)		(27,848	)		(16,882	)		(5,971	)
Cumulative effect of change in accounting principle, net of income tax of $273 in 2003 (1)		—			—			262			—			—			—			—

Net income (loss)		(38,800	)		541			(15,392	)		(36,331	)		(27,848	)		(16,882	)		(5,971	)
Preferred stock dividends (2)		(1,168	)		(3,457	)		(3,976	)		(3,367	)		(3,358	)		(1,665	)		(1,665	)

Net loss attributable to common shares	$	(39,968	)	$	(2,916	)	$	(19,368	)	$	(39,698	)	$	(31,206	)	$	(18,547	)	$	(7,636	)

Net loss per common share :
Basic and diluted net loss per common share	$	(8.07	)	$	(0.59	)	$	(3.63	)	$	(6.67	)	$	(5.25	)	$	(3.12	)	$	(1.28	)
Basic and diluted net loss per common share (pro forma for reverse stock split)

Selected Cash Flow and Other Financial Data:
Net cash provided by operating activities	$	5,149		$	4,674		$	16,935		$	17,369		$	31,475		$	14,671		$	18,281
Net cash used in investing activities		(51,662	)		(27,965	)		(39,121	)		(22,584	)		(35,019	)		(17,316	)		(36,490	)
Net cash provided by financing activities		44,856			21,251			26,236			1,650			4,108			4,550			18,425
Capital expenditures		6,993			27,965			39,121			22,985			34,588			16,296			36,554
EBITDAX (3)		30,758			22,951			20,354			28,658			37,342			17,351			18,766


	As of December 31,															As of June 30,
	2001			2002			2003			2004			2005			2005			2006
	(Restated)			(Restated)			(Restated)			(Restated)						(Unaudited)
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	2,072		$	31		$	4,081		$	516		$	1,080		$	2,421		$	1,296
Total assets		148,726			178,590			200,374			169,267			187,221			179,360			215,059
Long-term debt(4)		109,108			112,969			141,493			164,954			185,223			174,498			212,429
Series A preferred stock (including accrued but unpaid dividends) (5)		21,813			42,907			46,265			9,577			12,865			11,208			14,496
Stockholders’ deficit		(13,322	)		(24,340	)		(40,587	)		(36,060	)		(67,196	)		(54,572	)		(74,796	)
Total liabilities and stockholders’ deficit	$	148,726		$	178,590		$	200,374		$	169,267		$	187,221			179,360			215,059

(1)	Reflects adoption of SFAS 143 effective January 1, 2003.

(2)

(3)

EBITDAX is a non-GAAP financial measure. See note 3 to “Summary—Summary Consolidated Historical and Pro Forma Financial Information” for additional information about our calculation of EBITDAX and its reconciliation to net cash provided by operating activities, which is the most comparable GAAP financial measure.

(4)	Represents borrowings under our credit facility and the aggregate principal amount of outstanding senior notes and senior subordinated notes. Also includes long-term accrued interest on our senior notes and senior subordinated notes as of periods ending on or after December 31, 2004.

(5)

The amounts for the years ended December 31, 2001, December 31, 2002 and December 31, 2003 represent the book value of our Series A preferred stock plus all accrued but unpaid dividends thereon. The amount for periods ending on or after December 31, 2004 represent only accrued but unpaid dividends on the Series A preferred stock. In December 2004, the terms of the Series A preferred stock were amended to eliminate our requirement to redeem the outstanding shares of Series A preferred stock on a specified date. The amendment resulted in a balance sheet reclassification of the book value of the Series A preferred stock to stockholders’ deficit.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis should be read in conjunction with our selected consolidated historical financial data and our accompanying consolidated historical financial statements and the notes to those financial statements included elsewhere in this prospectus. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this prospectus, particularly the section entitled “Risk Factors.” See also “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

We are a growth-oriented, independent natural gas and oil company engaged in the acquisition, exploration and development of both conventional and unconventional natural gas and oil properties in Texas, Oklahoma, Louisiana and the Appalachian region. Our growth efforts are primarily directed at finding and developing natural gas reserves in unconventional shale gas areas and in known tight gas areas. We operate substantially all of our properties.

We were formed in July 2001 to acquire natural gas and oil properties in south Texas, Oklahoma and Louisiana. Prior to the Spring of 2003, we focused on the exploration and development of the reserves we acquired in connection with our formation. Since joining us in mid-2003, our senior management team has embarked on a strategy to acquire and develop a risk-balanced inventory of high growth opportunities, predominantly in shale gas. In order to implement this strategy, our new management initially devoted a substantial portion of its efforts to improving our operational efficiency and increasing our liquidity. In July 2004, we completed a financial restructuring that allowed the operating subsidiaries of Ascent Energy Inc., as borrowers, to enter into a new credit facility and reduced our debt service obligations by permitting us to pay in kind certain interest obligations.

Upon joining us in mid-2003, our senior management team undertook a detailed review and analysis of our proved natural gas and oil reserves, which resulted in a downward revision of our estimates of proved natural gas and oil reserves by a total of 37.7 Bcfe (6.3 MMBoe) for the year ended December 31, 2003 and by an additional 62.9 Bcfe (10.5 MMBoe) during the year ended December 31, 2004. The 2003 revision included approximately 22.3 Bcfe (3.7 MMBoe) of proved non-producing and proved undeveloped reserves plus a subsequent 15.4 Bcfe (2.6 MMBoe) reduction in underperforming producing properties. The 2004 revision included approximately 28.5 Bcfe (4.8 MMBoe) of proved non-producing reserves and 34.4 Bcfe (5.7 MMBoe) of proved undeveloped reserves. As a result of the events leading up to our July 2004 financial restructuring, we were forced to delay our 2004 capital expenditure program which resulted in a decline in our natural gas and oil production for the year ended December 31, 2004 because we were unable to offset natural production declines with new production. We had further production declines for the year ended December 31, 2005 resulting from a reduction in our capital expenditure program due to rig delays and the impact of Hurricanes Katrina and Rita. Our September 2006 production from our South Louisiana properties was 2.7 MMcfe/d (0.4 MBoe/d), which is approximately 69% of our average daily pre-hurricane production from these properties during February through July 2005. We continue to see some post-hurricane improvement in production from our South Louisiana properties; however, it is common for production from mature water-drive wells not to return to pre-shut-in production rates after being shut-in. We do not expect that all of these wells will return completely to pre-hurricane production rates.

Like all natural gas and oil production companies, we face the challenge of natural production declines. Natural gas and oil production from a given well naturally decreases over time. We attempt to overcome this natural decline by increasing our production through the development and identification of additional reserves

and by acquiring additional reserves that are expected to produce. Our future growth will depend upon our ability to increase production in an amount which exceeds our production declines and to add natural gas and oil reserves at a reasonable cost. We will maintain our focus on adding reserves through drilling and acquisitions and producing such reserves at attractive costs. Our independent reserve engineers have estimated that our natural gas and oil production in 2006 from our proved developed producing reserves as of December 31, 2005 will decline by approximately 18.6% from our production from those reserves for the year ended December 31, 2005.

This discussion and analysis of our financial condition and results of operations reflects the restatement of our financial statements:

•

for years ending prior to December 31, 2005 to reflect our conversion to the successful efforts method of accounting for natural gas and oil properties and to correct our previously recorded income tax provision; and

•

for the years ended December 31, 2003 and December 31, 2004 to reflect our previously understated asset retirement obligation.

In addition, in connection with our July 2004 financial restructuring, we entered into new derivative arrangements and no longer designated our derivative arrangements as hedges.

This discussion does not give effect to the 1-for- reverse stock split of our common stock expected to be effected in connection with this offering.

For the foregoing reasons, our results of operations and period-to-period comparisons of these results and certain other financial information may not be meaningful or indicative of our future results of operations.

Revenue and Expense Drivers

Revenues

Natural gas and oil sales. Our revenues are generated from sales of natural gas and oil which are substantially dependent on prevailing prices of natural gas and oil. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply of or demand for natural gas and oil, market uncertainty and a variety of additional factors beyond our control. We enter into derivative arrangements for a portion of our natural gas and oil production to achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas and oil. Our derivative arrangements for future production prior to our July 2004 financial restructuring were designated as hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), and accordingly realized gains and losses from these derivative arrangements were recorded as natural gas and oil sales and unrealized gains and losses from these derivative arrangements were not reported in earnings.

We generally sell our natural gas and oil at current market prices at the wellhead, or we transport it to “pooling points” where it is sold. We are required to pay gathering and transportation costs with respect to substantially all of our products. We market our products in several different ways depending upon a number of factors, including the availability of purchasers for the product at the wellhead, the availability and cost of pipelines near the well, market prices, pipeline constraints and operational flexibility. We sold an average of approximately 12.6 Mmcf/d and 12.8 Mmcf/d of natural gas and approximately 1.9 MBbls/d and 1.9 MBbls/d of oil and NGLs during the year ended December 31, 2005 and the six months ended June 30, 2006, respectively.

Operating Expenses

Our operating expenses primarily involve the expense of operating and maintaining our wells.

•

Lease operating expenses. Our lease operating expenses include certain direct employment-related costs, repair and maintenance costs, electrical power and fuel costs and other expenses necessary to

maintain our operations. Our lease operating expenses are driven in part by the type of commodity produced, the level of maintenance activity and the geographical location of our properties. Workover costs that improve the value of our properties are capitalized and otherwise are included in lease operating expenses.

•

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

•

General and administrative expenses. General and administrative expenses include employee compensation and benefits, professional fees for legal, accounting and other advisory services, corporate overhead and franchise taxes. Upon completion of this offering, we expect that our ongoing general and administrative expenses will increase as a result of significant increases in legal, accounting and other expenses associated with compliance with the Sarbanes-Oxley Act of 2002, other rules and regulations of the SEC, the listing standards of The Nasdaq Global Market and otherwise being a public company.

•

Exploration expenses. Exploration expenses include the geological and geophysical costs relating to our exploration efforts and costs related to unsuccessful exploratory wells.

•

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

•

Property impairments. We review our natural gas and oil properties for impairment on a field-by-field basis whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The impairment provision for each field is based on the excess of the carrying value of the field over its fair value.

•

Derivative loss. Subsequent to our July 2004 financial restructuring, we do not designate any of our derivative arrangements relating to future production as hedges under SFAS 133. Accordingly, derivative loss represents the changes in fair market value of, and realized gains and losses related to, our derivative arrangements.

Other Expenses and Income

Interest and other income. We also generate interest income from our cash deposits and other income (loss) from gains or losses on sales of our assets.

Interest expense. Our interest expense reflects our borrowing costs under our credit facility, our senior notes and our senior subordinated notes. Interest accrued on our senior notes and senior subordinated notes is payable in the form of additional notes. Upon consummation of the Recapitalization, the Incentive Issuance, this offering and the application of the net proceeds of this offering, we expect our interest expense to reflect only our borrowing costs under our credit facility.

Income tax benefit (expense). Income tax benefit (expense) represents current and deferred federal and state income taxes. Our taxes are calculated by applying the statutory tax rates in effect for the applicable period to our book loss or book income. These calculated income tax amounts are further adjusted to reflect the impact of federal and state valuation allowances and to adjust for the tax effect of book income and book expense items which are not taxable or deductible for tax purposes.

Reserve Write Down

Upon joining us in 2003, our management undertook a detailed review and analysis of our proved natural gas and oil reserves. Netherland, Sewell & Associates, Inc., one of our independent reserve engineers, has performed our reserves evaluation since our formation in 2001. LaRoche Petroleum Consultants, Ltd., our other

independent reserve engineering firm, was first engaged in 2004 to prepare a report on our proved reserves located in Louisiana and Texas as of December 31, 2004. Based on reports from both of our independent reserve engineering firms, our estimates of proved natural gas and oil reserves were revised downward by a total of 37.7 Bcfe (6.3 MMBoe) for the year ended December 31, 2003, which included approximately 22.3 Bcfe (3.7 MMBoe) of proved non-producing and proved undeveloped reserves plus a subsequent 15.4 Bcfe (2.6 MMBoe) reduction in underperforming producing properties, and by an additional 62.9 Bcfe (10.5 MMBoe) during the year ended December 31, 2004, which included approximately 28.5 Bcfe (4.8 MMBoe) of proved non-producing reserves and 34.4 Bcfe (5.7 MMBoe) of proved undeveloped reserves. The decrease primarily affected proved developed non-producing and proved undeveloped reserves that had been on our books prior to 2003. The revisions are not expected to have a material impact on our near-term production volumes, and it is still our intention to make investments in a number of the projects impacted by the revisions. The primary reasons for the revisions were as follows:

•

Two successful recompletions in the New Taiton field in south Texas during late 2002 resulted in the addition of proved developed non-producing and proved undeveloped locations throughout much of the field. This early success led our internal engineers and Netherland, Sewell & Associates, Inc., our independent reserve engineers, to believe that New Taiton’s potential development was analogous to a large, nearby field. Subsequent producing performance and failure of additional recompletions caused us to reconsider the initial conclusions. As a result, the majority of these reserves were removed or were moved to probable or possible status in 2003. We made additional downward revisions to our proved reserves in 2003 after disappointing well performance subsequent to our new completions caused us to determine that certain proved undeveloped locations in the La Copita field in south Texas were not economic.

