Edgar Filing: GULFPORT ENERGY CORP

FINAL PROSPECTUS

Filed pursuant to Rule 424(b)(1)
SEC File No. 333-133109

Prospectus

6,050,000 Shares

LOGO

Common Stock

The selling stockholders are offering 6,050,000 shares of our common stock. We will not receive any proceeds from the sale of the shares of common stock by the selling stockholders.

Our common stock is quoted on The Nasdaq National Market under the symbol “GPOR.” On April 27, 2006, the last reported sale price of our common stock on The Nasdaq National Market was $14.44 per share.

Investing in our common stock involves risks. See “ Risk Factors” beginning on page 11.


	Public Offering Price		Underwriting Discount		Proceeds to Selling Stockholders (Before Expenses)
Per Share	$	14.00	$	0.77	$	13.23
Total	$	84,700,000	$	4,658,500	$	80,041,500

The underwriters may purchase up to an additional 907,500 shares of our common stock from us at the public offering price less the underwriting discounts, solely to cover any over-allotments.

Delivery of the shares of common stock is expected to be made on or about May 3, 2006.

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.

Johnson Rice & Company L.L.C.

Dahlman Rose & Company

First Albany Capital

Pritchard Capital Partners, LLC

Simmons & Company International

The date of this prospectus is April 28, 2006.

Table of Contents


		Page
Prospectus Summary		1
Risk Factors		11
Cautionary Note Regarding Forward-Looking Statements		19
Use of Proceeds		20
Capitalization		21
Price Range of Common Stock		22
Dividend Policy		22
Selected Historical Financial Data		23
Business		25
Management		39
Principal and Selling Stockholders		45
Certain Relationships and Related Transactions		47
Description of Capital Stock		49
Underwriting		51
Legal Matters		53
Experts		53
Where You Can Find More Information		53
Glossary of Oil and Natural Gas Terms		A-1

About This Prospectus

You may rely only on the information contained or incorporated by reference in this prospectus. We and the selling stockholders have not, and the underwriters have not, authorized anyone to provide you with additional information or information different from that contained or incorporated by reference in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We and the selling stockholders are not making an offer to sell these securities in any jurisdiction where an offer to sell is not permitted. The information appearing in this prospectus is accurate in all material respects as of the date on the front cover of this prospectus, but our business, financial condition, results of operations and prospects may have changed since that date.

PROSPECTUS SUMMARY

This summary highlights certain information contained elsewhere in this prospectus and in documents we file with the Securities and Exchange Commission that are incorporated by reference in this prospectus. This summary is not complete and does not contain all of the information you should consider before investing in our common stock. You should carefully read the entire prospectus, including “Risk Factors” and the information incorporated by reference in this prospectus, including our financial statements and related notes thereto, before you decide whether to invest in our common stock. Unless otherwise indicated or the context otherwise requires, all references in this prospectus to “Gulfport,” the “Company,” “us,” “our” or “we” are to Gulfport Energy Corporation. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” in Appendix A.

Our Company

Overview

We are an independent oil and natural gas exploration and production company with properties located along the Louisiana Gulf Coast. Our operations are concentrated in two fields: West Cote Blanche Bay, or WCBB, and East Hackberry. As of December 31, 2005, we had 23.2 MMboe of proved reserves, of which 84% was oil, with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $456.9 million and associated standardized measure of discounted future net cash flows of approximately $369.8 million. See “—Summary of Operating and Reserve Data” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. Our 2005 production was 84% oil.

We seek to achieve reserve and production growth and increase our cash flow through our annual drilling programs. In 2005, we drilled 17 wells and recompleted 11 existing wells in our WCBB field for an estimated aggregate cost of $21.1 million. Of our 17 new wells, nine were completed as producing wells, seven were waiting to be completed at year end (one of which will be side-tracked in 2006 to test deeper zones) and one was a dry hole. During 2006, we intend to drill 22 wells, recomplete 18 existing wells at our WCBB field and complete six wells that we drilled in 2005 for an estimated aggregate cost of $33.2 million. As of April 18, 2006, we had drilled ten new wells of which eight are awaiting completion and two were dry holes. During 2005, we completed a 3-D seismic program at our East Hackberry field, to enhance our drilling program at that field, and we currently intend to drill up to six wells in 2006 for an estimated aggregate cost of $13.3 million.

WCBB. The WCBB field lies approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (79.4% NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.4% non-operated working interest (30.0% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. Texaco drilled the discovery well in this field in 1940. Of the 846 wells drilled as of December 31, 2005, 766 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. As of December 31, 2005, estimated field cumulative gross production was 232 MMboe. During the first half of 2005, we reprocessed a 70 square mile 3-D seismic survey using the most recent advances in seismic data processing. This reprocessed data has helped and will continue to help us add to our inventory of identified drilling locations. Since our acquisition of WCBB in 1997, we have drilled 62 new wells, seven of which were dry holes, for an 89% success rate. We have also recompleted 57 wells resulting in 44 producing wells. Our inventory of prospects includes approximately 120 PUD wells, many of which are up-dip offsets to wells that produced from a sub-optimum position within a particular zone. The drilling schedule used in our December 31, 2005 reserve report anticipates that all of those wells will be drilled by 2015. In addition, we have identified over 100 more developmental and exploratory prospects which include several deep natural gas prospects, one of which we intend to drill in 2006.

East Hackberry. The East Hackberry field is located along the western shore of Lake Calcasieu in Louisiana, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. The interest includes two separate lease blocks, the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. The two lease blocks together contain 3,147 acres. The East Hackberry field was discovered in 1926 by Gulf Oil Company. The estimated field cumulative oil and condensate production through 2005 was approximately 56 MMboe. We have received and are currently reviewing our proprietary 3-D seismic survey of 42 square miles in and around the East Hackberry field. Since this portion of the East Hackberry field has never been included in a 3-D seismic survey, we anticipate the data will reveal undrilled fault blocks that will allow us to drill new wells to both shallow and deep targets in the field.

Results for the Year Ended December 31, 2005

The following are highlights for the year ended December 31, 2005:

•

Oil and natural gas revenues increased 19% to $27.4 million for the year ended December 31, 2005 from $23.1 million for 2004.

•

Net income increased 153% to $10.9 million for the year ended December 31, 2005 from $4.3 million for 2004.

•

Oil production decreased 11% to 517 MBbls for the year ended December 31, 2005 from 584 MBbls for 2004 due to damage caused by Hurricane Rita during September 2005. See “—Impact of Hurricanes” below.

•

We commenced our 2005 WCBB drilling program in March 2005 and drilled 17 wells and recompleted 11 wells during the year. Of our 17 new wells drilled, nine were completed as producing wells, seven were waiting on completion due to the impact of Hurricane Rita (including one that will be side-tracked in 2006 to test deeper zones) and one was unsuccessful.

Impact of Hurricanes

Due to the impact of Hurricanes Katrina and Rita, much of our production was shut-in in the fourth quarter of 2005 and the first quarter 2006. As a result, total production in the fourth quarter of 2005 was 22.4 Mboe, not including adjustment for prior periods, and total estimated production in the first quarter of 2006 was 80.6 Mboe.

WCBB. We sustained no damage to our facilities at WCBB from Hurricane Katrina which made landfall on August 29, 2005. Prior to that storm, both our Hackberry and WCBB facilities were shut-in and evacuated for four days for precautionary reasons. In our WCBB field, we used the shut-in period to implement tie-in points for future facilities upgrades.

In preparation for Hurricane Rita, on September 21, 2005, we began shutting-in production and evacuating personnel from our WCBB field. On September 24, 2005, the tidal surge from Hurricane Rita caused damage to our WCBB facilities. Our main tank batteries, which handled approximately 70% of our production before Hurricane Rita, again became operational during the first quarter of 2006. We anticipate that the balance of our production facilities at WCBB will be brought on line in the second and third quarters of 2006. We began returning wells to production during the first quarter of 2006, and as of April 18, 2006, 27 of the 57 active wells in the field prior to Hurricane Rita had been returned to production on an intermittent basis. We continue to reactivate our remaining shut-in WCBB wells and are in the process of completing 15 that have been drilled after Hurricane Rita but not completed due to the damage to our facilities caused by that storm. We expect that all of these wells will begin producing during the second quarter of 2006.

On September 20, 2005, prior to Hurricane Rita, aggregate net production at WCBB was 2,204 Boe. We lost more than 100 days of production but have since resumed production at WCBB from 27 of the 57 wells that were active prior to Hurricane Rita, with aggregate net production ranging from 1,754 Boe to 3,032 Boe per day during the period March 20, 2006 through March 30, 2006. Aggregate net production from WCBB during the first quarter of 2006 was 59.1 Mboe.

East Hackberry Field. On September 20, 2005, prior to shutting-in our 11 producing East Hackberry wells in preparation for Hurricane Rita, aggregate net production was approximately 299 Boe per day. Production was re-established from six of these wells in November 2005, and during the period March 20, 2006 through March 30, 2006, aggregate net production from these wells ranged from approximately 181 Boe to 219 Boe per day. Due to damage to certain of our production facilities caused by Hurricane Rita, five wells in our State Lease 50 Block remain shut-in. Prior to being shut-in, these five wells had aggregate production of approximately 50 Boe per day. We have budgeted $8.0 million to replace and upgrade certain of our East Hackberry facilities in connection with our 2006 drilling program and intend to put the five remaining shut-in wells back on line when these facilities are completed. Aggregate net production from the East Hackberry field during the first quarter of 2006 was 14.6 Mboe.

Insurance Coverage. As of December 31, 2005, we had incurred costs of $3.2 million relating to the damage to our WCBB fields and facilities caused by Hurricane Rita. As of April 10, 2006, we had incurred an additional $2.6 million in hurricane related costs subsequent to December 31, 2005 at WCBB. Based upon consultations with insurance adjustors and review of our policies, we believe this entire amount will be covered by our insurance. We had no insurance coverage for property damage to our East Hackberry facilities. We also maintained business interruption insurance to cover lost production revenue in the event of shut-in production. The business interruption insurance began 60 days after the occurrence of an insurable event, subject to a daily limit of $45,000 and had a maximum coverage of 180 days. Coverage began on November 24, 2005 for shut-in production caused by Hurricane Rita. During 2005, we accrued $1.7 million of business interruption insurance recoveries in other income in our statement of operations, which was received subsequent to year end.

Our Strengths

We believe that our following strengths will help us achieve our business goals:

High quality asset base with a long reserve life. Our reserves are concentrated in two fields that have historically produced significant volumes of hydrocarbons from multiple geologic horizons. As of December 31, 2005, our proved developed reserves to production ratio was over six years. We believe this relatively stable base of long-lived production from multiple geologic horizons is a strong platform to support further growth in our reserves and production.

Experienced management and technical team. Our management and technical personnel have an average of 25 years of experience in the oil and natural gas industry, including two geophysicists who have worked together for over 25 years and together have participated in drilling over 60 wells in the Gulf Coast region.

Substantial drilling inventory. We have assembled an inventory of approximately 120 PUD locations and over 100 developmental and exploratory prospects. At our current pace of drilling, we believe we have over seven years of drilling inventory. We believe there are substantial opportunities to expand our exploration activities on our existing leasehold acreage position, particularly by exploring deeper gas prospects.

Operate core properties. We serve as operator of the WCBB field above the 13900 Sand and of our East Hackberry field. As operator, we can manage all phases of a project’s drilling and development operations. This

allows us to exercise greater control over the cost, timing and scope of our activities and more effectively use our platforms, processing facilities and flowlines.

Concentrated drilling operations. By drilling our wells in a relatively small geographic area, our mobilization costs are lower and the time required to move between wells is relatively short. Our ongoing, concentrated operations have also enabled us to refine our drilling and well completion techniques and maintain continuous use of key equipment. These factors can help reduce the cost to drill and complete our wells.