•

In connection with our retention of LaRoche Petroleum Consultants, Ltd., we undertook a more detailed analysis of the mapping underlying our reserves which resulted in the reclassifications of certain proved undeveloped reserves in the New Taiton and La Copita fields and certain proved undeveloped reserves in Louisiana as probable or possible as of December 31, 2004.

•

In Oklahoma, prior to 2003, a large number of proved developed non-producing reserves were generally recognized throughout a broad area. We developed an extensive casing gas gathering system to rapidly exploit the reserves. Well performance subsequent to recompletion indicated reserve estimates of approximately 46% of the previously estimated reserves. This lower-than-expected well production, along with higher costs, made many of the identified reserves uneconomic, and resulted in a significant downward revision in 2004. Our 2004 reserve write downs also reflect a downward revision of our estimated proved undeveloped reserves attributable to an expected waterflood response in the Hunton Devonian limestone. Although water had been injected into portions of the reservoir for some time, we did not have conclusive evidence that any response to water injection was occurring. We revised downward the balance of these estimated proved undeveloped reserves in 2005, and these downward revisions were reflected in the net increase in the revisions of previous estimates in our estimated net proved reserves in 2005 of 8.0 Bcfe (1.3 MMBoe). As of the date of this prospectus, we recognized no proved undeveloped reserves attributable to expected waterflood response in the Hunton reservoir at the Northeast Fitts Unit; however, we do attribute approximately 1.34 MMBoe of our proved reserves to waterflood response from the Allen and Ada fields in Oklahoma.

Asset Retirement Obligation Restatement and Tax Provision Restatement

During the fourth quarter of 2005, we determined that our initial adoption of SFAS 143 understated our asset retirement obligation. The understatement was primarily attributable to our understating the number of wells subject to future retirement obligations and associated retirement costs on certain properties. Additionally, we overstated the useful lives of a significant portion of our properties which contributed to the understatement of our asset retirement obligation because we determined the present value of the asset retirement obligation to be recorded by discounting the estimated future cash flows related to our asset retirement obligation over the useful lives of our properties.

We restated our financial statements for the years ended December 31, 2003 and December 31, 2004 to reflect the revision to our asset retirement obligation for those periods. The effect of the restatement at adoption is as follows:


	Initial adoption			Restated adoption
	(in thousands)
Natural gas and oil properties	$	1,563		$	6,033
Accumulated depreciation, depletion and amortization		(276	)		1,496
Asset retirement obligations		(1,996	)		(7,103	)
Deferred tax liability		273			(164	)

Cumulative effect of change in accounting principle, net of income tax benefit of $273 at initial adoption and income tax expense of $164 as restated	$	(436	)	$	262

The following table summarizes the restated changes to our asset retirement obligation for the years ended December 31, 2004 and December 31, 2005:


	Year Ended December 31,
	2004			2005
	(in thousands)
Asset retirement obligations at beginning of period	$	8,319		$	9,274
Accretion expense		868			991
Liabilities incurred		135			450
Liabilities settled		(48	)		(145	)

Asset retirement obligations at year-end		9,274			10,570
Less: current asset retirement obligations		85			517

Long-term asset retirement obligations	$	9,189		$	10,053

During 2005, we reviewed the tax basis of all our related assets and net operating loss carryforwards for the current year and previous four years. As a result of this review, we restated our 2003 financial statements to reduce by $5.6 million the valuation allowance previously recorded for the year ended December 31, 2003. We determined that the valuation allowance recorded during 2003 was not required because the reported gross federal deferred tax assets were more likely than not fully realizable as an offset against the recorded federal deferred tax liabilities.

The effect of the restatement of our asset retirement obligations, net of income taxes, and our tax provision on the financial statements was an increase in retained earnings as of December 31, 2004 of $4.6 million, an increase in net loss by $0.3 million ($0.04 per basic and diluted share) for the year ended December 31, 2004 and a decrease in net loss by $5.3 million ($0.99 per basic and diluted share) for the year ended December 31, 2003.

Critical Accounting Policies

Basis of Presentation. The consolidated financial statements include our accounts and the accounts of our subsidiaries as of the respective dates of such financial statements. All inter-company balances have been eliminated. Certain prior year amounts for accounts payable and accrued liabilities have been reclassified to conform to current year presentation due to segregation of the accounts on the consolidated balance sheets. This discussion and analysis of our financial condition and results of operation are based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles as presently established in the United States.

Use of Estimates in the Preparation of Financial Statements. The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, equity,

revenues and expenses. Our estimates include those related to natural gas and oil revenues, bad debts, natural gas and oil properties, operating expenses, natural gas and oil reserves, abandonment liabilities, contingencies; and litigation. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates used in preparation of our financial statements. In addition, alternatives can exist among various accounting methods. In such cases, the choice of accounting method can have a significant impact on reported amounts. After this offering, we will discuss the development, selection and disclosure of each of these with our audit committee. We believe the accounting policies described below reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read the notes to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Natural Gas and Oil Reserve Estimates. Independent petroleum engineers prepare estimates of our natural gas and oil reserves. Proved reserves, estimated future net revenues and the present value of our reserves are estimated based upon a combination of historical data and estimates of future activity. You should not assume that the present value of our reserves is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based our present value from proved reserves on prices on the date of the estimate. The reserve estimates are used in calculating depletion, depreciation and amortization and in the assessment of assets for impairment as further discussed below. Significant assumptions are required in the valuation of proved natural gas and oil reserves which, as described herein, may affect the amount at which natural gas and oil properties are recorded. Actual results could differ materially from these estimates.

Revenue Recognition Policy. We follow the accrual method of accounting for revenue recognition and natural gas imbalances. Natural gas and oil revenues are recognized when sales are confirmed or reasonably anticipated and collection of the sales proceeds is probable. Accrued sales are based on field or pipeline volume statements valued at purchaser contract terms. Volumes attributable to natural gas imbalances are valued at published prices for the anticipated settlement date and accrued accordingly. Recognized sales attributable to natural gas imbalances were not significant for the periods presented.

Change in Accounting Principle to Successful Efforts from Full Cost. Generally accepted accounting principles allow the option of two acceptable methods for accounting for natural gas and oil properties. The primary differences between the two methods are in the treatment of exploration costs, the computation of depreciation, depletion and amortization, and the calculation of property impairments.

Effective January 1, 2005, we changed our accounting method for natural gas and oil properties from the full cost method to the successful efforts method. Management believes that the successful efforts method of accounting is the preferable method in the natural gas and oil industry and that the accounting change will more accurately present the results of our exploration and development activities, minimize asset write-offs caused by temporary declines in natural gas and oil prices and reflect an impairment in the carrying value of our natural gas and oil properties only when there has been a permanent decline in their fair value.

Under the successful efforts method of accounting, we capitalize all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. All costs related to unsuccessful exploratory wells are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

Unproved leasehold costs are capitalized and reviewed periodically for impairment. Costs related to impaired prospects are charged to expense. If natural gas and oil prices decline in the future, some of these unproved prospects may not be economic to develop, which could lead to increased impairment expense.

Costs of development dry holes and proved leaseholds are amortized on the unit-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment and drilling costs is based on the unit-of-production method using proved developed reserves on a field basis.

We review our proved natural gas and oil properties for impairment on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from estimated future production of total proved natural gas and oil reserves based on our expectations of future natural gas and oil prices and costs. Due to the volatility of natural gas and oil prices, it is possible that our assumptions regarding natural gas and oil prices may change in the future and may result in future impairment provisions. We recorded impairment provisions related to our proved natural gas and oil properties of $3.8 million, $20.7 million and $1.3 million for the years ended December 31, 2003, December 31, 2004 and December 31, 2005, respectively. The impairment provision for 2004 resulted primarily from a downward revision of our reserves at our New Taiton field in Texas.

We retrospectively adjusted our financial statements for the periods ending prior to December 31, 2005 to give effect to our change to the successful efforts method of accounting. The effect of the retrospective application, net of income taxes, was a reduction of retained earnings as of December 31, 2004 of $56.5 million, primarily resulting from a reduction of net property, plant and equipment of $92.3 million and a reduction of deferred income tax liability of $35.8 million. The change in accounting method increased our net loss by $5.6 million ($1.05 per basic and diluted share) and $19.8 million ($3.32 per basic and diluted share) for the years ended December 31, 2003 and December 31, 2004, respectively.

Asset Retirement Obligations. Effective January 1, 2003, we adopted SFAS 143. SFAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Periodic accretion of the discount of the estimated liability is recorded in the statement of operations. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability.

We escrow a portion of the future abandonment costs of our wells and facilities. Approximately $0.5 million is included in escrowed and restricted funds on our balance sheets as of December 31, 2004 and December 31, 2005.

Asset Retirement Obligation Restatement and Tax Provision Restatement. During the fourth quarter of 2005, we determined that our initial adoption of SFAS 143 understated our asset retirement obligation. The understatement was primarily attributable to our understating the number of wells subject to future retirement obligations and associated retirement costs on certain properties. Additionally, we overstated the useful lives of a significant portion of our properties which contributed to the understatement of our asset retirement obligation because we determined the present value of the asset retirement obligation to be recorded by discounting the estimated future cash flows related to our asset retirement obligation over the useful lives of our properties. During 2005, we reviewed the tax basis of all our related assets and net operating loss carryforwards for the current year and previous four years. As a result of this review, we restated our 2003 financial statements to reduce by $5.6 million the valuation allowance previously recorded for the year ended December 31, 2003. We determined that the valuation allowance recorded during 2003 was not required because the reported gross federal deferred tax assets were more likely than not fully realizable as an offset against the recorded federal deferred tax liabilities. Please see “—Overview—Asset Retirement Obligation Restatement and Tax Provision Restatement” above for additional information about these restatements.

Depletion, Depreciation and Amortization. We use estimates of proved natural gas and oil reserve quantities to estimate depletion, depreciation and amortization expense using the unit-of-production method of accounting. Depreciation of property and equipment other than natural gas and oil properties is calculated using the straight-

line method over the useful lives of the assets ranging from three to seven years. Any change in reserves directly impacts the amount of depreciation, depletion and amortization expense we recognize in a given period. Assuming no other changes, as our reserves increase, depletion, depreciation and amortization expense decreases and as reserves decrease, depletion, depreciation and amortization expense increases. Changes in our estimate of proved reserves can cause material changes in our depletion, depreciation and amortization expense.

Fair Value of Financial Instruments. Our financial instruments consist primarily of cash equivalents, trade receivables, trade payables, derivative instruments and bank debt. Our cash equivalents, trade receivables and trade payables are considered to be representative of their respective fair values due to their short maturities. Our derivative instruments are reflected at fair value as provided by our counterparties. The fair value of our bank debt approximates its carrying value because the interest rate available to us is variable and reflective of market rates. Our senior notes and senior subordinated notes do not trade on any market and to determine the fair value of these financial instruments is not practicable.

Derivative Instruments. We account for our derivative arrangements under SFAS 133, as amended by Statement of Financial Accounting Standards No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133,” Statement of Financial Accounting Standards No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities,” and Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which is more fully discussed below under “—Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Under SFAS 133, instruments qualifying for hedge accounting treatment are recorded on the balance sheet as an asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income until the sale of the related hedged production is recognized in earnings, at which time amounts previously recognized on other comprehensive income are recognized in earnings. Any ineffective portion of changes in fair value on derivatives qualifying for hedge accounting treatment is recognized in earnings immediately. Instruments not qualifying for hedge accounting treatment are recorded on the balance sheet at fair value and subsequent changes in fair value are recognized in earnings. Derivative instruments entered into prior to our July 2004 financial restructuring qualified for hedge accounting treatment; however, derivative instruments entered into subsequent to such restructuring were not qualified for hedge accounting treatment.

Deferred Income Taxes. We follow the asset and liability method for accounting for deferred income taxes and income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for natural gas and oil properties for financial reporting purposes and income tax purposes. As of December 31, 2005, we had a net deferred tax liability of $1.9 million. For financial reporting purposes, all development expenditures and certain exploratory costs on successful wells are capitalized and depreciated, depleted and amortized on the units-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code of 1986, as amended, or the Code, that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion and capitalization of interest expenses for income tax purposes. Beginning in 2001, we established a valuation allowance which we increased periodically to reflect the uncertainty about the realization of the deferred tax asset. In 2005, we increased the valuation allowance of $6.2 million by an additional $9.8 million and in the first six months of 2006, we increased the valuation allowance of $16.0 million by an additional $0.9 million based on uncertainty surrounding our ability to utilize the entire balance of our deferred tax assets based on an analysis of whether we are more likely than not to receive such a benefit and if so, to what extent.

Contingencies. Contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that a liability has been incurred and the amount of the liability can reasonably be determined.

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (“SFAS 123(R)”), which is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” (“SFAS 123”). SFAS 123(R) is effective for public companies for interim or annual periods beginning after December 15, 2005. SFAS 123(R) supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows.” SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in financial statements based on their fair values beginning with the first interim or annual period after December 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS 123 are no longer an alternative to financial statement recognition. SFAS 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow rather than as an operating cash flow as currently required. SFAS 123(R) is effective for our first annual reporting period ending after December 31, 2005. We adopted SFAS 123(R) on January 1, 2006 using a modified prospective application. Our adoption of SFAS 123(R) did not have an impact on our financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”), which replaces Accounting Principles Board Opinion No. 20 “Accounting Changes,” and Statement of Financial Accounting Standards No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005 and requires retrospective application to prior period financial statements of voluntary changes in accounting principles unless it is impractical to determine either the period-specific effects or the cumulative effect of the change. We adopted SFAS 154 during 2005. The adoption of SFAS 154 resulted in additional disclosure requirements for our change in accounting principle from full cost to successful efforts and our restatements. See “—Critical Accounting Policies—Change in Accounting Principle to Successful Efforts from Full Cost” and “—Critical Accounting Policies—Asset Retirement Obligation Restatement and Tax Provision Restatement.”

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” of being sustained if the position were to be challenged by a taxing authority. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We are currently evaluating the impact, if any, the adoption of FIN 48 will have on our consolidated financial position or results of operations.

Results of Operations

The following table sets forth certain operating information with respect to our natural gas, oil and NGL operations for the periods presented:


	Year Ended December 31,								Six Months Ended June 30,
	2003			2004			2005		2005		2006
	(Restated)
Production data:
Oil (MBbls)		688			625			598		309		298
Natural gas (MMcf)		6,545			5,158			4,592		2,348		2,324
NGLs (MBbls)		107			120			107		60		43
Combined volumes (MMcfe)		11,318			9,630			8,826		4,560		4,370
Combined volumes (MBoe)		1,886			1,605			1,471		760		728
Average prices:
Oil (per Bbl)	$	30.14		$	40.66		$	55.55	$	50.79	$	65.95
Effects of hedging		(0.54	)		—			—		—		—

Oil price (net of hedging)	$	29.60		$	40.66		$	55.55	$	50.79	$	65.95
Natural gas (per Mcf)	$	5.52		$	5.93		$	7.98	$	6.32	$	7.00
Effects of hedging		(1.77	)		(1.66	)		—		—		—

Natural gas price (net of hedging)	$	3.75		$	4.27		$	7.98	$	6.32	$	7.00
NGLs (per Bbl)	$	21.37		$	27.15		$	34.56	$	29.76	$	39.41
Combined (per Mcfe):
Price	$	5.23		$	6.15		$	8.34	$	7.09	$	8.61
Effects of hedging		(1.06	)		(0.89	)		—		—		—

Price (net of hedging)	$	4.17		$	5.27		$	8.34	$	7.09	$	8.61
Combined (per Boe):
Price	$	31.37		$	36.91		$	50.02	$	42.52	$	51.64
Effects of hedging		6.34			5.32			—		—		—

Price (net of hedging)	$	25.03		$	31.59		$	50.02	$	42.52	$	51.64


	Year Ended December 31,						Six Months Ended June 30,
	2003		2004		2005		2005		2006
	(Restated)
Average expenses (per Mcfe):
Production and ad valorem taxes	$	0.38	$	0.32	$	0.38	$	0.38	$	0.51
Lease operating expenses		1.05		1.25		1.31		1.20		1.46
General and administrative expenses		0.92		0.86		0.96		0.84		1.27
Exploration expenses		0.50		0.09		0.39		0.10		0.19
Depreciation, depletion and amortization		1.90		3.24		2.35		2.33		2.38
Property impairments		0.34		2.15		0.14		—		—
Derivative loss		—		0.69		3.84		3.94		1.54
Average expenses (per Boe):
Production and ad valorem taxes	$	2.28	$	1.93	$	2.26	$	2.28	$	3.06
Lease operating expenses		6.32		7.49		7.88		7.22		8.78
General and administrative expenses		5.51		5.15		5.73		5.07		7.62
Exploration expenses		2.98		0.53		2.35		0.58		1.12
Depreciation, depletion and amortization		11.42		19.44		14.08		13.98		14.27
Property impairments		2.02		12.90		0.85		—		—
Derivative loss		—		4.11		23.01		23.66		9.23


	As of December 31,
	2003		2004		2005
	(dollars in thousands)
Estimated net proved reserves:
Oil (MBbls)		13,620		9,578		9,572
Natural gas (MMcf)		80,423		37,311		42,066
NGLs (MBbls) (1)		—		1,119		1,098
Total (MMcfe)		162,141		101,491		106,089
Total (MBoe)		27,024		16,915		17,681
PV-10 (2)	$	379,494	$	239,632	$	371,303

(1)	Oil reserve data as of December 31, 2003 includes NGLs.

(2)	See note 3 to “Summary—Summary Historical Reserve and Operating Data.”


	Year Ended December 31,									Six Months Ended June 30,
	2003			2004			2005			2005			2006
	(Restated)			(Restated)						(Unaudited)
	(in thousands)
Revenues:
Oil	$	20,377		$	25,431		$	33,228		$	15,694		$	19,631
Natural gas		24,553			22,021			36,634			14,848			16,271
NGLs		2,027			3,257			3,714			1,776			1,713

Total revenues		46,957			50,709			73,576			32,318			37,615
Expenses:
Production and ad valorem taxes		4,307			3,091			3,332			1,731			2,231
Lease operating expenses		11,915			12,018			11,594			5,487			6,398
General and administrative expenses		10,388			8,272			8,436			3,851			5,548
Exploration expenses		5,630			854			3,460			444			818
Depreciation, depletion and amortization		21,539			31,207			20,771			10,623			10,393
Property impairments		3,802			20,711			1,254			—			—
Derivative loss		—			6,604			33,851			17,983			6,725

Total operating expenses		57,581			82,757			82,698			40,119			32,113

Income (loss) from operations		(10,624	)		(32,048	)		(9,122	)		(7,801	)		5,502
Interest and other income		7			203			561			78			110
Interest expense		(13,661	)		(16,958	)		(19,496	)		(9,286	)		(11,266	)

Loss before income taxes		(24,278	)		(48,803	)		(28,057	)		(17,009	)		(5,654	)
Income tax benefit (expense)		8,624			12,472			209			127			(317	)

Loss before cumulative effect of change in accounting principle		(15,654	)		(36,331	)		(27,848	)		(16,882	)		(5,971	)
Cumulative effect of change in accounting principle, net of income tax of $273 in 2003		262			—			—			—			—

Net loss	$	(15,392	)	$	(36,331	)	$	(27,848	)	$	(16,882	)	$	(5,971	)

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Revenues. Revenues for the six months ended June 30, 2006 increased $5.3 million, or 16%, to $37.6 million as compared to $32.3 million for the six months ended June 30, 2005. This increase was due primarily to increases in the prices received for natural gas, oil and NGLs of 11%, 30% and 32%, respectively, partially offset by decreases in natural gas, oil and NGL production of 1%, 4% and 27%, respectively.

The average sales prices for natural gas, oil and NGLs for the six months ended June 30, 2006 were $7.00 per Mcf, $65.95 per Bbl and $39.41 per Bbl, respectively, as compared to average sales prices for natural gas, oil and NGLs for the six months ended June 30, 2005 of $6.32 per Mcf, $50.79 per Bbl and $29.76 per Bbl, respectively.

The 4% decrease in oil production was due primarily to production declines in Louisiana and Texas of 22% and 13%, respectively. The decline in Louisiana production was due primarily to wells not fully recovering to previous production levels after a mandatory shut-in in response to Hurricanes Katrina and Rita. The decline in Texas production was due primarily to natural declines and maintenance issues which resulted in production shut-ins, primarily in south Texas, partially offset by production on new wells in south and east Texas.

The 1% decrease in natural gas production was due primarily to production declines in Louisiana and Oklahoma of 21% and 7%, respectively, partially offset by a 7% production increase in Texas. The decrease in Oklahoma production resulted from production declines, which are typical for tight gas sands, and weather related shut-ins. Declines in our Louisiana production resulted from wells not fully recovering to previous production levels after a mandatory shut-in in response to Hurricanes Katrina and Rita. The increase in Texas production was due primarily to production from new wells in south and east Texas.

The decrease of 27% in NGL production was due primarily to an overall decline in processed gas production at our La Copita Field in south Texas.

Lease operating expenses. Lease operating expenses for the six months ended June 30, 2006 increased $0.9 million, or 17%, to $6.4 million as compared to $5.5 million for the six months ended June 30, 2005 and increased 22% per Mcfe (Boe) during the six months ended June 30, 2006 to $1.46 per Mcfe ($8.78 per Boe) as compared to $1.20 per Mcfe ($7.22 per Boe) during the six months ended June 30, 2005. The increase in lease operating expenses was due primarily to increased costs for well insurance, chemicals, and surface and subsurface repair and maintenance. During early 2005, marginal wells in need of repair were temporarily shut-in which delayed completion of repairs. As natural gas and oil prices have increased, many of these wells were repaired and returned to production, which resulted in increased repair and maintenance costs during the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. Additionally, field employee costs during the six months ended June 30, 2006 exceeded field employee costs for the six months ended June 30, 2005 due to higher field staff bonuses during the six months ended June 30, 2006. The increase in lease operating expenses on a per Mcfe (Boe) basis during the six months ended June 30, 2006 was due primarily to increased costs and a 4% decline in production.

Production and ad valorem taxes. Production and ad valorem taxes for the six months ended June 30, 2006 increased $0.5 million, or 29%, to $2.2 million from $1.7 million for the six months ended June 30, 2005. The increase was due primarily to increases in revenues during the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. Production and ad valorem taxes were 6% of revenues for the six months ended June 30, 2006 and 5% of revenues for the six months ended June 30, 2005. These rates are lower than historical percentages due to current and retroactive exemptions granted by the State of Texas for high-cost natural gas.

General and administrative expenses. General and administrative expenses, or G&A, for the six months ended June 30, 2006 increased $1.7 million, or 44%, to $5.5 million as compared to $3.9 million for the six months ended June 30, 2005. The increase in G&A was due primarily to increases in employee-related costs,

legal costs and audit costs during the six months ended June 30, 2006. Employee-related costs increased primarily due to our hiring additional staff and awarding annual salary increases, legal costs increased primarily due to an increase in legal issues arising in the normal course of business and audit costs increased primarily due to additional fees related to our conversion from full-cost accounting to successful efforts accounting and the restatement of our prior period financial statements.

Exploration expenses. Exploration expenses for the six months ended June 30, 2006 increased $0.4 million, or 84%, to $0.8 million as compared to $0.4 million for the six months ended June 30, 2005. The increase was due primarily to an increase in delay rental costs during the six months ended June 30, 2006 resulting from the timing of delay rental payments and the expiration of a lease during February 2006.

Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A, for the six months ended June 30, 2006 decreased $0.2 million, or 2%, to $10.4 million as compared to $10.6 million for the six months ended June 30, 2005. DD&A for the six months ended June 30, 2006 increased 2% to $2.38 per Mcfe ($14.27 per Boe), as compared to $2.33 per Mcfe ($13.98 per Boe) for the six months ended June 30, 2005. The decrease in DD&A expense for the six months ended June 30, 2006 was due primarily to a decrease in production, partially offset by a higher DD&A rate per Mcfe (Boe).

Loss on derivatives. Derivative loss for the six months ended June 30, 2006 decreased $11.3 million, or 63%, to $6.7 million as compared to $18.0 million during the six months ended June 30, 2005. The decrease in derivative losses for the six months ended June 30, 2006 as compared to the six months ended June 30, 2005 was due primarily to a decrease in unrealized natural gas and oil derivative losses resulting from less significant unfavorable changes in the prices of natural gas and oil and due to more favorable pricing under our derivative instruments during the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. See “—Quantitative and Qualitative Disclosures about Market Risk.”