Technical approach. Substantially all of our drilling prospects are generated internally by our technical team using advanced technology in analyzing, interpreting and visualizing 3-D seismic data. We have reprocessed existing 3-D seismic data at WCBB and undertaken a new 3-D seismic survey at East Hackberry. We believe that our 94% drilling success rate at WCBB since 2003 is attributable to our technical knowledge of the field and our effective use of 3-D seismic data and subsurface geological mapping.

Our Business Strategy

Our goal is to increase stockholder value by investing in development and select exploration projects intended to grow our production and reserves and increase our cash flow while generating attractive rates of return. We seek to achieve this goal through the following:

Apply advanced technologies to enhance recoveries and grow production and reserves. We believe that our use of 3-D seismic data will help us identify prospective locations that were not visible using the older 2-D data that was primarily used in the development of the WCBB and East Hackberry fields. In addition, we primarily use directional drilling techniques that allow us to penetrate multiple prospects from each well bore increasing our potential reserve quantities and limiting exploration and development risk.

Focus on lower risk oil development projects, with selective expenditures on higher risk natural gas exploration projects. Many of our WCBB drilling locations are primarily shallow oil targets that are structurally up-dip to existing or historical production or located in undrilled fault blocks. We believe that by focusing our drilling budget on development oriented activities we can maintain high drilling success rates yielding attractive production and reserve growth. Our drilling program has achieved a success rate of 94% since 2003. We also plan to allocate a portion of our budget to drill higher impact, but higher risk, natural gas exploration prospects. In 2006, we plan to spend approximately 15% of our total drilling capital targeting natural gas prospects.

Financial flexibility. We seek to maintain a conservative financial position and believe that our operating cash flow will provide us with the financial flexibility to pursue our planned development and exploration activities through 2006.

Our Challenges

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 11 for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy as well as activities on our properties, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

Risks relating to the development of oil and natural gas reserves. Our oil and natural gas reserves and future production and, therefore, our future cash flow and income are highly dependent on our ability to successfully execute our drilling program, which will require substantial amounts of capital.

Risks relating to oil and natural gas reserve estimates. Reserve estimates are based on many assumptions and our properties may not produce the reserves we originally forecast. Our reserves will decline unless we are successful in finding or acquiring new reserves.

Access to equipment and personnel. Shortages of drilling rigs, equipment, supplies or personnel could delay, restrict or increase the cost of our exploration, exploitation and development operations, which in turn could impair our financial condition and results of operations.

Concentration in Louisiana. Our operations are concentrated in Louisiana. As a result, we may be disproportionately exposed to impacts of delays or interruptions of production from this region caused by hurricanes or other natural disasters, significant governmental regulation or lack of field infrastructure.

For a discussion of other considerations that could negatively affect us, see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Our Equity Sponsor

Prior to this offering, Charles E. Davidson beneficially owned 61.0% of our common stock, including the holdings of CD Holdings, L.L.C. and Wexford Capital LLC, or Wexford, both of which are entities controlled by Mr. Davidson. Wexford is a Greenwich, Connecticut based SEC registered investment advisor with approximately $4.5 billion under management as of December 31, 2005. Wexford has made private equity investments in many different sectors with particular expertise in the energy and natural resources sector. Certain investment funds controlled by Wexford, which in the aggregate beneficially own 5,631,011 shares of our common stock, are selling stockholders in this offering and are selling all of their shares in this offering. Upon completion of the offering, Mr. Davidson will beneficially own approximately 43.5% of our common stock.

Our Offices

We were organized in June 1997. Our principal executive offices are located at 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134, and our telephone number is (405) 848-8807. Our website address is www.gulfportenergy.com. Information contained on our website does not constitute a part of this prospectus.

The Offering

Common stock offered by the selling stockholders

6,050,000 shares

Common stock outstanding after this offering

32,180,326 shares

Over-allotment option granted by us

907,500 shares

Use of proceeds

We will not receive any of the proceeds from the sale of shares by the selling stockholders. We have granted the underwriters an option to purchase up to 907,500 shares of our common stock to cover over-allotments. We intend to use the net proceeds, if any, from the exercise of such option to repay outstanding borrowings under our credit facility with Bank of America.

The Nasdaq National Market symbol

“GPOR”

Risk Factors

Investing in our common stock involves certain risks. You should carefully consider the risk factors discussed under the heading “Risk Factors” beginning on page 11 of this prospectus and other information contained or incorporated by reference in this prospectus before deciding to invest in our common stock.

Except as otherwise indicated, all information contained in this prospectus:

•

assumes the underwriters do not exercise their over-allotment option;

•

excludes 1,557,273 shares of our common stock issuable upon exercise of outstanding stock options at a weighted average exercise price of $4.31 per share; and

•

excludes 350,588 shares of our common stock issuable upon exercise of outstanding warrants at a weighted average exercise price of $1.19 per share.

Summary Financial Data

The following tables summarize our financial data as of and for each of the years indicated. We derived the summary financial data from our audited financial statements for the years indicated. You should read the following financial information together with the information under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the notes to those financial statements incorporated by reference in our Annual Report on Form 10-KSB.


	Year Ended December 31,
	2005			2004			2003
	(In thousands, except per share amounts)
Consolidated Statements of Operations Information:
Revenues:
Gas sales	$	3,437		$	1,484		$	498
Oil and condensate sales		23,986			21,587			15,311
Other income		136			119			138

Total revenues		27,559			23,190			15,947

Costs and expenses:
Lease operating expenses		7,654			6,586			5,886
Production taxes		3,622			2,629			1,882
Depreciation, depletion, and amortization		4,789			4,952			4,637
General and administrative		1,561			2,107			1,843
Accretion expense		516			490			393

Total costs and expenses		18,142			16,764			14,641

Income from operations:		9,417			6,426			1,306

Other expense (income):
Interest expense		250			246			112
Interest expense—preferred stock		272			1,949			875
Business interruption insurance recoveries		(1,710	)		—			—
Interest income		(290	)		(73	)		(30	)

Total other expense (income)		(1,478	)		2,122			957

Income before taxes:		10,895			4,304			349
Income tax expense:		—			—			—

Net income before effect of change in accounting principle:		10,895			4,304			349
Cumulative effect of change in accounting principle:		—			—			270

Net income		10,895			4,304			619
Less: Preferred stock dividends		—			—			(838	)

Net income (loss) available to common stockholders	$	10,895		$	4,304		$	(219	)

Net income (loss) per common share—basic:
Per common share before effect of change in accounting principle	$	0.36		$	0.31		$	(0.05	)
Effect per common share of change in accounting principle		—			—			0.03

	$	0.36		$	0.31		$	(0.02	)

Net income (loss) per common share—diluted:
Per common share before effect of change in accounting principle	$	0.34		$	0.28		$	(0.05	)
Effect per common share of change in accounting principle		—			—			0.03

	$	0.34		$	0.28		$	(0.02	)


	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Consolidated Cash Flow Information:
Net cash provided (used) by:
Operating activities	$	15,200		$	8,403		$	6,872
Investing activities		(36,703	)		(15,123	)		(8,617	)
Financing activities		16,080			12,720			2,178

	At December 31,
	2005			2004			2003
	(In thousands)
Consolidated Balance Sheet Information:
Total current assets	$	12,249		$	12,337		$	3,440
Total assets		111,820			78,150			58,980
Long-term obligations and redeemable preferred stock, excluding current maturities		17,971			24,191			19,548
Total liabilities		27,493			29,053			25,832
Total stockholders’ equity		84,327			49,097			33,148

Summary Operating and Reserve Data

The following estimates of net proved oil and natural gas reserves are based on the reserve report prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers. For additional information, you should refer to “Risk Factors,” “Business—Proved Oil and Natural Gas Reserves” and “Business—Production, Prices and Production Costs” included herein and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this prospectus.


	Year Ended December 31,
	2005		2004
Production Data
Oil (MBbls)		517		584
Natural gas (MMcf)⁽¹⁾		575		284
Combined Volumes (Mboe)		613		631

Average Prices
Oil (per Bbl)⁽²⁾	$	46.39	$	36.97
Natural gas (per Mcf)	$	5.98	$	5.24
Combined volumes (per Boe)	$	44.75	$	36.58

	As of December 31,
	2005		2004
Estimated Proved Reserves
Oil (MMBbls)		19,542		20,905
Natural gas (MMcf)		21,780		23,162
Total (Mboe)		23,172		24,765
PV-10 (in millions)⁽³⁾	$	456.9	$	361.5
Standardized measure (in millions)⁽⁴⁾	$	369.8	$	301.0

(1)	Production of natural gas liquids is included in natural gas revenues and production.

(2)	Includes the effects of fixed price contracts. Excluding fixed price contracts, the prices for oil were $56.17 per Bbl in 2005 and $42.72 per Bbl in 2004.

(3)

Represents the present value, discounted at 10% per annum (PV-10), of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2005 and 2004, respectively. The estimated future production is priced at December 31, 2005, without escalation, using $57.75 per Bbl and $10.08 per MMBtu, and at December 31, 2004, without escalation, using $40.25 per Bbl and $6.18 per MMBtu, in each case adjusted by lease for transportation fees and regional price differentials.

PV-10 is a non-GAAP financial measure because it excludes income tax effects. 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 oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure—standardized measure of discounted future net cash flow—in the following table:


	As of December 31,
	2005		2004
Standardized measure of discounted future net cash flows	$	369,824,000	$	301,047,000
Add: Present value of future income tax discounted at 10%		87,086,000		60,495,000

PV-10	$	456,910,000	$	361,542,000

(4)

The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

The above table does not include (a) proved reserves, net to our interest in Tatex Thailand II, LLC of 3.36 Bcf of gas and 10,082 barrels of oil at August 1, 2005 or (b) proved reserves attributable to our Marquiss field of 212,584 Mcf of gas at December 31, 2005. For further discussion of our interests in Tatex and the Marquiss field, see “Business—Additional Properties.”

RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the following risks and all other information contained or incorporated by reference in this prospectus before deciding to invest in our common stock. Our business, financial condition or results of operations could be materially and adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business and Industry

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

•

worldwide and domestic supplies of oil and natural gas;

•

weather conditions;

•

the level of consumer demand;

•

the price and availability of alternative fuels;

•

risks associated with operating drilling rigs;

•

the availability of pipeline capacity;

•

the price and level of foreign imports;

•

domestic and foreign governmental regulations and taxes;

•

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

•

political instability or armed conflict in oil-producing regions; and

•

the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. The West Texas Intermediate posted price for crude oil on December 31, 2004 was $43.45 per Bbl and the Henry Hub spot market price of natural gas on December 31, 2004 was $6.21 per MMBtu and at December 31, 2003 were $32.52 per Bbl and $6.19 per MMBtu. The West Texas Intermediate posted price for crude oil on December 31, 2005 was $57.75 per Bbl and the Henry Hub spot market price of natural gas on December 31, 2005 was $10.08 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations.

Our success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production,

exploration and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including:

•

our proved reserves;

•

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

•

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

•

our ability to acquire, locate and produce new reserves.

We cannot assure you that we will have sufficient resources to undertake exploration for and development, production and acquisition of oil and natural gas reserves, that our exploratory projects or other replacement activities will result in significant additional reserves or that we will have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Shortage of rigs, equipment, supplies or personnel may restrict our operations.

The oil and natural gas industry is cyclical, and at the present time there is a shortage of drilling rigs, equipment, supplies and personnel. The costs and delivery times of rigs, equipment and supplies has increased as drilling activities have increased. In addition, demand for, and wage rates of, qualified drilling rig crews have risen with increases in the number of active rigs in service. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, supplies, personnel, trucking services, tubulars, fracing and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists, Stuart Maier and Randy Wilson, could disrupt our operations resulting in a loss of revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Liddell, and our executives are not restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures, including many factors beyond our control. The reserve information set forth in this prospectus represents only estimates based on reports prepared by NSAI as of December 31, 2005. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes,

capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as:

•

actual prices we receive for oil and natural gas;

•

the amount and timing of actual production;

•

supply of and demand for oil and natural gas; and

•

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows 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 oil and natural gas industry in general. PV-10 is a non-GAAP measure because it excludes income tax effects. See “Business—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10.