Interest expense. Interest expense increased $2.0 million, or 21%, to $11.3 million during the six months ended June 30, 2006 from $9.3 million for the six months ended June 30, 2005. The increase in interest expense during the six months ended June 30, 2006 was due to increased interest rates under our credit facility and increased outstanding debt under our credit facility, senior notes and senior subordinated notes.

Income tax benefit. We are required to establish a net deferred tax liability or benefit calculated at the applicable federal and state tax rates resulting primarily from financial reporting and income tax reporting basis differences in natural gas and oil properties. Beginning in 2001, we established a valuation allowance which we increased periodically to reflect the uncertainty about the realization of the deferred tax asset. We increased the prior accumulated valuation allowance of $16.0 million for the six months ended June 30, 2006 by an additional $0.9 million, based on uncertainty surrounding our ability to utilize the entire balance of our deferred tax assets based on an analysis of whether we are more likely than not to receive such a benefit and if so, to what extent.

We recognized income tax expense of $0.3 million for the six months ended June 30, 2006 primarily due to the recognition of current federal alternative minimum tax of $0.07 million, current state income tax of $0.09 million and the recognition of $0.16 million in deferred state tax expense. The deferred tax expense in the amount of $0.16 million relates primarily to the implementation of the Texas margin tax.

Net loss. Due to the factors described above, a net loss of $6.0 million was recorded for the six months ended June 30, 2006 compared to a net loss of $16.9 million for the six months ended June 30, 2005.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Revenues. Revenues for the year ended December 31, 2005 increased $22.9 million, or 45%, to $73.6 million as compared to $50.7 million for the year ended December 31, 2004. This increase was due primarily to increases in the prices received for oil, natural gas and NGLs of 37%, 87% and 27%, respectively, which were partially offset by decreases in oil, natural gas and NGL production of 4%, 11% and 10%, respectively.

The average sales prices for oil, natural gas and NGLs for the year ended December 31, 2005 were $55.55 per Bbl, $7.98 per Mcf and $34.56 per Bbl, respectively, as compared to the average sales prices for oil, natural gas and NGLs for the year ended December 31, 2004 of $40.66 per Bbl, $4.27 per Mcf and $27.15 per Bbl, respectively. We had no oil hedging losses during the years ended December 31, 2004 or December 31, 2005 and no natural gas hedging losses during the year ended December 31, 2005. The average sales prices for natural gas received during the year ended December 31, 2004 were net of hedging losses of $1.66 per Mcf.

The 4% decrease in oil production was due primarily to production declines during the year ended December 31, 2005 in Louisiana and Texas of 30% and 14%, respectively. The decline in Louisiana and Texas production was due primarily to a loss of production from August through December 2005 of approximately 9,200 Bbls of oil as a result of mandatory shut-ins in response to Hurricanes Katrina and Rita and our subsequent inability to return to pre-hurricane production rates.

The 11% decrease in natural gas production was due primarily to production declines during the year ended December 31, 2005 in Louisiana, Oklahoma and Texas of 19%, 11% and 8%, respectively. Production decreases during the year ended December 31, 2005 resulted primarily from natural production declines in Texas and Oklahoma, which are typical for tight gas sands, and decreases in production of approximately 87,000 Mcf in Louisiana due to Hurricanes Katrina and Rita. Reductions in our capital spending during the years ended December 31, 2003 and December 31, 2004 due to liquidity constraints delayed plans to offset natural declines in these areas with new production. Production during the year ended December 31, 2005 was also adversely affected by intermittent shut-ins necessary for repairs.

The decrease of 10% in NGL production was due primarily to the declines in natural gas production in Texas discussed above.

Lease operating expenses. Lease operating expenses for the year ended December 31, 2005 decreased $0.4 million, or 4%, to $11.6 million as compared to $12.0 million for the year ended December 31, 2004 and increased 5% per Mcfe (Boe) during the year ended December 31, 2005 to $1.31 per Mcfe ($7.88 per Boe) as compared to $1.25 per Mcfe ($7.49 per Boe) during the year ended December 31, 2004. The decrease in lease operating expenses was due primarily to cost saving measures implemented during the year ended December 31, 2004. These cost saving measures included closing our Louisiana field office, reducing our field staff and reducing costs associated with producing certain marginal wells due to curtailment of daily production. The increase in lease operating expenses on a per Mcfe (Boe) basis during the year ended December 31, 2005 was due primarily to a 8% decrease in production during 2005.

Production and ad valorem taxes. Production and ad valorem taxes for the year ended December 31, 2005 increased $0.2 million, or 8%, to $3.3 million from $3.1 million for the year ended December 31, 2004. The increase was due primarily to increases in revenues during the year ended December 31, 2005 as compared to the year ended December 31, 2004. Production and ad valorem taxes were 5% of revenues for both years which is lower than historical percentages due to current and retroactive exemptions granted by the State of Texas for high-cost natural gas.

General and administrative expenses. G&A for the year ended December 31, 2005 increased $0.2 million, or 2%, to $8.4 million as compared to $8.3 million for the year ended December 31, 2004. The increase in G&A was due primarily to an increase in professional fees of $0.2 million for the year ended December 31, 2005 and increased franchise taxes of $0.3 million during the year ended December 31, 2005 due primarily to our July 2004 financial restructuring. These costs were partially offset by reduced employee-related costs of $0.3 million resulting from staff reductions, attrition and cost saving reductions made throughout the year ended December 31, 2004.

Exploration expenses. Exploration expenses for the year ended December 31, 2005 increased $2.6 million, or 305%, to $3.5 million as compared to $0.9 million for the year ended December 31, 2004. The increase was due

primarily to increases in dry hole costs and geological and geophysical costs of $1.7 million and $0.6 million, respectively, during the year ended December 31, 2005 as compared to the year ended December 31, 2004.

Depreciation, depletion and amortization. DD&A for the year ended December 31, 2005 decreased $10.5 million, or 34%, to $20.8 million as compared to $31.2 million for the year ended December 31, 2004. DD&A for the year ended December 31, 2005 decreased to $2.35 ($14.08 per Boe), or 27% on a per-Mcfe (Boe) basis, as compared to $3.24 ($19.44 per Boe) for the year ended December 31, 2004. The decrease in DD&A expenses and the DD&A rate during the year ended December 31, 2005 was due primarily a significant decrease in depletable costs on our New Taiton field in Texas resulting from a impairment of $20.3 million at December 31, 2004. Additionally we experienced a decrease in production and an increase in reserves of 8% and 4%, respectively, for the year ended December 31, 2005 as compared to the year ended December 31, 2004 which further reduced the DD&A rate for the year ended December 31, 2005 and resulted in a significantly lower depletion rate during the year ended December 31, 2005. The decrease in DD&A during the year ended December 31, 2005 was due to the lower DD&A rate per Mcfe (Boe) and the decrease in production.

Property impairments. Property impairments for the year ended December 31, 2005 decreased $19.5 million, or 94%, to $1.3 million as compared to $20.7 million for the year ended December 31, 2004. Property impairments for the year ended December 31, 2004 were due primarily to a significant downward revision in reserves on our New Taiton field in Texas at year-end 2004, which resulted in a property impairment of $20.3 million. During the year ended December 31, 2005, we did not experience any significant reserve writedowns.

Loss on derivatives. Derivative loss for the year ended December 31, 2005 increased $27.2 million, or 413%, to $33.9 million as compared to $6.6 million during the year ended December 31, 2004. We recognized natural gas and oil realized losses of $11.9 million, natural gas and oil unrealized losses of $22.3 million and interest rate unrealized gains of $0.4 million during the year ended December 31, 2005. During the year ended December 31, 2004, we recognized natural gas and oil realized losses of $2.0 million and unrealized losses of $4.6 million. The increase in derivative losses for the year ended December 31, 2005 as compared to the year ended December 31, 2004 is due to significant price increases in natural gas and oil during the year ended December 31, 2005, an increase in production volumes covered under derivative arrangements during the year ended December 31, 2005 and differences in the accounting treatment of derivative arrangements during the first seven months of 2004 as compared to subsequent periods. Derivative arrangements for production prior to our July 2004 financial restructuring were designated as hedges under SFAS No 133; therefore, realized gains and losses were recorded as natural gas and oil sales and unrealized gains and losses were not reported in earnings. Subsequent to our July 2004 restructuring, we did not designate any of our derivative arrangements for future production as hedges under SFAS No 133; therefore, changes in fair market value and realized losses related to those derivative arrangements are reported in earnings as gain or loss on derivatives.

Interest and other income. Interest and other income for the year ended December 31, 2005 increased $0.4 million, or 176%, to $0.6 million as compared to $0.2 million for the year ended December 31, 2004. The increase was due primarily to gains on the sales of assets during the year ended December 31, 2005.

Interest expense. Interest expense increased $2.5 million, or 15%, to $19.5 million during the year ended December 31, 2005 from $17.0 million for the year ended December 31, 2004. The increase in interest expense during 2005 was due to increased borrowing under our credit facility and the issuance of additional senior notes and senior subordinated notes as interest paid in kind. These increases were partially offset by a decrease in interest rates under our credit facility during the year ended December 31, 2005.

Income tax benefit. We are required to establish a net deferred tax liability or benefit calculated at the applicable federal and state tax rates resulting primarily from financial reporting and income tax reporting basis differences in natural gas and oil properties. Our effective income tax rate of approximately 38.5% reflects the combined federal statutory rate and applicable state taxes. Beginning in 2001, we established a valuation allowance which we increased periodically to reflect the uncertainty about the realization of the deferred tax

asset. During 2005, we increased the valuation allowance of $6.2 million by an additional $9.8 million based on uncertainty surrounding our ability to utilize the entire balance of our deferred tax assets based on an analyses of whether we are more likely than not to receive such a benefit and if so, to what extent.

Net loss. Due to the factors described above, we recorded a net loss of $27.8 million for the year ended December 31, 2005 compared to a net loss of $36.3 million for the year ended December 31, 2004.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Revenues. Revenues for the year ended December 31, 2004 increased $3.8 million, or 8%, to $50.7 million as compared to $47.0 million for the year ended December 31, 2003. This increase was due primarily to increases in the prices received for oil, natural gas (net of hedging losses) and NGLs of 37%, 14% and 27%, respectively, and a 12% increase in NGL production, which was partially offset by decreases in natural gas and oil production of 21% and 9%, respectively.

The average sales prices received for oil, natural gas and NGLs for the year ended December 31, 2004 were $40.66 per Bbl, $4.27 per Mcf and $27.15 per Bbl, respectively, as compared to average sales prices for oil, natural gas and NGLs for the year ended December 31, 2003 of $29.60 per Bbl, $3.75 per Mcf and $21.37 per Bbl, respectively. The average sales prices received for natural gas during the year ended December 31, 2004 are net of natural gas hedging losses of $1.66 per Mcf. The average sales prices received during the year ended December 31, 2003 are net of natural gas and oil hedging losses of $0.54 per Bbl and $1.77 per Mcf, respectively.

The decreases of 9% in oil production and 21% in natural gas production during the year ended December 31, 2004 were due to several factors, including weather, repairs, natural production declines, particularly in south Texas, and curtailment of capital expenditures during late 2003 and 2004 due to liquidity constraints, which prevented us from offsetting natural production declines with new production.

The 12% increase in NGL production during the year ended December 31, 2004 was due primarily to the completion of several new wells in Texas during mid to late 2004.

Lease operating expenses. Lease operating expenses for the year ended December 31, 2004 increased $0.1 million, or 1%, to $12.0 million as compared to $11.9 million for the year ended December 31, 2003 and increased 19% to $1.25 per Mcfe ($7.49 per Boe) for the year ended December 31, 2004 from $1.05 per Mcfe ($6.32 per Boe) for the year ended December 31, 2003. The increase on a per-Mcfe (Boe) basis is due to a 15% decrease in production during the year ended December 31, 2004 as compared to the year ended December 31, 2003.

Production and ad valorem taxes. Production and ad valorem taxes for the year ended December 31, 2004 decreased $1.2 million, or 28%, to $3.1 million for the year ended December 31, 2004 from $4.3 million during 2003 and on a Mcfe (Boe) basis, decreased 16% to $0.32 per Mcfe ($1.93 per Boe) during 2004 from $0.38 per Mcfe ($2.28 per Boe) during the year ended December 31, 2003. This decrease was primarily attributable to current and retroactive exemptions for high-cost natural gas granted by the State of Texas during the year ended December 31, 2004. Additionally, we experienced increased sales on certain Oklahoma production, which is exempt from Oklahoma severance tax.