Substantially all of our producing properties are located in Louisiana, making us vulnerable to risks associated with operating in this region.

Our operations are concentrated in Louisiana. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by hurricanes or other natural disasters, significant governmental regulation or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We cannot assure you that we will be able to obtain and maintain adequate insurance at rates we consider reasonable or that any particular types of coverage will be available. See “Summary—Our Company—Impact of Hurricanes” and “Business—West Cote Blanche Bay Field,” “—East Hackberry Field” and “—West Hackberry Field” for a discussion regarding the impact of Hurricane Rita and Hurricane Katrina.

Our identified drilling locations comprise an estimation of part of our future drilling plans over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have identified over 200 drilling locations on our core properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, including hurricanes, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Operating hazards and uninsured risks may result in substantial losses.

Our operations are subject to all of the hazards and operating risks inherent in drilling for and production of oil and gas, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and

environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, we historically have maintained insurance against some, but not all, of these risks. On April 1, 2006, our insurance expired and we are currently determining whether to renew our coverages. We cannot assure you that we will renew these coverages or, if we do, that such insurance will be adequate to cover any losses or liabilities we may suffer. We also cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities would not be covered by insurance.

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. These laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue.

We face extensive competition in our industry.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation.

We depend upon two customers for the sale of most of our oil and natural gas production.

The availability of a ready market for any oil and/or natural gas we produced depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production is being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade month average P+ value, plus or minus the Platt’s WII/LLS differential less $0.85 per Bbl for transportation. During 2005, we sold 99% of our oil production to Shell and 88% of our natural gas production to Chevron. During 2004, we sold 99% of our oil production to Shell and 68% and 21% of our natural gas production to Chevron and Apache Corporation, respectively. Our wells are not subject to any agreements that would prevent us from either selling our production on the spot market or

committing such gas to a long-term contract; however, there can be no assurance that we will continue to have ready access to suitable markets for our future oil and natural gas production.

Our method of accounting for oil and natural gas properties may result in impairment of asset value.

We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil.

Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We have hedged and may continue to hedge a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

To reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter into hedging arrangements. Our hedging arrangements currently in place for 2006 involve 45,000 barrels of oil per month at a price of $64.05 per barrel. Such hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. For example, under these arrangements the counterparty may require us to post cash collateral approximately equal to the difference between the agreed contract price of $64.05 per barrel and a defined market price multiplied by the remaining barrels of oil under the open contracts. As a result, significant increases in oil prices could adversely affect our financial position. In addition, our hedging arrangements may limit the benefit to us of increases in the price of oil.

We will be subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected.

We will be required to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as of December 31, 2007. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls and management’s assessment of those controls. We will be required to evaluate our existing controls against the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weakness, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Risks Related to this Offering and Our Common Stock

If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile.

Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including:

•

changes in oil and natural gas prices;

•

changes in production levels;

•

changes in governmental regulations and taxes;

•

geopolitical developments;

•

the level of foreign imports of oil and natural gas; and

•

conditions in the oil and natural gas industry and the overall economic environment.

Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly.

Our officers and directors together with our largest stockholder control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

As of the date hereof, our executive officers and directors, in the aggregate, beneficially own approximately 5.6% of our outstanding common stock. Additionally, Charles E. Davidson beneficially owns approximately 61.0% of our outstanding common stock. Upon completion of this offering, our officers and directors, in the aggregate, will beneficially own 4.4%, and Mr. Davidson will beneficially own 43.5% of our outstanding common stock. As a result, these stockholders acting together are able to exercise significant influence over most matters requiring approval by our stockholders, including the election of directors and the approval of significant corporate transactions. Such a concentration of ownership may have the effect of delaying or preventing a change in control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices.

We have incurred and will continue to incur increased costs as a result of being a public company.

As a result of being a public company, we have incurred and will continue to incur significant legal, accounting and other expenses. We have incurred and will continue to incur costs associated with our public company reporting requirements and costs associated with recently adopted corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as new rules implemented by the SEC and the NASD. Prior to the consummation of this offering, we were considered to be a “controlled company” for the purposes of The Nasdaq National Market’s corporate governance requirements, and as a result were eligible for exemptions from provisions of these rules requiring that our board have a majority of independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. Because we will cease to be a controlled company within the meaning of these rules upon consummation of this offering, we will be required to comply with these provisions after the specified transition periods. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. We also expect these new rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these new rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We can give no assurances as to the market for our common stock.

Since February 28, 2006, our common stock has been quoted on The Nasdaq National Market under the symbol “GPOR.” Prior to that date, our common stock was traded on the NASD OTC Bulletin Board under the symbol “GPOR.OB.” There is a limited market for our shares. We cannot assure you that an active trading market will develop, or if it does, that it will be sustained.

We do not currently pay dividends on our common stock and do not anticipate doing so in the future.

We have paid no cash dividends on our common stock, and there can be no assurance that we will achieve sufficient earnings to pay cash dividends on our common stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock.

A change of control could limit our use of net operating losses.

As of December 31, 2005, we had a net operating loss, or NOL, carry forward of approximately $100.4 million for federal income tax purposes. Transfers of our stock in the future could result in an ownership

change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate.

Future sales of our common stock may depress our stock price.

Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of common or preferred stock. As of April 27, 2006, we had 32,180,326 shares of common stock issued and outstanding.

In addition, some of our current stockholders may have “demand” and/or “piggyback” registration rights in connection with future offerings of our common stock. “Demand” rights enable the holders to demand that their shares be registered and may require us to file a registration statement under the Securities Act at our expense. “Piggyback” rights require that we provide notice to the relevant holders of our stock if we propose to register any of our securities under the Securities Act, and grant such holders the right to include their shares in the registration statement.

We could issue additional preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects.

We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine, each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock.

In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders.

Provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders.

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. See “Description of Capital Stock—Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws.”

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference herein include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical facts, included in this prospectus and the documents incorporated by reference herein that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; changes in laws or regulations; hurricanes and other natural disasters and other factors, many of which are beyond our control. Consequently, all of the forward-looking statements made in this prospectus, and the documents incorporated by reference in this prospectus, are qualified by these cautionary statements and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward looking statements, whether as a result of new information, future results or otherwise.

USE OF PROCEEDS

We will not receive any proceeds from the sale of shares of our common stock by the selling stockholders.

We have granted the underwriters an option to purchase up to an additional 907,500 shares of common stock from us to cover over-allotments, if any. Assuming the underwriters exercise their over-allotment option in full, the net proceeds from our sale of these shares of common stock will be approximately $11.5 million, based on a public offering price of $14.00 per share and after deducting the underwriting discount and estimated offering expenses. If the underwriters exercise their over-allotment option, we intend to use the net proceeds to repay outstanding borrowings under our credit facility with Bank of America. Our credit facility provides for a $30.0 million revolver subject to a current borrowing base limitation of $23.0 million. On April 27, 2006, $21.5 million was outstanding under this facility. The credit facility has a term of three years and all principal amounts of revolving loans outstanding under the credit facility, together with all accrued and unpaid interest and fees, will be due and payable on March 11, 2008. Amounts borrowed against the credit facility bear interest at the Bank of America prime rate plus 0.25% (7.5% at December 31, 2005). Our obligations under the credit facility are collateralized by a lien on substantially all of our Louisiana based oil and natural gas assets. The outstanding borrowings under our credit facility were used for general corporate purposes.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2005:

•

on an actual basis; and

•

on an as adjusted basis to reflect the exercise in full by the underwriters of their over-allotment to purchase from us up to 907,500 shares of common stock, and our receipt of the estimated net proceeds of $11.5 million from such sale, based on a public offering price of $14.00 per share, after deducting the underwriting discount and estimated offering expenses.

You should read this table in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes which are incorporated by reference in this prospectus.


	As of December 31, 2005
	Actual			As Adjusted (Unaudited)
	(Dollars in thousands, except share data)
Cash and cash equivalents	$	2,119		$	3,425

Total debt (including current maturities) (1)	$	10,200		$	—
Stockholder’s Equity:
Common stock, $0.01 par value, 55,000,000 authorized, 32,168,203 issued and outstanding actual; 55,000,000 authorized, 33,075,703 issued and outstanding as adjusted		322			331
Paid-in capital		119,192			130,689
Accumulated other comprehensive income		759			759
Accumulated deficit		(35,946	)		(35,946	)

Total stockholder’s equity	$	84,327		$	95,833

Total capitalization	$	94,527		$	95,833

(1)	On April 27, 2006, total debt was $24.5 million.

PRICE RANGE OF COMMON STOCK

•

the high and low sales prices for our common stock as reported by The Nasdaq National Market for each quarter during the period from February 28, 2006 through April 27, 2006; and

•

the high and low sales prices for our common stock as reported by the NASD OTC Bulletin Board for each quarter in 2004 and 2005 and for the first quarter of 2006 through February 27, 2006, which quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.


	Low		High
Year Ending December 31, 2006
First Quarter (through February 27, 2006)	$	10.00	$	15.35
First Quarter (beginning February 28, 2006)	$	12.24	$	16.00
Second Quarter (through April 27, 2006)	$	13.88	$	15.89

Year Ended December 31, 2005
First Quarter	$	3.24	$	5.90
Second Quarter	$	5.00	$	6.90
Third Quarter	$	6.70	$	11.50
Fourth Quarter	$	9.10	$	13.00

Year Ended December 31, 2004
First Quarter	$	2.80	$	3.40
Second Quarter	$	2.15	$	3.10
Third Quarter	$	1.55	$	3.90
Fourth Quarter	$	2.75	$	4.00

On April 27, 2006, the last reported sale price of our common stock on The Nasdaq National Market was $14.44 and there were 32,180,326 shares of our common stock outstanding and approximately 400 stockholders of record.

DIVIDEND POLICY

We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibits the payment of any dividends to the holders of our common stock.

SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth our selected historical financial data as of and for each of the years indicated. We derived the selected historical financial data as of and for each of the years ended 2005, 2004 and 2003 from our historical audited financial statements. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and historical financial statements and related notes incorporated by reference in this prospectus.


	Year Ended December 31,
	2005			2004			2003
	(In thousands, except per share amounts)
Consolidated Statements of Operations Information:
Revenues:
Gas sales	$	3,437		$	1,484		$	498
Oil and condensate sales		23,986			21,587			15,311
Other income		136			119			138

Total revenues		27,559			23,190			15,947

Costs and expenses:
Lease operating expenses		7,654			6,586			5,886
Production taxes		3,622			2,629			1,882
Depreciation, depletion, and amortization		4,789			4,952			4,637
General and administrative		1,561			2,107			1,843
Accretion expense		516			490			393

Total costs and expenses		18,142			16,764			14,641

Income from operations:		9,417			6,426			1,306

Other expense (income):
Interest expense		250			246			112
Interest expense—preferred stock		272			1,949			875
Business interruption insurance recoveries		(1,710	)		—			—
Interest income		(290	)		(73	)		(30	)

Total other expense (income)		(1,478	)		2,122			957

Income before taxes:		10,895			4,304			349
Income tax expense:		—			—			—

Net income before effect of change in accounting principle:		10,895			4,304			349
Cumulative effect of change in accounting principle:		—			—			270

Net income		10,895			4,304			619
Less: Preferred stock dividends		—			—			(838	)

Net income (loss) available to common stockholders	$	10,895		$	4,304		$	(219	)

Net income (loss) per common share—basic:
Per common share before effect of change in accounting principle	$	0.36		$	0.31		$	(0.05	)
Effect per common share of change in accounting principle		—			—			0.03

	$	0.36		$	0.31		$	(0.02	)

Net income (loss) per common share—diluted:
Per common share before effect of change in accounting principle	$	0.34		$	0.28		$	(0.05	)
Effect per common share of change in accounting principle		—			—			0.03

	$	0.34		$	0.28		$	(0.02	)


	Year Ended December 31,
	2005			2004			2003
	(In thousands)
Consolidated Cash Flow Information:
Net cash provided (used) by:
Operating activities	$	15,200		$	8,403		$	6,872
Investing activities		(36,703	)		(15,123	)		(8,617	)
Financing activities		16,080			12,720			2,178

	At December 31,
	2005			2004			2003
	(In thousands)
Consolidated Balance Sheet Information:
Total current assets	$	12,249		$	12,337		$	3,440
Total assets		111,820			78,150			58,980
Long-term obligations and redeemable preferred stock, excluding current maturities		17,971			24,191			19,548
Total liabilities		27,493			29,053			25,832
Total stockholders’ equity		84,327			49,097			33,148

BUSINESS

General

We are an independent oil and natural gas exploration and production company with properties located along the Louisiana Gulf Coast. Our operations are concentrated in two fields: WCBB and East Hackberry. As of December 31, 2005, we had 23.2 MMboe of proved reserves, of which 84% was oil, with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $456.9 million and associated standardized measure of discounted future net cash flows of approximately $369.8 million. See “—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. Our 2005 production was 84% oil.

We seek to achieve reserve and production growth and increase our cash flow through our annual drilling programs. In 2005, we drilled 17 wells and recompleted 11 existing wells in our WCBB field for a total estimated cost of $21.1 million. Of our 17 new wells, nine were completed as producing wells, seven were waiting to be completed at year end (one of which will be side-tracked in 2006 to test deeper zones) and one was a dry hole. During 2006, we intend to drill 22 wells, recomplete 18 existing wells at our WCBB field and complete six wells that we drilled in 2005 for an estimated aggregate cost of $33.2 million. As of April 18, 2006, we had drilled ten new wells of which eight are awaiting completion and two were dry holes. During 2005, we completed a 3-D seismic program at our East Hackberry field to enhance our drilling program at that field and we currently intend to drill up to six wells in 2006 for an estimated aggregate cost of $13.3 million.

Principal Oil and Natural Gas Properties

We own interests in producing oil and natural gas properties located along the Louisiana Gulf Coast. The following table presents certain information as of December 31, 2005 reflecting our net interest in our principal producing oil and natural gas properties in Louisiana.


								Proved Reserves
Field	NRI/WI ⁽¹⁾	Producing Wells ⁽²⁾		Non-Producing Wells		Developed Acreage ⁽³⁾		Gas	Oil	Total
Field	Percentages	Gross	Net	Gross	Net	Gross	Net	Mboe	Mboe	Mboe
West Cote Blanche Bay ⁽⁴⁾	79.4/100	0	0.0	258	258	5,668	5,668	2,937	16,663	19,600
East Hackberry	78.7/100	6	6.0	70	70	3,147	3,147	693	2,717	3,410
West Hackberry	87.5/100	3	3.0	24	24	592	592	—	157	157
Overrides/Royalty Non-operated	Various	9	0.4	28	1.3	4,956	586	—	5	5

Total		18	9.4	380	353.3	14,363	9,993	3,630	19,542	23,172

(1)	Net Revenue Interest (NRI)/Working Interest (WI).

(2)

On September 21, 2005, we began shutting in all of our producing wells at WCBB and the Hackberry fields in preparation for the arrival of Hurricane Rita. Six of our 11 producing wells in the Hackberry fields returned to production in November 2005. Our WCBB facilities, however, sustained more damage and the 57 wells that were producing on September 20, 2005 before the hurricane struck remained shut-in at December 31, 2005. As a result, all of these wells have been classified as non-producing wells at December 31, 2005 in the above table. Our main tank batteries and gas sales line became operational, and we began returning wells to production, in February 2006. As of April 18, 2006, 27 of the 57 active wells at WCBB prior to Hurricane Rita had returned to production on an intermittent basis. We expect the remaining wells, as well as 15 additional wells drilled at WCBB after the hurricane but not completed due to the damage to our facilities, to commence production during the second quarter of 2006.

(3)

Developed acres are acres allocated or assignable to productive wells or wells capable of production. All of our acreage is developed acreage. All of the oil and natural gas leases in which we own an interest have been perpetuated by production. The operator may surrender the leases at any time by notice to the lessors, or by the cessation of production.

(4)	We have a 100% working interest (79.4% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.4% non-operated working interest (30.0% NRI).

West Cote Blanche Bay Field

Location and Land

The WCBB field lies approximately five miles off the coast of Louisiana, primarily in St. Mary Parish, in a shallow bay with water depths averaging eight to ten feet. Currently, we own a 100% working interest (79.4% NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.4% non-operated working interest (30.0% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB cover a portion of Louisiana State Lease 340 and contain 5,668 gross acres.

Area History and Production

Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 846 wells drilled as of December 31, 2005, 766 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. As of December 31, 2005, estimated field cumulative gross production was 193 MMbo and 234 Bcf of gas.

Of the 846 wells drilled in WCBB as of December 31, 2005, 57 were producing prior to being shut-in beginning on September 21, 2005 in preparation for Hurricane Rita, nine were drilled after Hurricane Rita but not completed by year end, 172 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 573 wells have been plugged and abandoned. During the period January 1, 2005 through September 21, 2005, our net daily production at WCBB averaged 1,727 barrels of oil, 1,934 Mcf of gas and 11,470 barrels of water.

In 1991, Texaco conducted a 70 square mile 3-D seismic survey. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data which our technical staff used to identify and develop prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using the most recent advances in seismic data processing.

From our acquisition of WCBB in 1997 through December 31, 2005, we drilled 62 new wells, seven of which were dry holes, for an 89% success rate. These wells produced 2,749 gross Mboe through December 31, 2005. We have also recompleted 57 existing wells resulting in 44 producing wells. These recompleted wells produced 1,193 gross Mboe through December 31, 2005.

Geology

WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed.

There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 846 wellbores that had been drilled in the field as of December 31, 2005, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive.

WCBB is a structurally and stratigraphically complex field. All of the PUD locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects includes approximately 120 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2015.

Facilities

We own and operate a production facility at WCBB that includes four production tank batteries and is equipped with hydrocarbon separation equipment, four natural gas compressor platforms, a dehydration unit and a salt water disposal system. We sustained minimal damage to our facilities at WCBB from Hurricane Katrina which came onshore on August 29, 2005. Our WCBB facilities were shut-in and evacuated for precautionary reasons for only four days. On September 24, 2005, however, the tidal surge from Hurricane Rita caused damage to our WCBB facilities and all of our active WCBB wells were shut-in. Our main tank batteries, which handled approximately 70% of our production before Hurricane Rita, and the gas sales line are now operational, and we anticipate that the balance of our production facilities at WCBB will be brought on line in the second and third quarters of 2006. We began returning WCBB wells to production on February 5, 2006, and as of April 18, 2006, 27 of the 57 active wells in the field prior to Hurricane Rita had been returned to production on an intermittent basis. We continue to reactivate our remaining shut-in WCBB wells and are in the process of completing 15 wells that have been drilled after Hurricane Rita but not completed due to the damage to our facilities caused by that storm. We expect that all of these wells will begin producing during the second quarter of 2006. We had an insurance program in place that we believe will adequately cover damage to our platform and facilities at WCBB. In addition, business interruption insurance has helped mitigate the financial impact of Hurricane Rita on our WCBB operations. Once fully operational, we believe our facilities will have capacity in excess of our current and anticipated production volumes.

Recent and Future Activity

In 2005, we drilled 17 wells and recompleted 11 existing wells at WCBB. Of these 17 new wells, nine were completed as producers, seven were drilled subsequent to Hurricane Rita and have not yet been completed (including one that will be side-tracked in 2006 to test deeper zones) and one was a dry hole. We anticipate drilling 22 wells and recompleting 18 wells at WCBB during 2006. As of April 18, 2006, we had drilled ten new wells and production casing has been run on seven of these wells, bringing to 15 the number of wells that have been drilled but not yet been completed due to the effects of Hurricane Rita. The 15 wells that are now in the process of being completed are expected to begin producing in the second quarter of 2006. The remaining two wells drilled in 2006 were dry holes.

The ten wells we have drilled at WCBB to date in 2006 include three deep wells, three intermediate depth wells and four shallow wells. The deep wells, with total depths ranging from 8,850 to 9,400 feet, have approximately 373 feet of apparent net pay. The intermediate wells, with total depths ranging from 5,000 to 7,500 feet, have approximately 188 feet of apparent net pay. Two of the shallow wells, at depths of less than 3,000 feet, have 40 feet of apparent net pay. Two additional shallow wells were unsuccessful, including one exploratory well that was drilled to satisfy our drilling commitment to hold the non-productive portions of WCBB.

In the second quarter of 2006, we anticipate drilling a 12,000 foot wildcat test well targeting the higher-pressure gas zones in the field for an anticipated well cost of approximately $5.5 million. The cost of this wildcat well is approximately four times the cost of a typical well drilled to 9,500 feet, and has more geologic risk.

However, we believe the additional geological risk is warranted by the higher reserve and production potential of the wildcat test. We have also identified other deeper wildcat gas test wells on the WCBB salt dome acreage, as well as undrilled conventional depth fault blocks. We expect to test these exploratory prospects in 2007 and thereafter based on our drilling results and available cash flows.

Production Status

On September 20, 2005, prior to Hurricane Rita, 57 wells, including nine productive wells we drilled in 2005, were producing and total net production at WCBB on that date was 2,204 Boe, 97% of which was from oil and 3% of which was from natural gas. During the period March 20, 2006 through March 30, 2006, total net production at WCBB from 27 of the 57 active wells that were shut-in in preparation for Hurricane Rita ranged from 1,754 Boe to 3,032 Boe per day. Aggregate net production from WCBB during the first quarter of 2006 was 59.1 Mboe. We expect our WCBB production to increase substantially in the second quarter of 2006 as the remaining wells shut-in for Hurricane Rita are returned to production and our 15 new wells drilled after the hurricane, together with additional wells that are now being drilled as part of our 2006 drilling program, are completed and brought on-line.

East Hackberry Field

Location and Land

The East Hackberry field is located along the western shore of Lake Calcasieu in Cameron Parish, Louisiana, approximately 80 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. The interest includes two separate lease blocks, the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. The two lease blocks together contain 3,147 acres.

Area History and Production

The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2005 was over 49 MMbo and 41 Bcf of casinghead gas production. There have been a total of 170 wells drilled on our portion of the field. As of December 31, 2005, six wells had daily production, 84 were shut-in and two had been converted to salt water disposal wells. The remaining 78 wells had been plugged and abandoned.

Geology

The Hackberry salt ridge is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet.

Facilities

We have land-based production and processing facilities located at the East Hackberry field. The facilities include dehydrating units and disposal pumps. We also have a field office that serves both the East and West Hackberry fields.

Recent and Future Activity

During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry for a total cost in 2004 and 2005 of approximately $5.0 million. Given that previous drilling activities at the East Hackberry field were undertaken without the benefit of modern seismic information, we believe that the newly acquired 3-D seismic data will enhance our probability of drilling success. We are evaluating the newly processed 3-D seismic data to identify additional drilling locations. We currently intend to drill six wells during 2006 to measured depths of approximately 13,000 feet using directional drilling techniques. The 3-D seismic data also suggests the possibility of deep gas production and, as a result, we intend to drill a deep wildcat well during 2007 for a total anticipated well cost of approximately $4.0 million. If productive, multiple offset locations could be drilled.

Prior to shutting-in our 11 producing East Hackberry wells on September 20, 2005 in preparation for Hurricane Rita, aggregate net production was approximately 299 Boe per day. Production was re-established from six of these wells in November 2005, and during the period March 20, 2006 through March 30, 2006, aggregate net production from these wells ranged from approximately 181 Boe to 219 Boe per day. Due to damage to certain of our production facilities caused by Hurricane Rita, five wells in our State Lease 50 Block remain shut-in. Prior to being shut-in, these five wells in the field had aggregate production of approximately 50 Boe per day with a limited amount of gas. We plan on replacing or upgrading certain of our East Hackberry facilities in connection with our 2006 drilling program and intend to put the five remaining shut-in wells back on line when these facilities are completed. Aggregate net production from the East Hackberry field during the first quarter of 2006 was 14.6 Mboe.