General and administrative expenses. G&A for the year ended December 31, 2004 decreased $2.1 million, or 20%, to $8.3 million as compared to $10.4 million for the year ended December 31, 2003. On a Mcfe (Boe) basis, G&A decreased 6% to $0.86 per Mcfe ($5.15 per Boe) during the year ended December 31, 2004 from $0.92 per Mcfe ($5.51 per Boe) for the year ended December 31, 2003. The decrease in G&A was due primarily to decreases of $1.0 million in employee related costs due to staff attrition and employee terminations during the year ended December 31, 2004 and a $1.2 million reduction in franchise taxes resulting from the application of a credit from the overpayment of franchise taxes in 2002 and a decrease in Louisiana franchise taxes due primarily to our 2004 financial restructuring.

Exploration expenses. Exploration expenses for the year ended December 31, 2004 decreased $4.8 million, or 85%, to $0.9 million as compared to $5.6 million for the year ended December 31, 2003. The decrease in exploration expenses was due primarily to a decrease in dry hole costs. During 2003, we expensed $0.5 million on unsuccessful exploratory drilling projects. During 2002 and 2003, we incurred $4.7 million in capitalized exploration costs on drilling a deep exploratory well in our New Taiton field in south Texas. During 2003, the well was determined to be unsuccessful and the capitalized costs were expensed as exploration expense.

Depreciation, depletion and amortization. DD&A for the year ended December 31, 2004 increased $9.7 million, or 45%, to $31.2 million from $21.5 million for the year ended December 31, 2003 and increased 70% on a Mcfe (Boe) basis to $3.24 per Mcfe ($19.44 per Boe) during the year ended December 31, 2004 from $1.90 per Mcfe ($11.42 per Boe) during the year ended December 31, 2003. The increase in DD&A during the year ended December 31, 2004 was due to a 37% decline in proved reserves as of December 31, 2004 as compared to the proved reserves as of December 31, 2003, see “—Overview—Reserve Write Down” above.

Property impairments. Property impairments for the year ended December 31, 2004 increased $16.9 million, or 445%, to $20.7 million as compared to $3.8 million for the year ended December 31, 2003. Property impairments for the year ended December 31, 2004 increased due primarily to a significant downward revision in reserves on our New Taiton field in Texas at year-end 2004, which resulted in a property impairment of $20.3 million. During the year ended December 31, 2003, we recorded impairments primarily on our Manilla Village field in Louisiana due to a downward revision in reserves, which resulted in a $3.7 million property impairment.

Loss on derivatives. During July 2004 and subsequent periods, we entered into new derivative arrangements, which were not designated as hedges under SFAS No 133. Therefore, changes in fair market value and realized losses related to these new derivative arrangements are required to be reported in current earnings as a derivative loss. During the year ended December 31, 2004, we recorded $2.0 million in realized losses and $4.6 million in unrealized losses. In prior periods, all derivative arrangements were designated as hedges and realized gains and losses on derivative arrangements were recognized in natural gas and oil sales; therefore, no derivative gain or loss amounts were recognized as a derivative loss in such periods.

Interest and other income. Interest and other income for the year ended December 31, 2004 increased $0.2 million to $0.2 million for the year ended December 31, 2004. The increase was due primarily to gains on the sales of assets during the year ended December 31, 2004.

Interest expense. Interest expense for the year ended December 31, 2004 increased $3.3 million, or 24%, to $17.0 million from $13.7 million for the year ended December 31, 2003. The increase in interest expense was due to an increase in outstanding indebtedness during 2004 as a result of our July 2004 financial restructuring in which we issued our senior notes and senior subordinated notes in exchange for our old senior notes and senior subordinated notes, including all accrued and unpaid interest thereon. In addition, we did not incur indebtedness under our old senior notes until mid-2003 and accrued interest on those notes for only five months in 2003.

Income tax benefit. We are required to establish a net deferred tax liability calculated at the applicable federal and state tax rates resulting primarily from financial reporting and income tax reporting basis differences in natural gas and oil properties. Beginning in 2001, we established a valuation allowance which we increased periodically to reflect the uncertainty about the realization of the deferred tax asset. In 2003, we increased the valuation allowance of $0.4 million by an additional $0.6 million and during 2004, we increased the valuation allowance by an additional $5.2 million, resulting in a valuation allowance of $6.2 million as of December 31, 2004. The increases in the valuation allowance are based on uncertainty surrounding our ability to utilize the entire balance of our deferred tax assets based on an analysis of whether we are more likely than not to receive such a benefit and, if so, to what extent.

Net loss. Due to the factors described above, we recorded a net loss of $36.3 million for the year ended December 31, 2004 compared to a net loss of $15.4 million for the year ended December 31, 2003.

Liquidity and Capital Resources

Overview

Virtually all of our exploration expenditures and a significant portion of our development expenditures are discretionary expenditures that are made based on current economic conditions and expected future natural gas and oil prices. We make capital expenditures to develop existing natural gas and oil reserves as well as to acquire additional reserves through exploration or acquisition. We operate substantially all of our properties, which gives us significant flexibility in the timing of making capital expenditures on these properties. We may also choose not to participate in capital expenditures on properties operated by others. This flexibility allows us to adjust our annual exploration and development capital expenditure levels according to liquidity and the other sources of operating capital. When we determine that a project involves more risk than we can accept alone or more capital than is commercially prudent to commit, such as certain of our exploration projects, we may take on partners. Historically, we have financed, and we currently finance, our exploration and development programs with net cash provided by operating activities and borrowings under our credit facility. However, as of October 20, 2006, we had $1.6 million available for additional borrowings under our revolving credit facility and $13.6 million available for additional borrowings under our acquisition facility. Therefore, prior to the consummation of this offering and the application of the net proceeds thereof, we are limited in our ability to use our credit facility and must rely almost entirely on our cash flow from operations to meet our additional capital expenditure requirements.

Our cash flows from operating activities are significantly affected by changes in natural gas and oil prices. Accordingly, our cash flows from operating activities would be significantly reduced by lower natural gas and oil prices, which would also reduce our exploration and development capital expenditure levels. Lower natural gas and oil prices may also reduce our borrowing base under our credit facility which would further reduce our ability to obtain funds. However, in an effort to minimize fluctuations in our cash flows and to reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we enter into derivative arrangements for a portion of our natural gas and oil production as further discussed under “—Qualitative and Quantitative Disclosures about Market Risk—Commodity Price Risk.”

Upon consummation of this offering, the application of the net proceeds therefrom, the Recapitalization and the Incentive Issuance, we believe that the cash we generate from operations and availability under our credit facility will be sufficient to satisfy our obligations through December 31, 2007. Our capital expenditure budget for 2006 is approximately $80.3 million, of which $59.7 million is targeted for drilling and workover and $17.8 million is targeted for leasehold acquisitions. Approximately 41% of our 2006 capital expenditure budget is allocated to acquisition, exploration and development of unconventional shale gas properties, and approximately 59% is allocated to exploration and development of our conventional resource properties, including our tight gas sands properties. Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, natural gas and oil prices, industry conditions, participation by other working interest owners and the prices and availability of drilling rigs and other oilfield goods and services. The following table provides certain information about our 2006 capital expenditure budget:


Area	Drilling and Workover		Land		Equipment and Maintenance		Seismic		Total		% of Total
	(dollars in thousands)
Unconventional shale gas:
Texas	$	6,272	$	10,434	$	—	$	872	$	17,578	21.9%
Oklahoma		8,025		1,268		—		—		9,293	11.6%
Appalachian region		3,734		2,292		—		25		6,051	7.5%

Subtotal		18,031		13,994		—		897		32,922	41.0%
East Texas		20,384		1,036		—		102		21,522	26.8%
South Texas		15,960		2,108		—		253		18,321	22.8%
Other		5,293		703		1,512		—		7,508	9.4%

Total	$	59,668	$	17,841	$	1,512	$	1,252	$	80,273	100.0%

% of Total		74.3%		22.2%		1.9%		1.6%		100.0%

Cash flows

Operating activities. For the six months ended June 30, 2006, net cash provided by operating activities increased $3.6 million, or 25%, to $18.3 million as compared to $14.7 million of net cash provided by operating activities for the six months ended June 30, 2005. This increase was due primarily to changes in assets and liabilities providing $2.7 million in cash for the six months ended June 30, 2006 as compared to changes in assets and liabilities using $0.7 million in cash for the six months ended June 30, 2005. The changes in assets and liabilities for the six months ended June 30, 2006 provided cash due primarily to an increase in trade payables and accrued liabilities resulting from increased capital expenditures and a decrease in natural gas and oil receivables resulting from declining natural gas and oil sales. These increases in cash were partially offset by decreases in cash due to an increase in joint interest receivables resulting from increased capital expenditures and increased outside ownership participation during the first six months of 2006, an increase in other assets due primarily to capitalization of deferred costs associated with this offering and a decrease in natural gas and oil revenue payables resulting from decreased natural gas sales during June of 2006. The changes in assets and liabilities for the six months ended June 30, 2005 used cash primarily for the payment of trade payables.

For the year ended December 31, 2005, net cash provided by operating activities increased $14.1 million, or 81%, to $31.5 million as compared to $17.4 million of net cash provided by operating activities for the year ended December 31, 2004. This increase was due primarily to an increase of $4.4 million in total revenues net of expenses (adjusted for non-cash items) for the year ended December 31, 2005 as compared to the year ended December 31, 2004, as well as to changes in operating assets and liabilities providing $1.7 million of cash for operating activities during the year ended December 31, 2005 as compared to $8.0 million of cash used for operating activities for the year ended December 31, 2004. The increase in total revenues net of expenses for the year ended December 31, 2005 resulted primarily from increased revenues of $22.9 million, partially offset by increased realized derivative losses of $10.6 million, increased exploration expenses of $2.6 million and increased interest expense of $1.2 million. Changes in operating assets and liabilities for the year ended December 31, 2005 provided $1.7 million of cash due primarily to an increase in trade payables and accrued liabilities resulting from increased capital expenditures during the year as compared to $8.0 million of cash used during the year ended December 31, 2004, primarily for the payment of trade payables that had not been paid during the prior year due to liquidity constraints.

For the year ended December 31, 2004, net cash provided by operating activities increased $0.4 million, or 3%, to $17.4 million compared to $17.0 million of net cash provided by operating activities for the year ended December 31, 2003. We used $2.2 million of cash for interest expense for the year ended December 31, 2004 as compared to $13.0 million of cash used for interest expense for the year ended December 31, 2003. The reduction in cash used for interest expense for the year ended December 31, 2004 was primarily attributable to our July 2004 restructuring which allowed us to pay interest on our senior notes and senior subordinated notes in the form of additional notes instead of in cash. Additionally, total revenues net of total expenses (adjusted for non-cash items) increased $11.9 million for the year ended December 31, 2005 as compared the year ended December 31, 2004. The increase in cash was partially offset by a reduction in cash for changes in operating assets and liabilities using $8.0 million of cash for operating activities during the year ended December 31, 2004 compared to $14.2 million of cash provided by operating activities for the year ended December 31, 2003. Cash was used during the year ended December 31, 2004 primarily for the payment of trade payables that had not been paid during the year ended December 31, 2003 due to liquidity constraints which contributed to the $14.3 million of cash provided during the year ended December 31, 2003.

Investing Activities. Substantially all of our investing activities involve capital expenditures. For the six months ended June 30, 2006, net cash used in investing increased $19.2 million, or 111%, to $36.5 million as compared to $17.3 million of net cash used in investing activities for the six months ended June 30, 2005. This increase was due primarily to an increase in capital expenditures of $20.3 million, or 124%, to $36.6 million for the six months ended June 30, 2006 compared to capital expenditures of $16.3 million for the six months ended June 30, 2005, as further described below. Additionally, we used $1.2 million of cash during the six months ended June 30, 2005 to acquire all of the outstanding capital stock of Dyne Exploration Company.

For the year ended December 31, 2005, net cash used in investing activities increased $12.4 million, or 55%, to $35.0 million as compared to $22.6 million of net cash used in investing activities for the year ended December 31, 2004. This increase was due primarily to an increase in capital expenditures of $11.6 million, or 50%, to $34.6 million for the year ended December 31, 2005 compared to capital expenditures of $23.0 million for the year ended December 31, 2004, as further described below. Additionally, we used $1.2 million of cash during the year ended December 31, 2005 to acquire all of the outstanding capital stock of Dyne Exploration Company.