West Hackberry Field

Location and Land

The West Hackberry field is located on land and is five miles West of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves.

Area History and Production

The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2005 was 18.4 MMbo and 12.9 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. During the period March 20, 2006 through March 30, 2006, aggregate net production from the wells ranged from 72 Boe to 83 Boe per day.

Geology

Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry salt ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 Mboe.

Facilities

We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields.

Additional Properties

Louisiana. In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and an overriding royalty interest in various fields in Louisiana as described in the following table:


Field	Parish	Acreage Working Interest		Overriding Royalty Interests		Producing Wells	Non-Producing Wells
Bayou Long	Iberia	3.125	%	0	%	1	0
Bayou Penchant	Terrebonne	3.125	%	0	%	1	13
Bayou Pigeon	Iberia	6.250	%	0	%	4	8
Deer Island	Terrebonne	6.250	%	0	%	0	6
Golden Meadow	Lafourche	3.125	%	0	%	0	1
Napoleonville	Assumption	0	%	2.5	%	3	0

Thailand. During March 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2,400,000. The remaining interests in Tatex are owned by other entities controlled by Wexford Capital LLC, or Wexford, an affiliate of ours. Tatex holds approximately 8.5% of the outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company, and our investment is accounted for on the cost method. APICO has a reserve base located in Southeast Asia through its ownership interests in concessions covering 3 million acres. Our interest in Tatex includes proved reserves, net to our interest, of 3.36 Bcf of natural gas and 10,082 barrels of oil at August 1, 2005, the latest date that reserve information is available to us. These reserves are not included in our December 31, 2005 reserve report.

Williston Basin. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by other entities controlled by Wexford, an affiliate of ours. As of December 31, 2005, Bakken had acquired leases covering approximately 83,300 gross and 41,600 net acres, all of which is undeveloped, in the Williston Basin located in western North Dakota and eastern Montana. The Williston Basin has production from 11 major geologic horizons that range in depth from 1,000 to over 14,000 feet, with our current zones of interest lying at depths ranging from 9,000 to 12,000 feet. Activities in this basin are expected to include both exploration and development drilling programs to different horizons including the Bakken shale. It is currently contemplated that Bakken will contribute all of its assets to Windsor Energy Resources, Inc., or Windsor Energy, in connection with Windsor Energy’s proposed initial public offering. We would receive an indirect equity interest in Windsor Energy as a result of that contribution. Windsor Energy is beneficially owned by Wexford and is an affiliate of ours.

Marquiss Field. In February 2005, we acquired our interest in the Marquiss field, an approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming, for $375,000. As of December 31, 2005, the Marquiss field included a total of 162 wells, of which 105 were producing and 57 were shut-in. The effective date of the sale was December 1, 2004. The wells produce from multiple horizons with additional upside potential from deeper coals and operational efficiencies. The Marquiss field contained proved gas reserves, net to our interest, of 212,548 Mcf at December 31, 2005. These reserves are not included in our December 31, 2005 reserve report. We plan to contribute these properties to Windsor Energy, an affiliate of our company, in connection with its initial public offering in exchange for common stock of Windsor Energy.

Competition and Markets

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production is being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade month average P+ value, plus or minus the Platt’s WII/LLS differential less $0.85 per Bbl for transportation. During 2005, we sold 99% of our oil production to Shell and 88% of our natural gas production to Chevron. During 2004, we sold 99% of our oil production to Shell and 68% and 21% of our natural gas production to Chevron and Apache Corporation, respectively. Our wells are not subject to any agreements that would prevent us from either selling our production on the spot market or committing such natural gas to a long-term contract; however, there can be no assurance that we will continue to have ready access to suitable markets for our future oil and natural gas production.

Production from our Marquiss field in Wyoming is gathered in the field and delivered to Western Gas Resources at two gas sales meters located in our field. We are paid based on a Gas Daily CIG index net of various deductions for gathering, quality and fuel for compression.

Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices.

We established an oil price-hedging program in August 2005 to reduce our exposure to unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by taking receive-fixed positions in price swap contracts. We pay the counterparty the excess of the oil market price over the fixed price and will receive the excess of the fixed price over the market price as defined in each contract. These contracts allow us to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. For the year ended December 31, 2005, price swap contracts hedged 8.7% of our oil production. As of December 31, 2005, price swap contracts were in place to hedge 540,000 barrels of estimated future production during 2006. For the year ended December 31, 2005, fixed-price sales contracts covered 71% of our oil production.

Regulation

Regulation of Oil and Natural Gas Production

Oil and natural gas operations are subject to various types of regulation by state and federal agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast and Wyoming. These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis.

Environmental Regulation

Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or permitting requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements; this trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, affect oil and natural gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration and production wastes as “hazardous wastes.”

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, and comparable state statutes, generally impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA, such persons may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use, and previous operators of our properties may have used, materials, that, if released, would be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been deposited.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These proscriptions also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act and the Oil Pollution Act of 1990 (OPA) require facilities that store or otherwise handle oil in excess of specified quantities to prepare and implement spill prevention, control and countermeasure plans and facility response plans relating to possible discharges of oil to surface water. Costs may be associated with the treatment of wastewater or developing and implementing required plans. We believe that we have obtained or applied for all permits required under the Clean Water Act. Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive relief.

Air Emissions. The federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.

Coastal Coordination. Various state and federal programs regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act, CZMA, was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation’s coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. In Louisiana, state legislation enacted in 1978 established the Louisiana Coastal Zone Management Program, LCZMP, to protect, develop and, where feasible, restore and enhance coastal resources of the state. Under the LCZMP, coastal use permits are required for certain activities in the coastal zone, even if the activity only partially infringes on the coastal zone. The Coastal Management Division of Louisiana’s Department of Natural Resources administers the coastal use permit program which applies in the coastal areas of 18 of Louisiana’s 64 parishes. Activities requiring such a permit include, among other things, projects involving the use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas activities. The LCZMP and its requirement to obtain coastal use permits may result in additional permitting requirements and associated time constraints for our projects.

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act, OSHA, and comparable state statutes. The OSHA Hazard Communications Standard, the EPA Community Right to Know regulations under Title III of CERCLA, and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. We believe we are in substantial compliance with the applicable requirements.

Operational Hazards and Insurance

Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to persons. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures

and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. In accordance with customary industry practice, we historically have maintained insurance against some, but not all, of these risks. On April 1, 2006, our insurance expired and we are currently determining whether to renew our coverages. We cannot assure you that we will renew these coverages or, if we do, that such insurance will be adequate to cover any losses or liabilities we may suffer. We also cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities would not be covered by insurance.

Headquarters and Other Facilities

We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is used as our Louisiana headquarters. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of warehouse area.

Employees

As of April 15, 2006, we had 83 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the estimated time they spent working for those affiliates. In addition, we receive 100% of the Council of Petroleum Accountants Societies (COPAS) overhead charges billed to these affiliated companies. For the years ended December 31, 2005 and 2004, expenses reimbursed to us under these arrangements were $6,232,000 and $2,146,000, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company serves as contract operator of WCBB and the Hackberry fields and provides all necessary field personnel.

Proved Oil and Natural Gas Reserves

The oil and natural gas reserve information set forth below represents estimates as prepared by the independent engineering firm of NSAI. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. See “Risk Factors” contained elsewhere in this prospectus. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year.

The following table sets forth estimates of our proved oil and natural gas reserves at December 31, 2005 and 2004, as estimated by NSAI.


	December 31, 2005						December 31, 2004
	Developed		Undeveloped		Total		Developed		Undeveloped		Total
Oil (MBbls)		4,308		15,234		19,542		4,633		16,272		20,905
Gas (MMcf)		3,758		18,022		21,780		4,635		18,527		23,162
Mboe		4,934		18,238		23,172		5,405		19,360		24,765
PV-10 (in millions) (1)	$	135.9	$	321.0	$	456.9	$	89.5	$	272.0	$	361.5
Standardized measure (in millions) (2)		—		—	$	369.8		—		—	$	301.0

(1)

Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2005 and 2004, respectively. The estimated future production is priced at December 31, 2005, without escalation, using $57.75 per Bbl and $10.08 per MMBtu, and at December 31, 2004, without escalation, using $40.25 per Bbl and $6.18 per MMBtu, in each case adjusted by lease for transportation fees and regional price differentials.


	As of December 31,
	2005		2004
Standardized measure of discounted future net cash flows	$	369,824,000	$	301,047,000
Add: Present value of future income tax discounted at 10%		87,086,000		60,495,000

PV-10	$	456,910,000	$	361,542,000

(2)

The above table does not include (a) proved reserves, net to our interest in Tatex, of 3.36 Bcf of gas and 10,082 barrels of oil at August 1, 2005 or (b) proved reserves attributable to our Marquiss field of 212,584 Mcf of gas at December 31, 2005. For further discussion of our interests in Tatex and the Marquiss field, see “Business—Additional Properties.”

Proved developed reserves are proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

Total proved reserves decreased 1,593 Mboe to 23,172 Mboe at December 31, 2005 from 24,765 at December 31, 2004. This decrease in reserves is mainly attributable to reserve revisions and reductions related to our 2005 production. Further, a significant portion of the reserves that were categorized as proved developed producing at December 31, 2004 have been recategorized as proved developed non-producing shut-in or proved undeveloped as a result of the damage caused by Hurricane Rita in September 2005.

Production, Prices and Production Costs

The following table presents our production volumes and average prices received during the periods indicated:


	2005			2004			2003
Production Volumes:
Oil (MBbls)		517			584			571
Gas (MMcf)		575			284			123
Oil Equivalents (Mboe)		613			631			592

Average Prices:
Oil (per Bbl)	$	46.39	⁽¹⁾	$	36.97	⁽¹⁾	$	27.66	⁽¹⁾
Gas (per Mcf)	$	5.98		$	5.24		$	4.04
Oil Equivalents (per Mboe)	$	44.75		$	36.58		$	26.70
Average Production Costs (per Boe)	$	12.49	⁽²⁾	$	10.44	⁽²⁾	$	9.93	⁽²⁾
Average Production Taxes (per Boe)	$	5.91		$	4.17		$	3.17

Total Production Costs (per Boe)	$	18.40		$	14.61		$	13.10

(1)	Includes fixed contract prices of:


January 2003	$	28.50
February 2003	$	28.34
March 2003	$	27.95
April 2003	$	27.08
May 2003	$	26.95
June 2003	$	24.27
July 2003	$	24.33
August 2003	$	24.42
September 2003	$	24.45
October 2003	$	24.45
November 2003	$	24.25
December 2003	$	24.10
January—June 2004	$	30.00
July—December 2004	$	33.60
January—June 2005	$	33.10
July—December 2005	$	39.70

Also includes financial hedge contracts with a mark-to-market value of approximately $50,000 total for the months of September—December 2005.

Excluding the effect of the fixed price contracts, the average oil price for 2005 would have been $56.17 per Bbl and $52.99 per Bbl oil equivalent price. Excluding the effect of the fixed price contracts, the average oil price for 2004 would have been $42.72 per Bbl and $41.88 per Bbl oil equivalent price. Excluding the effect of the fixed price contracts, the average oil price for 2003 would have been $32.38 per Bbl and $32.08 per Bbl oil equivalent price.

(2)	Does not include production taxes.

Productive Wells and Acreage

The following table presents our total gross and net productive wells, expressed separately for oil and gas, and the total gross and net developed acres as of December 31, 2005:


	Producing Wells (1)		Non-Producing Wells		Developed Acreage (2)
Field	Gross	Net	Gross	Net	Gross (3)	Net (4)
West Cote Blanche Bay	0	0	258	258	5,668	5,668
East Hackberry	6	6	70	70	3,147	3,147
West Hackberry	3	3	24	24	592	592
Overrides/Royalty Non-operated	9	0.4	28	1.3	4,956	586

Total	18	9.4	380	353.3	14,363	9,993

(1)

On September 21, 2005, we began shutting-in all of our producing wells at WCBB and the Hackberry fields in preparation for the arrival of Hurricane Rita. Six of our 11 producing wells in the Hackberry fields returned to production in November 2005. Our WCBB facilities, however, sustained more damage and the 57 wells that were producing on September 30, 2005 before the hurricane struck remained shut-in at December 31, 2005. As a result, all of these wells have been classified as non-producing wells at December 31, 2005 in the above table. Our main tank batteries and gas sales line became operational, and we began returning wells to production, in February 2006. As of April 18, 2006, 27 of the 57 active wells at WCBB prior to Hurricane Rita had returned to production on an intermittent basis. We expect the remaining wells, as well as 15 additional wells drilled at WCBB after the hurricane but not completed due to the damage to our facilities, to commence production during the second quarter of 2006.

(2)

(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Completed and Present Recompletion and Drilling Activities

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.


	2005 (1)		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Recompletions:
Productive	11	11	13	13	8	8
Dry	0	0	0	0	1	1

Total	11	11	13	13	9	9

Development:
Productive	16	16	8	8	7	7
Dry	0	0	0	0	0	0

Exploratory:
Productive	0	0	0	0	0	0
Dry	1	1	0	0	1	1

(1)	Includes seven gross and net wells that were drilled during 2005 but not completed due to the damage caused by Hurricane Rita. For further discussion of the impact of Hurricane Rita, see “Summary—Our Company—Impact of Hurricanes.”

Title to Oil and Natural Gas Properties

It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management’s opinion, will in the aggregate materially restrict our operations.

Legal Proceedings

We have been named as a defendant in various lawsuits related to our business. The ultimate resolution of these matters is not expected to have a material adverse effect on our financial condition or results of operations.

MANAGEMENT

Our officers, directors and other key employees are as follows:


Name	Age	Position
Mike Liddell	52	Chairman of the Board and Director
James D. Palm	61	Director, Chief Executive Officer
Michael G. Moore	49	Vice President and Chief Financial Officer
Joel H. McNatt	47	Vice President, Secretary and General Counsel
Stuart Maier	52	Geological/Geophysical Manager
Randy Wilson	54	Geological/Geophysical Manager
Robert E. Brooks	59	Director
David L. Houston	53	Director
Mickey Liddell	44	Director
Dan Noles	58	Director
Phillip G. Lancaster	48	Director

Mike Liddell has served as a director of our company since July 1997 and as Chairman of the Board of our company since July 1998. Mr. Liddell served as Chief Executive Officer of our company from April 1998 to December 2005 and President of our company from July 2000 to December 2005. In addition, Mr. Liddell served as Chief Executive Officer of DLB Oil & Gas, Inc., a publicly held oil and natural gas company, from October 1994 to April 1998, and as a director of DLB Oil & Gas from 1991 through April 1998. From 1991 to 1994, Mr. Liddell was President of DLB Oil & Gas. From 1979 to 1991, he was President and Chief Executive Officer of DLB Energy. Mr. Liddell has served since May 2005 as Chairman of the Board and a director of Bronco Drilling Company, Inc., a provider of contract land drilling services. Mr. Liddell has served since December 2005 as the Chairman of the Board and a director of Windsor Energy Resources, Inc., an independent energy company focused on the exploration, exploitation and development of both conventional and unconventional onshore oil and natural gas reserves. Windsor Energy Resources is indirectly controlled by Wexford Capital LLC and Bronco Drilling Company is a company in which Wexford Capital LLC beneficially owns approximately 47% of the outstanding shares of common stock. Mr. Liddell received a Bachelor of Science degree in education from Oklahoma State University. Mr. Liddell is the brother of Mickey Liddell and brother-in-law of Dan Noles.

James D. Palm has served as a director of our company since February 2006 and as Chief Executive Officer of our company since December 2005. Mr. Palm is the manager and owner of Crescent Exploration, LLC, an independent oil and natural gas exploration company founded by Mr. Palm in 1995 and operating primarily in Oklahoma, the Texas Panhandle and Kansas. Mr. Palm currently serves as a member of the Industry Advisory Committee of the Oklahoma Corporation Commission. From October 2001 through October 2003, Mr. Palm served as the Chairman of the Oklahoma Energy Resources Board. From 1997 through 1999, Mr. Palm served as the President of the Oklahoma Independent Petroleum Association. Mr. Palm received a Bachelor of Science degree in Mechanical Engineering in 1968, and a Masters in Business Administration in 1971, both from Oklahoma State University.

Michael G. Moore has served as a Vice President and Chief Financial Officer of our company since July 2000. From May 1998 through July 2000, Mr. Moore served as Vice President and Chief Financial Officer of Indian Oil Company. From September 1995 through May 1998, Mr. Moore served as Controller of DLB Oil & Gas. Prior to that, Mr. Moore served as Controller of LEDCO, Inc., a Houston based gas marketing company. Mr. Moore received both his Bachelor of Business Administration degree in finance and his Masters in Business Administration from the University of Central Oklahoma.

Joel H. McNatt has served as a Vice President, General Counsel and Secretary of our company since November 2004. From May 1996 through October 2004, Mr. McNatt practiced in the areas of energy, products liability and complex business litigation with the firm McKinney & Stringer, P.C. Mr. McNatt received his juris

doctorate, summa cum laude, from Oklahoma City University School of Law in 1996, and prior to that his Bachelor of Art in journalism from the University of Oklahoma.

Stuart Maier has served as a Geological/Geophysical Manager of our company since May 1998. From 1993 to May 1998, he had served as Senior Geologist with DLB Oil & Gas. From 1992 until joining DLB Oil & Gas, Mr. Maier was a consulting geologist/geophysicist and, from 1981 to 1991, Mr. Maier was a geologist/geophysicist with The Anschutz Corporation, an oil and natural gas exploration and production company. From 1979 to 1981, Mr. Maier was a production geologist for Gulf Oil Exploration and Production Company. From 1977 to 1979, Mr. Maier was a well site geologist. Mr. Maier received a Bachelor of Science degree in geology from the University of Missouri. Mr. Maier is a member of the American Association of Petroleum Geologists.

Randy Wilson has served as a Geologist/Geophysicist of our company since May 1998. From 1994 to May 1998, Mr. Wilson had served as Geologist with DLB Oil & Gas. From 1992 until joining DLB Oil & Gas, Mr. Wilson was President of J.L. Resources, Inc., a geological and geophysical consulting services company. From 1980 to 1987, Mr. Wilson was a geological/geophysical manager for The Anschutz Corporation Mid-continent division. From 1987 to 1992, Mr. Wilson was the Division Manager for The Anschutz Corporation Mid-continent division. From 1978 to 1980, Mr. Wilson was employed as a geophysicist with Terra Resources, Inc., an oil and natural gas exploration and production company. From 1977 to 1978, Mr. Wilson was a geologist for Monsanto Company and, from 1974 to 1977, Mr. Wilson was a geophysicist for Cities Service Oil Company, an oil and natural gas exploration and production company. Mr. Wilson received a Bachelor of Science degree in geology from Wichita State University. Mr. Wilson is a member of the American Association of Petroleum Geologists.

Robert E. Brooks has served as a director of our company since July 1997. Mr. Brooks is currently President of Delphi Oil & Gas, Inc. From 1997 to 2002, Mr. Brooks was a partner with Brooks Greenblatt, a commercial finance company located in Baton Rouge, Louisiana that was formed by Mr. Brooks in July 1997. Mr. Brooks is a Certified Public Accountant and was Senior Vice President in charge of Asset Finance and Managed Assets for Bank One, Louisiana between 1993 and July 1997. Mr. Brooks received his Bachelor of Science degree from Purdue University in mechanical engineering in 1969. Mr. Brooks obtained graduate degrees in finance and accounting from the Graduate School of Business at the University of Chicago in 1974.

David L. Houston has served as a director of our company since July 1998. Since 1991, Mr. Houston has been the principal of Houston & Associates, a firm that offers life and disability insurance, compensation and benefits plans and estate planning. Mr. Houston has served as a director of Bronco Drilling Company since May 2005. Mr. Houston is a nominee to serve as director of Windsor Energy Resources upon completion of its initial public offering. Windsor Energy Resources is indirectly controlled by Wexford Capital LLC and Bronco Drilling Company is a company in which Wexford Capital LLC beneficially owns approximately 47% of the outstanding shares of common stock. Prior to 1991, Mr. Houston was President and Chief Executive Officer of Equity Bank for Savings, F.A., an Oklahoma-based savings bank. Mr. Houston currently serves on the board of directors and executive committee of Deaconess Hospital, Oklahoma City, Oklahoma, and is the former chair of the Oklahoma State Ethics Commission and the Oklahoma League of Savings Institutions. Mr. Houston received a Bachelor of Science degree in business from Oklahoma State University and a graduate degree in banking from Louisiana State University.

Mickey Liddell has served as a director of our company since January 1999. Since 2001, Mr. Liddell has been the President of Berlanti-Liddell Entertainment, LLC, a television and motion picture production company. From 2000 through 2001, Mr. Liddell served as President of Entertainment Services, LLC. From 1994 through 1999, Mr. Liddell served as President of Banner Entertainment, LLC. Both Banner Entertainment LLC and Mr. Liddell filed for bankruptcy in 1999. Mr. Liddell received a Bachelor of Arts from the University of Oklahoma in Communications in 1984 and a graduate degree from Parson School of Design in New York, New York in 1987. Mr. Liddell is the brother of Mike Liddell and brother-in-law of Dan Noles.

Dan Noles has served as a director of our company since January 2000. Mr. Noles is the President of Dan Noles Construction LLC. Prior to that he served as the President of Atoka Management Company, an oilfield equipment company. Mr. Noles received his Bachelor degree in Finance from the University of Oklahoma in 1970. Mr. Noles is the brother-in-law of Mike Liddell and Mickey Liddell.

Phillip G. Lancaster has served as a director of our company since February 2006. Mr. Lancaster is currently a director and founder of three Australian companies, Ozpride Pty LTD., Texoz Pty LTD and Magipark Pty LTD, whose principal business is real-estate investment and property management in Australia. Mr. Lancaster has served as a director of Bronco Drilling Company since July 2005. Bronco Drilling Company is a company in which Wexford Capital LLC beneficially owns approximately 47% of the outstanding shares of common stock. Mr. Lancaster is also currently a management partner for a sports management facility in Dallas, Texas affiliated with ClubCorp. Mr. Lancaster was the managing partner of Lankin Drilling Fund, Inc. from 1985 through 1999. Mr. Lancaster received a Bachelor of Science degree in Sociology from David Lipscomb College in 1978.

Board of Directors and Committees

We are managed under the direction of our board of directors. The size of our board of directors is set at seven members, and we currently have seven directors including five non-employee directors. Our directors generally serve one-year terms from the time of their election until the next annual meeting of stockholders or until their successors are duly elected and qualified. Our board of directors has two standing committees: the audit committee and the compensation committee, each of which are further described below.

Audit Committee. The audit committee oversees our accounting and financial reporting processes and the audits of our financial statements. In that regard, the audit committee assists our board of directors in monitoring (1) our accounting, auditing and financial reporting processes generally, including the qualifications, independence and performance of the independent auditor, (2) the integrity of our financial statements, (3) our systems of internal control regarding finance and accounting and (4) our compliance with legal and regulatory requirements.

The audit committee is composed of David L. Houston, Robert E. Brooks and Phillip G. Lancaster, all of whom are non-employee directors. All of the members of the audit committee are financially literate and Mr. Houston serves as chairman of the audit committee and is designated as the “audit committee financial expert” as such term is defined in Item 401(e) of Regulation S-B of the Securities Exchange Act of 1934, as amended. Messrs. Houston, Brooks and Lancaster are “independent” within the meaning of the NASD’s director independence standards. In February 2006, our board of directors and audit committee amended and restated the Audit Committee Charter, which sets for the specific functions and responsibilities of the audit committee.