For the year ended December 31, 2004, net cash used in investing activities decreased $16.5 million, or 42%, to $22.6 million as compared $39.1 million of net cash used in investing activities for the year ended December 31, 2003. The decrease was due primarily to a decrease in capital expenditures of $16.1 million, or 41%, to $23.0 million for the year ended December 31, 2004 as compared to $39.1 million of capital expenditures for the year ended December 31, 2003, as further described below.

The following table summarizes the major components of capital expenditures for the following periods (in thousands):


	Year Ended December 31,						Six Months Ended June 30,
	2003		2004		2005		2005		2006
Unproved property acquisitions	$	127	$	1,045	$	5,454	$	908	$	9,116
Proved property acquisitions		1,410		449		1,748		382		46
Exploration activities		319		3,725		5,370		2,822		10,671
Development activities		36,489		17,724		21,820		12,125		16,628
Other property		776		42		196		59		93

Total	$	39,121	$	22,985	$	34,588	$	16,296	$	36,554

Financing Activities. For the six months ended June 30, 2006, net cash provided by financing activities increased $13.9 million, or 305%, to $18.4 million as compared to $4.6 million of net cash provided by financing activities for the six months ended June 30, 2005. This increase was primarily the result of borrowings under our credit facility during the six months ended June 30, 2006.

For the year ended December 31, 2005, net cash provided by financing activities increased $2.5 million, or 149%, to $4.1 million as compared to $1.7 million of net cash provided by financing activities for the year ended December 31, 2004. The increase was due primarily to an increase in borrowings under our credit facility during the year ended December 31, 2005.

For the year ended December 31, 2004, net cash provided by financing activities decreased $24.6 million, or 94%, to $1.7 million as compared to $26.2 million of net cash provided by financing activities for the year ended December 31, 2003. The decrease was due primarily to decreased borrowings under our credit facility and our senior notes during the year ended December 31, 2004. We had borrowings under our credit facility of $2.4 million during the year ended December 31, 2004 as compared to borrowing under our credit facility and our senior notes of $4.4 million and $24.0 million, respectively, during the year ended December 31, 2003. Additionally, we used $2.1 million of cash to pay accrued but unpaid dividends on our Series B preferred stock in connection with its mandatory conversion to common stock in August 2003.

Contractual Obligations and Commitments

The following is a summary of our contractual obligations and commitments as of December 31, 2005:


	Total		Payments due by Period
	Total		Less than 1 Year		1 – 3 Years		3 – 5 Years		More than 5 Years
	(in thousands)
Credit facility (1)	$	64,274	$	3,798	$	7,596	$	52,880	$	—
Senior notes (2)		64,259		—		—		64,259		—
Senior subordinated notes (2)		166,004		—		—		166,004		—
Operating leases		3,237		239		896		870		1,232
Accrued abandonment costs (3)		10,570		517		3,743		776		5,534
Fair value of derivatives (4)		28,512		11,469		14,925		2,118		—
Series A preferred stock accrued dividends (5)		12,865		—		—		—		12,865

Total	$	349,721	$	16,023	$	27,160	$	286,907	$	19,631

(1)

Represents required payments on outstanding borrowings plus estimated interest through maturity. See “Use of Proceeds.” Interest payments on floating-rate debt were estimated using December 31, 2005 interest rates applicable to the floating-rate debt. Actual payments will fluctuate as interest rates fluctuate.

(2)

Represents the outstanding principal amount of the notes plus estimated interest thereon through maturity. All outstanding principal and accrued interest are expected to be repaid or exchanged for common stock in connection with this offering and the Recapitalization. See “Use of Proceeds” and “Recapitalization and Incentive Issuance.” Interest is payable semi-annually in kind by the issuance of new notes. The issuances of new notes for payment of interest in kind are excluded from the above table until the notes mature and are included at the maturity period. Assumes no extension of the maturity dates of the notes.

(3)	Accrued abandonment costs are based on estimates. The timing and amounts of cash settlements may vary from the amounts presented.

(4)

Commitments under our natural gas, oil and interest rate derivative instruments are based on market values, which fluctuate month to month. Actual cash settlements will be calculated based on applicable NYMEX natural gas and oil prices at the time of settlement and may vary significantly from the amounts presented. See “—Quantitative and Quantitative Disclosures about Market Risk.”

(5)	Cash payments for preferred stock accrued dividends are at our option or at the option of the holder in the event of a change of control.

On a pro forma basis, after giving effect to the Recapitalization, the Incentive Issuance, this offering and the application of the use of proceeds therefrom to repay long-term debt, as described in “Use of Proceeds” and “Recapitalization and Incentive Issuance,” our contractual obligations and commitments as of December 31, 2005 would have consisted of the following:


	Total		Payments due by Period
	Total		Less than 1 Year		1 – 3 Years		3 – 5 Years		More than 5 Years
	(in thousands)
Credit facility (1)	$		$		$		$		$	—
Operating leases		3,237		239		896		870		1,232
Accrued abandonment costs (2)		10,570		517		3,743		776		5,534
Fair value of derivatives (3)		28,512		11,469		14,925		2,118		—

Total	$		$		$		$		$

(1)	Reflects repayment of $ million of indebtedness with a portion of the net proceeds of this offering. See “Use of Proceeds.”

(2)	Accrued abandonment costs are based on estimates. The timing and amounts of cash settlements may vary from the amounts presented.

(3)

Credit Facility

On July 27, 2004, we completed a financial restructuring that permitted the operating subsidiaries of Ascent Energy Inc., as borrowers, to enter into a new credit facility with a new group of lenders. In connection with our financial restructuring, Ascent Energy Inc. reorganized as a holding company by transferring all of our natural gas and oil operations to certain operating subsidiaries of Ascent Energy Inc. Our Parent and each operating subsidiary of Ascent Energy Inc. are borrowers under our credit facility. Ascent Energy Inc. is not a borrower under our credit facility, but is a party thereto and subject to certain restrictions thereunder. The stock of Ascent Oil and Gas Inc., which is the direct wholly owned subsidiary of Ascent Energy Inc., and substantially all of the assets of the operating subsidiaries of Ascent Energy Inc., are pledged to our bank lenders to secure the obligations of the borrowers under our credit facility. If an event of a default were to occur under our credit facility, our lenders would have no recourse to Ascent Energy Inc., other than to the stock of Ascent Oil and Gas Inc., but would have recourse to all of our revenue generating assets.

Our credit facility provides for loans to finance our future acquisition opportunities and to assist in meeting our working capital requirements. Our lenders periodically re-determine our borrowing base by applying criteria similar to those used with similarly situated natural gas and oil borrowers.

Subject to our borrowing base (currently set at $80.0 million), our credit facility provides for borrowings of up to $115.0 million, which includes a $100.0 million revolving credit facility and a $15.0 million acquisition facility. Borrowings under our revolving credit facility mature on November 1, 2009. As of October 20, 2006, we had $1.6 million available for additional borrowings under our revolving credit facility and $13.6 million available for additional borrowings under our acquisition facility.

Our credit facility provides for interest periods of one, two, three or six months for LIBOR loans. We can also elect to pay interest at a base rate calculated by reference to the higher of the federal funds rate or Fortis Bank’s prime rate. In the case of London Interbank Offered Rate, or LIBOR, loans or base rate loans, we are required to pay an additional interest rate margin that varies with the aggregate amount of loans and letters of credit outstanding under the line of credit. Our interest rate on our outstanding borrowings as of June 30, 2006 was 8.62%.

Under our acquisition facility, we are permitted to borrow up to 70% of the net discounted present value of proved reserves that we acquire. Advances under the acquisition facility are required to be repaid on the later of the six-month anniversary of the advance or the three-month anniversary of the date of the first borrowing base redetermination following the advance and may be repaid in cash or converted to borrowings under our credit facility. If a conversion of an acquisition advance at its maturity would exceed our borrowing base, we are permitted to convert the amount in excess of our borrowing base to a term loan.

Our credit facility contains various covenants that, among other restrictions, limit the ability of Ascent Energy Inc., its operating subsidiaries and our Parent to: grant or assume liens; enter into derivative arrangements above certain limitations; incur indebtedness; change the nature of our business; or enter into agreements to merge or acquire assets. Our credit facility also limits the ability of the operating subsidiaries of Ascent Energy Inc. and our Parent to allow a change of control; engage in transactions with affiliates; sell assets; make loans or advances to third parties; make investments; create subsidiaries or amend their organizational documents. In addition, our credit facility prohibits the operating subsidiaries of Ascent Energy Inc. and our Parent from

making cash dividends, cash redemptions or cash distributions unless certain financial tests are satisfied, the then outstanding borrowings do not exceed our borrowing base and no default under our credit facility exists or is anticipated as a result of payment of the dividend, redemption or distribution.

Additionally, our credit agreement requires that as of the last day of any fiscal quarter:

•

we have a consolidated tangible net worth of at least $170.0 million;

•

our ratio of current assets (which includes remaining availability under our credit facility) to current liabilities is 1.0 to 1.0;

•

our ratio of total debt to EBITDAX for the immediately preceding four fiscal quarters be not greater than 2.5 to 1.0; and

•

our ratio of EBITDAX to an amount equal to cash interest expense plus dividends, if any, from our direct subsidiary for the immediately preceding four fiscal quarters be at least 2.5 to 1.0.

EBITDAX is defined in our credit facility as earnings before interest expense; income tax (expense) benefit; depreciation, depletion and amortization; exploration expenses; any other item expensed under successful efforts accounting and capitalized under full cost accounting, such as property impairments; and any other non-cash items deducted at arriving in earnings, such as non-cash hedging and derivative losses and cumulative effect of change in accounting principle. As of June 30, 2006, we were in compliance with all of the covenants under our credit facility.

Our credit facility limits the ability of Ascent Energy Inc. to modify or amend the terms of the senior notes or the indenture governing the senior subordinated notes generally and prohibits Ascent Energy Inc. from amending or modifying the senior notes or the indenture governing the senior subordinated notes to provide for cash interest payments or a maturity date that is earlier than 90 days after the maturity date of our credit facility. Ascent Energy Inc. is also prohibited from engaging in any activity other than in connection with the ownership of its shares of stock in Ascent Oil and Gas Inc., but it may form and own additional subsidiaries which would not be restricted in the nature of their businesses.

Our Parent will remain a borrower under our credit facility and therefore will be subject to the same covenants and restrictions thereunder after it becomes a wholly owned subsidiary of Ascent Energy Inc. pursuant to the Parent Merger.

Recapitalization and Incentive Issuance

Upon the consummation of this offering, the application of the net proceeds of this offering as described in “Use of Proceeds” and the consummation of the Recapitalization and the Incentive Issuance, all of our senior notes and senior subordinated notes will be extinguished and our outstanding long-term indebtedness will consist solely of approximately $ million of borrowings under our credit facility. In connection with this offering and the Recapitalization, we intend to repay in cash or exchange for common stock all indebtedness outstanding under our senior notes and our senior subordinated notes and to repay $ million of borrowings outstanding under our credit facility. We also expect that all of our outstanding Series A preferred stock (including accrued but unpaid dividends thereon) and all warrants to purchase shares of our common stock (other than the Merger Warrants) will be exchanged for an aggregate of shares of our common stock at a ratio of shares of our common stock for each $1,000 of Series A preferred stock (including accrued but unpaid dividends thereon). All such warrants to purchase shares of our common stock are substantially out-of-the-money and will be cancelled in connection with the Preferred Exchange. We expect to pay an aggregate of $ in exchange for the cancellation of Merger Warrants to purchase shares of our common stock at an exercise price of $ per share and that Merger Warrants to purchase shares of our common stock at an exercise price of $ per share will remain outstanding until January 14, 2007, unless earlier exercised by the holders thereof. The Jefferies Investors and The TCW Funds are the principal holders of our senior notes, our senior subordinated notes, our Series A preferred stock and our warrants and will receive cash and shares of our

common stock in this offering and the Recapitalization. Our executive officers are expected to participate in the Incentive Issuance and to receive a portion of the net proceeds of this offering and shares of our common stock in connection with this offering and the Incentive Issuance. See “Management—Termination of 2005 Incentive Plan,” “Related Party Transactions—Termination of 2005 Incentive Plan” and “Principal Stockholders.”

Senior Notes. On November 9, 2005, we issued approximately $33.5 million aggregate principal amount of our 16% senior notes due February 1, 2010 (or such later date as automatically extended in accordance with the terms of the notes, but in no event later than February 1, 2015) in exchange for all then-outstanding principal and accrued but unpaid interest on our 16% senior notes due October 26, 2007, which we refer to as the old senior notes. The old senior notes were issued on July 27, 2004 in connection with our financial restructuring in exchange for all then-outstanding principal and accrued but unpaid interest on certain promissory notes that we issued during 2003 for short-term liquidity needs.

The senior notes are senior unsecured obligations and are not guaranteed by any of our subsidiaries. The senior notes are effectively subordinated to all indebtedness and other liabilities of our subsidiaries, including indebtedness under our credit facility. Interest on the senior notes accrues at a rate of 16% per annum and is payable semi-annually, in the form of additional senior notes. On April 30, 2006, we paid the accrued interest on the senior notes by issuing an additional $2.6 million in senior notes.

During each of the years 2006 through 2010, each holder of senior notes has the right, during the 30-day period beginning on September 1 of each such year, to deliver written notice to us rejecting any further extension of the maturity date of such holder’s senior notes. If the holder fails to deliver such notice on a timely basis, the maturity date of such holder’s senior notes will be automatically extended by one calendar year from the then applicable maturity date. Any senior notes that are the subject of a timely delivered notice will become due and payable at the then applicable maturity date. The senior notes currently mature on February 1, 2011.

Senior Subordinated Notes. On November 9, 2005, we issued approximately $99.6 million aggregate principal amount of our 11³/4% senior subordinated notes due May 1, 2010 (or such later date as automatically extended in accordance with the terms of the notes, but in no event later than May 1, 2015) in exchange for all then-outstanding principal and accrued but unpaid interest on our 11³/4% senior subordinated notes due 2008, which we refer to as the old senior subordinated notes. The old senior subordinated notes were issued on July 27, 2004 in connection with our financial restructuring in exchange for all then-outstanding principal and accrued but unpaid interest on our 11³/4% Series A senior notes due 2006 which were originally issued on June 28, 2001 in connection with our acquisition of our south Texas properties.

The senior subordinated notes are subordinate in right of payment to the senior notes and are effectively subordinated to all indebtedness and other liabilities of our subsidiaries, including indebtedness under our credit facility. Interest on the senior subordinated notes accrues at a rate of 11³/4% per annum and is payable semi- annually in the form of additional senior subordinated notes. On April 30, 2006, we paid the accrued interest on the senior subordinated notes by issuing an additional $5.6 million in senior subordinated notes.

During each of the years 2006 through 2010, each holder of senior subordinated notes has the right, during a 30-day period beginning on July 15 of each such year, to deliver written notice to us rejecting any further extension of the maturity date of such holder’s senior subordinated notes. If the holder fails to deliver such notice on a timely basis, the maturity date of such holder’s senior subordinated notes will be automatically extended by one calendar year from the then applicable maturity date. Any senior subordinated notes that are the subject of a timely delivered notice will become due and payable at the then applicable maturity date. The senior subordinated notes currently mature on May 1, 2011.

8% Series A Preferred Stock and Warrants. As of June 30, 2006, we had outstanding 41,100 shares of our 8% Series A preferred stock, par value $0.001 per share, and warrants to purchase an additional 3,000 shares of our Series A preferred stock at an exercise price of $333.33 per share. Dividends on our Series A preferred stock accrue at the rate of 8% per annum. Accrued but unpaid dividends do not bear interest. Our board of directors has

never declared or paid any dividends on the outstanding shares of Series A preferred stock. Each outstanding share of Series A preferred stock, and each share issuable upon exercise of the warrants described above, was or will be issued with a warrant to purchase 191.943 shares of our common stock at an exercise price of $5.21 per share (exercise price will be adjusted to $ per share in connection with the reverse stock split). As of June 30, 2006, we had outstanding warrants to purchase 7,888,858 shares of our common stock. On a pro forma basis, assuming the exercise of all outstanding warrants to purchase shares of our Series A preferred stock and giving effect to the reverse stock split, we would have had outstanding warrants to purchase shares of our common stock as of June 30, 2006.

Inflation

Historically, general inflationary trends have not had a material effect on our operating revenue or expenses. However, we have experienced inflationary pressure on technical staff compensation and the cost of oilfield services and equipment due to the increase in drilling activity and competitive pressures from higher natural gas and oil prices in recent years.

Quantitative and Qualitative Disclosures about Market Risk

Commodity price risk. Our revenue, profitability and future rate of growth substantially depend upon market prices of natural gas and oil, which fluctuate widely. Natural gas and oil price decline and volatility could adversely affect our revenue, net cash provided by operating activities and profitability. For example, assuming a 10% decline in realized natural gas and oil prices, our net loss attributable to common stock for the six months ended June 30, 2006 would have increased by approximately 49% from a loss of $7.6 million to a loss of $11.4 million. If the costs and expenses of operating our properties had increased by 10% for the six months ended June 30, 2006, our net loss attributable to common stock would have increased by approximately 8% from a loss of $7.6 million to a loss of $8.3 million.

We have entered into derivative arrangements with respect to portions of our natural gas and oil production to reduce our sensitivity to volatile commodity prices. Our credit facility requires us to enter into derivative instruments covering a minimum of 50% of our production for the three-year period following the effective date of the credit facility, but not in excess of 85% for the 12-month period immediately subsequent to any fiscal quarter, of our forecast proved developed producing reserves. Our management limits the periods covered by derivative instruments to the term of the credit facility. Historically, our derivative arrangements have been puts, price swaps and costless collar agreements. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to price fluctuations. However, derivative arrangements limit the benefit to us of increases in the prices of natural gas and oil sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial price protection against declines in prices. Additionally, these arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our derivative arrangements in light of market conditions, commodity price forecasts, capital spending and debt service requirements. We do not enter into derivative transactions for trading purposes.

Fixed price swaps typically require monthly payments by us (if prices rise) or provide payments to us (if prices fall) based on the difference between the strike price and the agreed-upon average of either New York Mercantile Exchange, or NYMEX, or other widely recognized index prices. Currently, all of our derivative arrangements are settled based on NYMEX pricing.

Collar contracts set a minimum price, or floor, and a maximum price, or ceiling, and provide payments to us if the NYMEX price falls below the floor or require payments by us if the NYMEX price rises above the ceiling.

Puts provide payment to us if the NYMEX price falls below the strike price. If the NYMEX price is above the strike price, we have no payment obligation.

Currently, our natural gas contracts settle using the near-month NYMEX prices for the next to last trading day or the last trading day of the month. Our crude oil contracts settle using the average of the near month closing price for each day of the month.

In connection with our July 2004 financial restructuring, Fortis Energy LLC, an affiliate of one of the underwriters in this offering, assumed our then existing derivative arrangements, which we refer to as the old derivative arrangements, and replaced them with new derivative arrangements. As of that date, we had a $4.0 million liability under our old derivative arrangements representing a deferred loss which we recognized on our balance sheet as a current asset and a corresponding derivative liability. The deferred loss was amortized monthly into earnings over the related contract periods, which were August 2004 through December 2004, and settlement of the liability will occur monthly through June 2007 as the new derivative arrangements are settled. The old derivative arrangements qualified for hedge accounting treatment under SFAS 133; therefore, amortization of the deferred loss was recognized in natural gas sales.

Our new derivative arrangements are not designated as hedges under SFAS 133; therefore, changes in fair market value and realized gains and losses related to our new derivative arrangements are reported in current earnings.

As of June 30, 2006, the fair market value of our natural gas and oil derivative arrangements was a liability of $30.6 million, which includes the remaining liability of $1.1 million related to the deferred loss on the old derivative arrangements. The fair market values of our derivative arrangements as of June 30, 2006 are reflected on our balance sheet in current assets (fair value of derivatives) in the amount of $0.7 million, in other assets (fair value of derivatives) in the amount of $20,000, in current liabilities (fair value of derivatives) in the amount of $13.2 million and in long-term liabilities (fair value of derivatives) in the amount of $18.1 million.

As of June 30, 2006 our natural gas and oil derivative arrangements were as follows:


Natural Gas (MMBtu)	Quantity	Ceiling		Floor		Fixed Price		Put
2006
July 1, 2006 to October 31, 2006	410,820		—		—	$	7.26		—
July 1, 2006 to October 31, 2006	69,741	$	8.20	$	5.00		—		—
July 1, 2006 to October 31, 2006	139,359		—		—		—	$	5.00
July 1, 2006 to October 31, 2006	503,894	$	8.05	$	6.25		—		—
November 1, 2006 to December 31, 2006	246,986	$	13.65	$	8.00		—		—
November 1, 2006 to December 31, 2006	176,290	$	6.75	$	4.65		—		—
November 1, 2006 to December 31, 2006	92,720	$	10.25	$	5.50		—		—
2007
January 1, 2007 to March 31, 2007	260,100	$	6.75	$	4.65		—		—
January 1, 2007 to June 30, 2007	275,120	$	10.25	$	5.50		—		—
January 1, 2007 to March 31, 2007	315,912	$	13.65	$	8.00		—		—
April 1, 2007 to June 30, 2007	234,780		—		—	$	7.26		—
April 1, 2007 to October 31, 2007	509,999	$	10.95	$	7.00		—		—
July 1, 2007 to December 31, 2007	920,000	$	9.05	$	5.00		—		—
November 1, 2007 to December 31, 2007	78,436	$	13.95	$	8.00		—		—
2008
January 1, 2008 to March 31, 2008	179,230	$	13.95	$	8.00		—		—
January 1, 2008 to December 31, 2008	1,460,000	$	9.05	$	5.00		—		—
April 1, 2008 to October 31, 2008	298,551	$	9.60	$	7.00		—		—
November 1, 2008 to December 31, 2008	56,808	$	12.25	$	8.00		—		—
2009
January 1, 2009 to March 31, 2009	154,402	$	12.25	$	8.00		—		—
January 1, 2009 to June 30, 2009	543,000	$	9.05	$	5.00		—		—
April 1, 2009 to October 31, 2009	647,304	$	8.55	$	6.75		—		—

Total	7,573,452

Oil (Bbls)	Quantity	Ceiling		Floor		Fixed Price		Put
2006
July 1, 2006 to August 31, 2006	3,410	$	60.50	$	50.00		—		—
July 1, 2006 to December 31, 2006	77,675		—		—	$	61.56 to $64.68		—
July 1, 2006 to December 31, 2006	156,400		—		—	$	44.95		—
2007
January 1, 2007 to June 30, 2007	25,010	$	56.50	$	47.00		—		—
January 1, 2007 to June 30, 2007	135,750		—		—	$	44.95		—
January 1, 2007 to December 31, 2007	105,725		—		—	$	64.80 to $65.03		—
July 1, 2007 to December 31, 2007	147,200	$	50.00	$	42.50		—		—
2008
January 1, 2008 to December 31, 2008	255,500	$	50.00	$	42.50		—		—
January 1, 2008 to December 31, 2008	101,960		—		—	$	64.00 to $64.74		—
2009
January 1, 2009 to June 30, 2009	108,600	$	50.00	$	42.50		—		—
January 1, 2009 to October 31, 2009	154,328		—		—	$	63.37 to $63.94		—

Total	1,271,558

We also incur gains and losses on our interest rate derivative instruments. See “—Quantitative and Qualitative Disclosures about Market Risk.”

The following table shows the effect of our natural gas and oil derivative instruments on our consolidated income statements for the periods presented (in thousands):


	Natural Gas and Oil Derivatives Designated as Hedges									Natural Gas and Oil Derivatives Not Designated as Hedges
	Cash Settlements (1)			Amortization (2)			Reduction in Oil and Gas Sales (3)			Cash Settlements (1)			Amortization of Old Derivative Arrangements (4)		Unrealized Gains (Losses)			Derivative Gains (Losses) (5)
2003
1^st Quarter	$	(3,962	)	$	(122	)	$	(4,084	)	$	—		$	—	$	—		$	—
2^nd Quarter		(2,941	)		(122	)		(3,063	)		—			—		—			—
3^rd Quarter		(2,461	)		(122	)		(2,583	)		—			—		—			—
4^th Quarter		(2,213	)		(6	)		(2,219	)		—			—		—			—

Total	$	(11,577	)	$	(372	)	$	(11,949	)	$	—		$	—	$	—		$	—

2004
1^st Quarter	$	(1,645	)	$	—		$	(1,645	)	$	—		$	—	$	—		$	—
2^nd Quarter		(2,168	)		—			(2,168	)		—			—		—			—
3^rd Quarter		(775	)		(1,484	)		(2,259	)		(973	)		411		(7,537	)		(8,099	)
4^th Quarter		—			(2,474	)		(2,474	)		(1,858	)		407		2,946			1,495

Total	$	(4,588	)	$	(3,958	)	$	(8,546	)	$	(2,831	)	$	818	$	(4,591	)	$	(6,604	)

2005
1^st Quarter	$	—		$	—		$	—		$	(1,481	)	$	254	$	(15,062	)	$	(16,289	)
2^nd Quarter		—			—			—			(2,494	)		469		332			(1,693	)
3^rd Quarter		—			—			—			(4,654	)		475		(15,038	)		(19,217	)
4^th Quarter		—			—			—			(4,779	)		332		7,457			3,010

Total	$	—		$	—		$	—		$	(13,408	)	$	1,530	$	(22,311	)	$	(34,189	)

2006
1^st Quarter	$	—		$	—		$	—		$	(2,423	)	$	206	$	(966	)	$	(3,183	)
2^nd Quarter		—			—			—			(2,430	)		339		(1,706	)		(3,797	)

Total	$	—		$	—		$	—		$	(4,853	)	$	545	$	(2,672	)	$	(6,980	)

(1)	Cash settlements of derivative arrangements are included in net cash provided by operating activities.