Compensation Committee. The compensation committee considers executive employment agreements, adoption of employee benefit plans and other issues related to compensation and employee benefits. The compensation committee is comprised of Phillip G. Lancaster and David L. Houston, both of whom are “non-employee directors” as defined by Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as amended, and “outside directors” as defined by Section 162(m) of the Internal Revenue Code.

Because we are considered to be controlled by Charles E. Davidson under The Nasdaq National Market rules, we are eligible for exemptions from provisions of these rules requiring that a majority of our board of directors be comprised of independent directors and a nominating and corporate governance committee composed entirely of independent directors and written charters addressing specified matters. We have elected to take advantage of certain of these exemptions. Upon consummation of this offering, however, we will cease to be a controlled company within the meaning of these rules. Accordingly, we will be required to comply with these provisions after the specified transition periods.

Director Compensation

Members of our board of directors who are also our officers or employees do not receive compensation for their services as directors. We pay our non-employee directors a monthly retainer of $1,000 and a per meeting attendance fee of $500 and reimburse all ordinary and necessary expenses incurred by non-employee directors in the conduct of our business.

During 2005, we implemented our 2005 Stock Incentive Plan. Under the 2005 Stock Incentive Plan, each non-employee director was granted nonqualified stock options during 2005 to purchase 20,000 shares of our common stock at an exercise price of $3.36, an amount equal to the fair market value of our common stock on the date of grant. Options granted to eligible non-employee directors under the 2005 Stock Incentive Plan vest in 36 equal monthly installments beginning on the date of grant and are exercisable for a period of ten years beginning on the date of grant.

Compensation Committee Interlocks

None of our executive officers serves, or has served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of our board of directors or compensation committee.

Executive Compensation

Summary Compensation Table

The following table sets forth information for the fiscal years ended December 31, 2005, 2004 and 2003 with respect to compensation earned by our chief executive officer and by our three other highest paid executive officers as of the end of the last fiscal year.


						Long Term Compensation
Name and Principal Position	Year	Annual Compensation (1)				Securities Underlying Options (#)	All Other Compensation (2)
Name and Principal Position	Year	Salary ($)		Bonus ($)		Securities Underlying Options (#)	All Other Compensation (2)
Mike Liddell (3) Chairman of the Board	2005 2004 2003	$	230,687 224,184 218,566	$	70,395 29,108 24,000	467,270 — —	$	25,290 22,423 19,500

James D. Palm (4) Chief Executive Officer	2005	$	16,167	$	—	200,000	$	1,000

Michael G. Moore Vice President and Chief Financial Officer	2005 2004 2003	$	176,333 128,813 105,000	$	120,000 17,138 13,800	30,000 — —	$	17,780 8,757 7,128

Joel H. McNatt (5) Vice President, General Counsel and Secretary	2005 2004	$	130,333 17,769	$	40,000 5,000	20,000 —	$	10,220 2,043

(1)

Amounts shown include cash and non-cash compensation earned and received by the named executives as well as amounts earned but deferred at their election. We provide various perquisites to certain employees, including the named executives. In each case, the aggregate value of the perquisite provided to the named executives did not exceed $50,000 or 10% of such named executive’s total annual salary and bonus.

(2)

Amounts for Mike Liddell include our matching 401(k) plan contributions of $18,065, $15,198 and $12,000 during 2005, 2004 and 2003, respectively, and life insurance premium payments of $7,225, $7,225 and $7,500 during 2005, 2004 and 2003, respectively. Amounts for Messrs. Palm, Moore and McNatt represent our matching 401(k) plan contributions during each of the indicated years.

(3)	Mr. Liddell resigned as our Chief Executive Officer and President in December 2005, but remains our Chairman of the Board and a director.

(4)	Mr. Palm joined us as Chief Executive Officer in December 2005 with a salary of $200,000.

(5)	Mr. McNatt joined us as Vice President, General Counsel and Secretary in November 2004 with a salary of $120,000.

Option Grants in Last Fiscal Year

The following table sets forth certain information concerning option grants made to named executive officers during 2005 pursuant to our 2005 Stock Incentive Plan.


	Individual Grants
	Number of Securities Underlying Options Granted (#)	Percentage of Total Options Granted to Employees in Fiscal Year (1)		Exercise Price ($/Sh)		Expiration Date
Mike Liddell	457,270	46	%	$	3.36	1/24/2015
James D. Palm	200,000	20	%	$	11.20	12/1/2015
Michael G. Moore	10,000	1	%	$	3.36	1/24/2015
	20,000	2	%	$	9.07	9/9/2015
Joel H. McNatt	20,000	2	%	$	3.36	1/24/2015

(1)	In 2005, we granted options to purchase a total of 997,269 shares of our common stock at exercise prices ranging from $3.36 to $11.20 per share.

Option Exercises in Last Fiscal Year and Fiscal Year End Option Values

The following table sets forth certain information concerning the exercise of options during 2005 and the number of unexercised options held by named executive officers as of December 31, 2005.


Name	Shares Acquired on Exercise (#)	Value Realized ($)		Number of Securities Underlying Unexercised Options at Fiscal Year End (#)		Value of Unexercised In-the- Money Options at Year End ($)
Name	Shares Acquired on Exercise (#)	Value Realized ($)		Exercisable (1)	Unexercisable	Exercisable(2)		Unexercisable
Mike Liddell	—		—	457,270	457,270	$	4,600,000	$	4,000,000
James D. Palm	—		—	5,555	194,444	$	4,722	$	165,277
Michael G. Moore	6,581	$	36,000	2,220	27,780	$	6,616	$	139,884
Joel H. McNatt	—		—	—	20,000	$	—	$	173,800

(1)	These options are exercisable at a weighted average exercise price per share of $2.12 per share.

(2)	Value for “in the money” options represents the positive spread between the respective exercise prices of outstanding options and the closing price of the shares of our common stock of $12.05 per share as reported by the NASD OTC Bulletin Board on December 30, 2005.

2005 Stock Incentive Plan

We have implemented a 2005 Stock Incentive Plan. The purpose of the plan is to enable our company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to our company’s long range success and to provide incentives which are linked directly to increases in share value which will inure to the benefit of our stockholders. The plan provides a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of our common stock through the granting of incentive stock options and nonstatutory stock options.

Eligible award recipients are our employees, consultants and directors and our affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to

employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed 1,904,606 shares, subject to adjustments to reflect certain corporate transactions or changes in our capital structure.

In 2005, we granted options to employees and certain non-employee directors to purchase a total of 997,269 shares of our common stock under the plan. These options have a weighted average exercise price of $5.62 per share, have a term of ten years and vest in 36 equal monthly installments beginning on the date of grant. In addition, we have granted options to eligible non-employee directors as described in “—Director Compensation” above.

Our board of directors and a majority of our stockholders approved amendments to the plan which, when effective, will:

•

expand the plan to include (a) Incentive Stock Options, (b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights; and

•

increase the maximum aggregate amount of common stock which may be issued under the plan from 1,904,606 shares to 3,000,000 shares.

Employment Agreements

In May 1999, we entered into an employment agreement with Mike Liddell. The agreement has a five year term and automatically renews for successive one-year terms thereafter. The agreement provides for an annual base salary of $200,000, adjusted for cost of living increases. Upon termination of Mr. Liddell’s employment by us without cause, Mr. Liddell is entitled to receive twelve months of his then current base salary, and all of Mr. Liddell’s then unexercisable options will become exercisable. The agreement also restricts Mr. Liddell’s use or disclosure of any of our confidential information during the term of the agreement and for a period of five years thereafter.

We entered into an oral agreement with James D. Palm with respect to his compensation and benefits, pursuant to which Mr. Palm will be entitled to an annual salary of $200,000 and, at the discretion of our board of directors, an annual cash incentive bonus. Mr. Palm will also be eligible to participate in all insurance, retirement and benefits plans available to our other employees.

PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth certain information regarding the beneficial ownership of our common stock as of the date hereof, before and after this offering, by (1) each director, (2) each named executive officer, (3) each person known or believed by us to own beneficially five percent or more of our outstanding common stock, (4) all directors and executive officers as a group and (5) each selling stockholder. Except as otherwise indicated, the beneficial owners named in the table below have sole voting and investment power with respect to all shares of capital stock held by them.


	Beneficial Ownership (1) Prior to the Offering			Number of Shares Offered	Beneficial Ownership After the Offering
Name and Address of Beneficial Owner	Number	Percentage		Number of Shares Offered	Number	Percentage
Charles E. Davidson (2) 411 West Putnam Avenue Greenwich, CT 06830	19,637,446	61.0	%	5,631,011	14,006,435	43.5	%

Southpoint Capital Advisors, LP(3) 237 Park Avenue, Suite 900 New York, NY 10017	2,018,527	6.3	%	—	2,018,527	6.3	%

Luxor Capital Group (4) 767 Fifth Avenue, 19^th Floor New York, New York 10153	1,606,948	5.0	%	—	1,606,948	5.0	%

Mike Liddell (5)	1,714,880	5.2	%	418,989	1,295,891	4.0	%

Robert Brooks (6)	24,000	*		—	24,000	*

David Houston (7)	24,000	*		—	24,000	*

Mickey Liddell (8)	24,000	*		—	24,000	*

Dan Noles (9)	24,000	*		—	24,000	*

Michael G. Moore (10)	7,555	*		—	7,555	*

Joel McNatt (11)	4,000	*		—	4,000	*

James D. Palm (12)	38,889	*		—	38,889	*

Phillip Lancaster (13)	5,555	*		—	5,555	*

All directors and executive officers as a group (9 individuals)	1,866,879	5.7	%	—	1,466,879	4.5	%

*	Less than one percent

(1)

Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to options held by that person that are currently exercisable, or exercisable within 60 days of the date hereof, are deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 32,180,326 shares of common stock outstanding prior to and after the offering. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options that are not exercisable as of the date hereof or exercisable within 60 days of the date hereof.

(2)

Includes 13,195,478 shares of common stock held by CD Holdings, L.L.C. and 810,957 shares of common stock held in an IRA for Mr. Davidson. Mr. Davidson is the manager and a member of CD Holdings, L.L.C. Mr. Davidson is the Chairman and controlling member of Wexford Capital LLC. In addition, the amount includes 5,631,011 shares of common stock owned by the following investment funds that are affiliated with Wexford: Wexford Special Situations 1996, L.P.; Wexford Special Situations 1996 Institutional, L.P.;

Wexford Special Situations 1996 Limited; Wexford-Euris Special Situations 1996, L.P.; Wexford Spectrum Investors LLC; Wexford Capital Partners II, L.P.; and Wexford Overseas Partners I, L.P., which we refer to collectively as the Wexford investment funds. Mr. Davidson disclaims beneficial ownership of the 5,631,011 shares of common stock owned by the Wexford investment funds. The Wexford investment funds are selling all of their shares of common stock in this offering.

(3)

Based solely upon information obtained from Amendment No. 1 to Schedule 13G filed with the SEC on March 10, 2005 on behalf of Southpoint Capital Advisors LLC, a Delaware limited liability company, Southpoint GP, LLC, a Delaware limited liability company, Southpoint Capital Advisors LP, a Delaware limited partnership, Southpoint GP, LP, Robert W. Butts and John S. Clark II. Southpoint Capital Advisors LP, Southpoint GP LP, Southpoint Capital Advisors LLC, Southpoint GP LLC, Robert W. Butts and John S. Clark II have sole voting and dispositive power over 2,018,527 shares of common stock. Southpoint Capital Advisors LLC is the general partner of Southpoint Capital Advisors LP. Southpoint GP LLC is the general partner of Southpoint GP, LP. Southpoint GP, LP is the general partner of Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited partnership, and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership. Southpoint Offshore Fund, Ltd., a Cayman Island exempted company, is also a general partner of the Southpoint Offshore Operating Fund, LP.