(2)	Amortization during 2003 relates to premium on oil put options. Amortization during 2004 relates to deferred loss under old derivative arrangements.

(3)	The ineffectiveness of these hedges was tested and determined to be immaterial.

(4)	Amortization relates to cash settlement of old derivative arrangements which qualified as hedges and were expensed in the prior year as a reduction of natural gas and oil sales. The amortization period for settlement of old derivative arrangements extends through June 2007.

(5)

Derivative loss for the year ended December 31, 2005 includes a $34.2 million loss on natural gas and oil derivatives and a $0.4 million gain on interest rate derivatives. Derivative loss for the quarter ended March 31, 2006 includes a $3.2 million loss on natural gas and oil derivatives and a $0.2 million gain on interest rate derivatives. Derivative loss for the quarter ended June 30, 2006 includes a $3.8 million loss on natural gas and oil derivatives and a $0.1 million gain on interest rate derivatives.

Based on NYMEX crude oil futures prices as of June 30, 2006, we would expect to make future cash payments of $21.6 million to settle our crude oil derivative arrangements as they mature. If future prices of natural gas and oil were to decline by 10%, we would expect to make future cash payments under our crude oil

derivative arrangements of $9.9 million, and if future prices were to increase by 10% we would expect to make future cash payments of $32.9 million.

Interest Rate Risk. As of June 30, 2006, we had outstanding $68.2 million of floating-rate debt attributable to borrowings under our credit facility. As a result, our interest expense fluctuates based on changes in short-term interest rates. A hypothetical 10% change in the short-term interest rate (approximately 81 basis points) would have a $0.2 million impact on interest expense and a $0.2 million impact on net loss for the six months ended June 30, 2006.

We enter into derivative transactions to secure a fixed interest rate for a portion of our debt under our credit facility. The primary objective of these transactions is to reduce our exposure to the possibility of rising interest rates during the term of the derivative transactions. We currently use fixed rate interest swaps for these purposes. Fixed rate interest swaps are not designated as hedges; therefore, gains and losses resulting from these derivative arrangements are reported as they occur as derivative loss on our consolidated statements of operations. We do not enter into derivative transactions for trading purposes.

Our fixed rate interest swaps typically provide monthly payments to us (if rates rise) or by us (if rates fall) based on the difference between the strike price and the LIBOR. All of our fixed rate interest swaps are with affiliates of the financial institutions that are parties to our credit facility.

As of June 30, 2006, we had fixed rate interest swaps for $30.0 million per day for the period July 1, 2006 through July 27, 2007 at a fixed rate of 3.98%. For the six months ended June 30, 2006, we had realized gains of $72,000 relating to these swaps, and their fair market value was a net unrealized receivable of $546,000 of which $513,000 was recorded on our balance sheet as a current asset (fair value of derivatives) and $33,000 of which was recorded on our balance sheet as an other asset (fair value of derivatives).

Based on LIBOR as of June 30, 2006, we would expect to receive future cash payments of $0.5 million to settle our fixed rate interest swaps as they mature. If interest rates were to decline by 10%, we would expect to receive future cash payments under these derivative arrangements of $0.4 million, and if interest rates were to increase by 10% we would expect to receive future cash payments under these derivative arrangements of $0.7 million.

BUSINESS AND PROPERTIES

Overview

Since joining us in mid-2003, our senior management team has embarked on a strategy to acquire and develop a risk-balanced inventory of high growth opportunities, predominately in shale gas. In order to implement this strategy, our new management initially devoted a substantial portion of its efforts to improving our operational efficiency and increasing our liquidity. Since 2004, our management has successfully added unconventional shale gas acreage in four large shale gas exploration areas and entered the tight gas areas of the Cotton Valley trend in east Texas.

Based on reserve reports prepared by our independent reserve engineering firms, our total proved reserves as of December 31, 2005 were approximately 106.1 Bcfe (17.7 MMBoe), of which 51.7% were proved developed producing and 10.5% were proved developed non-producing and 60.3% were oil and NGLs. As of September 30, 2006, we had interests in approximately 137,185 net acres, including approximately 113,765 net undeveloped acres. Our average net daily production during September 2006 was approximately 23.9 MMcfe/d (4.0 MBoe/d). As of December 31, 2005 and June 30, 2006, the related PV-10 of our proved reserves was $371.3 million and $340.0 million, respectively. Our 2005 reserve reports do not reflect any reserves attributable to our unconventional shale gas acreage.

Ascent Energy Inc. was incorporated on July 9, 2001 as a wholly owned subsidiary of our Parent to acquire natural gas and oil properties in Louisiana, Texas and Oklahoma. In July 2001, our Parent contributed to Ascent Energy Inc. substantially all of its assets and liabilities which consisted primarily of natural gas and oil properties in Louisiana and Texas. In August 2001, Ascent Energy Inc. acquired Pontotoc Production, Inc. which held primarily natural gas and oil properties in Oklahoma. In connection with that acquisition, Ascent Energy Inc. issued shares of its convertible preferred stock to the former stockholders of Pontotoc Production, Inc. When those shares automatically converted into shares of common stock of Ascent Energy Inc. in August 2003, our Parent’s ownership of Ascent Energy Inc. was reduced to 83% of the outstanding shares of common stock of Ascent Energy Inc. Prior to mid-2003, when our new management team joined us, we focused primarily on the acquisition, exploitation, exploration, development and production of conventional natural gas and oil properties in Louisiana, Texas and Oklahoma.

Our Strengths

Significant Growth Opportunities. We have an attractive inventory of drilling projects, which we believe contains significant production growth opportunities. We believe our approximate two-year inventory of conventional and tight gas drilling projects will generate near-term production growth and cash flow. In addition, we have acquired acreage positions in several unconventional shale gas areas where industry drilling and production activity has increased in the past several years. If our initial unconventional shale gas drilling projects are successful, we expect to increase significantly our long-term reserves, production and drilling inventory. Additionally, we expect to add to our existing acreage position, which will provide additional growth potential.

Our Business Strategy

Operate Substantially All of Our Assets. We serve as the operator of substantially all of our producing properties and intend to continue to do so in the future. Operating control enables us to better control timing and risk as well as the cost of exploration and development drilling and ongoing operations. We believe that in the

competitive market for drilling rigs it is advantageous to be in a position to make longer term commitments to drilling rig operators in order to secure service.

Maintain Financial Flexibility. Following the completion of this offering and our anticipated Recapitalization and Incentive Issuance, we will have increased our equity capital base by over $ million and will have approximately $ million of undrawn availability under our credit facility. We believe that future cash flow and access to the capital markets following this offering will provide us with financial flexibility that both enhances our ability to execute our business plan and allows us to selectively seek and complete acquisitions. We expect to use our commodity price risk management program to protect our ability to execute our capital expenditure program and service our debt. We may also to reduce our existing derivative liability with a portion of the net proceeds of this offering, which should increase our flexibility and could increase our future cash flow.

Seek Acquisitions that Complement Our Exploration and Development Plans. We pursue acquisitions that add efficiency to our existing operations or represent attractive additions to our exploration and development prospect inventory in large, mature producing regions. We direct our acquisitions toward areas with long production histories or areas where we believe significant untapped reserve potential exists. We maintain a disciplined acquisition process to help ensure that acquisitions fit our strategic and financial objectives.

Our Areas of Operation

We operate in Texas, Oklahoma, Louisiana and the Appalachian region. The following table presents descriptive information about our natural gas and oil properties based on our 2005 reserve reports prepared by our independent reserve engineering firms:


Field	Estimated Net Proved Reserves (1) (MMcfe)	Estimated Net Proved Reserves (1) (MBoe)	PV-10 (2) (in thousands)		% Developed
Texas:
La Copita	22,323	3,720	$	72,570	44.9	%
Rosita	2,238	373		8,188	93.3	%
New Taiton	3,191	532		18,378	100.0	%
Other	3,268	545		6,066	36.6	%

Subtotal	31,020	5,170	$	105,202	53.2	%

Oklahoma:
Northeast Fitts	20,870	3,478	$	67,225	82.6	%
Allen	31,238	5,206		103,076	52.7	%
Other	10,726	1,788		34,011	72.1	%

Subtotal	62,834	10,472	$	204,312	66.0	%

Louisiana:
Lake Enfermer	5,546	924	$	32,238	53.6	%
Boutte	4,947	825		23,283	100.0	%
Other	1,742	290		6,268	10.6	%

Subtotal	12,235	2,039		61,789	66.2	%

Total	106,089	17,681	$	371,303	62.3	%

(1)	In accordance with SEC requirements, our estimated net proved reserves were determined using year-end posted prices for natural gas and oil:


Natural gas (per MMBtu)	$	8.17
Oil (per Bbl)	$	57.75

(2)

future net cash flows on a pre-tax basis. In order to calculate our natural gas reserve estimates, the posted

natural gas prices in note 1 above were adjusted lease by lease to reflect adjustments for energy composition, quality, gathering and transportation fees, marketing fees and regional price differentials. In order to calculate our oil reserve estimates, the posted prices in note 1 above were adjusted lease by lease to reflect adjustments for gravity, crude quality, transportation fees, marketing fees and regional price differentials. These adjustments to the year-end posted prices resulted in the following average prices:


	Year Ended December 31, 2005		Six Months Ended June 30, 2006
Natural gas (per MMBtu)	$	8.76	$	6.02
Oil and NGLs (per Bbl)		57.94		70.33


	Year Ended December 31, 2005
	(in thousands)
Future cash inflows	$	986,683
Less: Future production costs		(276,962	)
Less: Future development costs		(56,042	)

Future net cash flows		653,679
Less: 10% discount factor		(282,376	)

PV-10		371,303
Less: Undiscounted income taxes		(179,732	)
Plus: 10% discount factor		89,357

Discounted income taxes		(90,375	)

Standardized measure of discounted future net cash flows	$	280,928

As of June 30, 2006, our estimated net proved reserves were 100.8 Bcfe (16.8 MMBoe), which was determined using June 30, 2006 posted prices, in accordance with SEC guidelines of $6.04 per MMBtu of natural gas and $70.50 per Bbl of oil and includes 61.5 Bcfe (10.3 MMBoe) attributable to our Oklahoma properties, 27.7 Bcfe (4.6 MMBoe) attributable to our Texas properties and 11.6 Bcfe (1.9 MMBoe) attributable to our Louisiana properties. Our reserve estimates are based on reserve reports prepared by our independent reserve engineers. See “Business and Properties—Proved Reserves.” The standardized measure of discounted future net cash flows from our total proved natural gas and oil reserves as of December 31, 2005 was $280.9 million.

Operating Area Production

The following table sets forth our production for the areas and periods presented:


Operating Area	Total Production for Year Ended December 31, 2005 (MMcfe)	Total Production for Year Ended December 31, 2005 (MBoe)	Total Production for the Nine Months Ended September 30, 2006 (MMcfe)	Total Production for the Nine Months Ended September 30, 2006 (MBoe)	September 2006 Average Net Daily Production (Mcfe/d)	September 2006 Average Net Daily Production (Boe)
Texas:
Cotton Valley trend	22	4	455	76	1,733	289
Vicksburg trend	2,578	429	1,722	287	6,316	1,053
Wilcox trend	1,324	221	911	152	3,446	574

Subtotal	3,924	654	3,088	515	11,495	1,916

Oklahoma:
Northeast Fitts	1,650	275	1,313	219	4,613	769
Allen Anticline	1,661	277	1,122	187	3,816	636
Other	328	55	263	44	1,031	172

Subtotal	3,639	607	2,698	450	9,460	1,577

Louisiana:
Lake Enfermer	631	105	432	72	1,518	253
Boutte	580	97	347	58	1,047	174
Other	51	8	40	7	120	20

ASCENT ENERGY INC S-1/A