(4)

Based solely upon information obtained from the Schedule 13G filed by Luxor Capital Partners, LP, LCG Select, LLC, Luxor Capital Partners Offshore, Ltd., Luxor Capital Group, LP, Luxor Management, LLC, LCG Holdings, LLC and Christian Leone with the SEC on February 14, 2006. Luxor Capital Partners, LP, Luxor Capital Group, LP, Luxor Management, LLC, LCG Holdings, LLC and Mr. Leone share voting and dispositive power over 690,171 shares of common stock held by Luxor Capital Partners, LP. LCG Select, LLC, Luxor Capital Group, LP, Luxor Management, LLC, LCG Holdings, LLC and Mr. Leone share voting and dispositive power over 8,472 shares of common stock held by LCG Select, LLC. Luxor Capital Partners Offshore, Ltd., Luxor Capital Group, LP, Luxor Management, LLC and Mr. Leone share voting and dispositive power over 908,305 shares of common stock held by Luxor Capital Partners Offshore, Ltd. Luxor Capital Group, LP is the Investment Manager of Luxor Capital Partners, LP, LCG Select, LLC and Luxor Capital Partners Offshore, Ltd. Luxor Management, LLC is the general partner of Luxor Capital Group, LP, and Mr. Leone is the managing member of Luxor Management, LLC. LCG Holdings, LLC is the general partner of Luxor Capital Partners, LP and LCG Select, LLC and Mr. Leone is the managing member of LCG Holdings, LLC. Luxor Capital Partners Offshore, Ltd. is an entity organized in the Cayman Islands.

(5)

Includes 1,123,070 shares of common stock held of record by Liddell Investments, L.L.C. Mr. Liddell is the sole member of Liddell Investments, L.L.C. Includes 43,086 shares of common stock held of record by a certain family member of Mr. Liddell. Also includes 548,724 shares of common stock issuable upon the exercise of options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(6)	Represents 24,000 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(7)	Represents 24,000 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(8)	Represents 24,000 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(9)	Represents 24,000 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(10)	Includes 7,555 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(11)	Represents 4,000 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(12)	Represents 38,889 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

(13)	Represents 5,555 shares of common stock issuable upon the exercise of stock options that, as of the date hereof, were exercisable or exercisable within 60 days of the date hereof.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Back-stop Agreement

Pursuant to an agreement dated April 14, 2004, between us and CD Holdings, L.L.C., an entity controlled by Charles E. Davidson, one of our principal stockholders, CD Holdings agreed, subject to certain conditions, to back-stop our 2004 rights offering by purchasing all of the shares of our common stock that were not otherwise subscribed for by the other holders of subscription rights under their basic subscription privileges and over-subscription privileges. In return for its agreement to back-stop the rights offering, CD Holdings received a commitment fee equal to 2% of the gross proceeds of the rights offering, or $240,000, which was applied to the subscription price payable upon exercise of the rights issued to it in the rights offering.

Credit Agreement

In connection with our 2004 rights offering, we entered into a $3,000,000 revolving credit facility dated April 30, 2004 with CD Holdings. Borrowings under the CD Holdings credit facility were due on the earlier of the closing of the rights offering or August 1, 2005, and bore interest at the rate of 10.0% per annum. The CD Holdings credit facility provided that if the rights offering was not completed, CD Holdings had the right to convert any borrowings plus any accrued but unpaid interest under the facility into shares of our common stock at a conversion price equal to $1.20 per share. Under the CD Holdings credit facility, CD Holdings had the option to apply the outstanding principal amount and any accrued but unpaid interest either (1) to the subscription price payable upon exercise of the rights issued to CD Holdings in the rights offering, or (2) to the purchase price for the common stock. Upon closing of the rights offering, $500,000 had been borrowed on the facility to fund a part of our 2004 drilling program. CD Holdings applied all amounts due it under this credit facility to the exercise price payable upon exercise of rights it received in the rights offering. See “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Liquidity and Capital Resources—Credit Facilities” incorporated by reference in this prospectus for additional information regarding this credit facility.

Administrative Services for Affiliates

Effective April 1, 2005, we entered into an administrative services agreement with Bronco Drilling Company, Inc. Under this agreement, we agreed to provide certain services to Bronco Drilling Company including accounting, human resources, legal and technical support services. In return for these services, Bronco Drilling Company agreed to pay us an annual fee of approximately $414,000 payable in equal monthly installments during the term of this agreement. In addition, Bronco Drilling Company leased approximately 1,200 square feet of office space from us for its headquarters located in Oklahoma City, Oklahoma for which it agreed to pay us annual rent of $20,880 in equal monthly installments. The services we provide under the administrative services agreement and the fees for such services can be amended by mutual agreement of the parties. In January 2006, Bronco Drilling Company reduced the level of administrative services being provided by us and increased the office space it leases to approximately 2,500 square feet. As a result, our annual fee for administrative services was reduced to approximately $150,000 and our annual rental was increased to approximately $44,000. The administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by Bronco Drilling Company at any time with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. Prior to entry into this administrative services agreement, Bronco Drilling Company reimbursed us for our dedicated employee time, office space and general and administrative costs based upon the pro rata share of time its employees spent performing services for Bronco Drilling Company. In 2005, 2004 and 2003, we received payments from Bronco Drilling Company for such services and overhead totaling approximately $353,000, $115,000 and $33,000, respectively. Three of our directors, Mike Liddell, David L. Houston and Phillip G. Lancaster, are also directors of Bronco Drilling Company and Mr. Liddell serves as chairman of Bronco Drilling Company. Wexford Capital

LLC is the sole manager of Bronco Drilling Holdings, L.L.C., which beneficially owned 47.3% of the common stock of Bronco Drilling Company as of March 17, 2006. Charles E. Davidson is the Chairman of Wexford Capital.

In addition, our personnel help manage the oil and natural gas production and oil and natural gas related assets owned by certain of our affiliates. In return for these services, we are reimbursed for our dedicated employee time, office space and general and administrative costs based upon the pro rata share of time our employees spend performing these services. In 2005, 2004 and 2003, we received payments from these affiliates, excluding Bronco Drilling Company, for such services and overhead totaling approximately $5,876,000, $2,030,000 and $732,000, respectively.

DESCRIPTION OF CAPITAL STOCK

The following summary description of our capital stock is qualified in its entirety by reference to our certificate of incorporation and bylaws, each of which is incorporated by reference in this prospectus.

Common Stock

We are currently authorized to issue up to 55,000,000 shares of common stock, par value $0.01 per share, of which there were 32,180,326 shares outstanding as of the date hereof. Holders of our common stock are entitled to cast one vote for each share held of record on each matter submitted to a vote of stockholders. There is no cumulative voting for election of directors. Subject to the prior rights of any series of preferred stock which may from time to time be outstanding, if any, holders of our common stock are entitled to receive ratably dividends when, as, and if declared by the board of directors out of funds legally available therefor and, upon the liquidation, dissolution or winding up of the company, are entitled to share ratably in all assets remaining after payment of liabilities and payment of accrued dividends and liquidation preferences on the preferred stock, if any. There are no redemption or sinking fund provisions that are applicable to our common stock. Subject only to the requirements of the DGCL, the board of directors may issue shares of our common stock without stockholder approval, at any time and from time to time, to such persons and for such consideration as the board of directors deems appropriate. Holders of our common stock have no preemptive rights and have no rights to convert their common stock into any other securities. The outstanding common stock is validly authorized and issued, fully paid, and nonassessable.

Preferred Stock

We are authorized to issue up to 5,000,000 shares of preferred stock, par value $.01 per share. Shares of preferred stock may be issued from time to time in one or more series as the board of directors, by resolution or resolutions, may from time to time determine, each of said series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the DGCL, the board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series of preferred stock.

The issuance of any such preferred stock could adversely affect the rights of the holders of our common stock and therefore, reduce the value of the common stock. The ability of the board of directors to issue preferred stock could discourage, delay, or prevent a takeover of us. See “Risk Factors.”

Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our certificate of incorporation and our bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Preferred stock. Our certificate of incorporation permits our board of directors to authorize and issue one or more series of preferred stock, which may render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary

obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent stockholder or stockholder group.

Stockholder meetings. Our bylaws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the President, or upon the request of a majority of our board of directors or the holders of not less than sixty-six percent of our outstanding shares entitled to vote at such a special meeting.

Requirements for advance notification of stockholder nominations and proposals. Our bylaws and certificate of incorporation establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors.

Amendment of the bylaws. Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Both our certificate of incorporation and bylaws grant our board of directors and stockholders the power to adopt, amend and repeal our bylaws.

Removal of Directors. Our bylaws provide that members of our board of directors may only be removed for cause and only by the affirmative vote of holders of at least 66% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

The provisions of our certificate of incorporation and bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is UMB Bank, N.A.

UNDERWRITING

We and the selling stockholders have entered into an underwriting agreement with the underwriters named below with respect to the shares being offered. Subject to the terms and conditions of the underwriting agreement, the underwriters named below have severally agreed to purchase from the selling stockholders the number of shares of our common stock set forth opposite their names on the table below at the public offering price, less the underwriting discounts and commissions shown on the cover page of this prospectus as follows:


Name		Number of Shares
Johnson Rice & Company L.L.C.		3,630,000
Dahlman Rose & Company, LLC		605,000
First Albany Capital Inc.		605,000
Pritchard Capital Partners, LLC		605,000
Simmons & Company International		605,000

Total		6,050,000

The underwriting agreement provides that the underwriters’ obligation to purchase shares of our common stock depend on the satisfaction of the conditions contained in the underwriting agreement. The conditions contained in the underwriting agreement include the condition that the representations and warranties made by us and the selling stockholders to the underwriters are true, that there has been no material adverse change to our condition or in the financial markets and that we and the selling stockholders deliver to the underwriters customary closing documents. The underwriters are obligated to purchase all of the shares of common stock (other than those covered by the over-allotment option described below) if they purchase any of the shares.

The underwriters propose to offer the shares of common stock to the public at the public offering price set forth on the cover of this prospectus. The underwriters may offer the common stock to securities dealers at the price to the public less a concession not in excess of $0.47 per share. After the shares of common stock are released for sale to the public, the underwriters may vary the offering price and other selling terms from time to time.

We have granted to the underwriters an option, exercisable for 30 days from the date of the underwriting agreement, to purchase up to 907,500 additional shares at the public offering price per share less the underwriting discounts and commissions shown on the cover page of this prospectus. The underwriters may exercise this option solely to cover over-allotments, if any, made in connection with this offering.

The following table summarizes the compensation to be paid to the underwriters by the selling stockholders, and by us, assuming the underwriters’ option is fully exercised, in connection with this offering.


			Total
	Per Share		Without Over- allotment		With Over- allotment

Public offering price by the selling stockholders	$	14.00	$	84,700,000		—
Underwriting fees to be paid by the selling stockholders	$	0.77	$	4,658,500		—
Proceeds, before expenses, to the selling stockholders	$	13.23	$	80,041,500		—

Public offering price by us	$	14.00		—	$	12,075,000
Underwriting fees to be paid by us	$	0.77		—	$	698,775
Proceeds, before expenses, to us	$	13.23		—	$	12,006,225

We estimate our expenses associated with the offering, excluding underwriting discounts and commissions, will be approximately $500,000.

We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the federal securities laws, or to contribute to payments that may be required to be made in respect of these liabilities.

We, our officers and directors, and the selling stockholders and certain of their affiliates have agreed that, for a period of 90 days from the date of this prospectus, we and they will not, without the prior written consent of Johnson Rice & Company L.L.C., directly or indirectly, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any share of common stock or any securities convertible into or exercisable or exchangeable for common stock, or file any registration statement under the Securities Act of 1933 with respect to any of the foregoing or enter into any swap or any other agreement or transaction that transfers, in whole or in part, directly or indirectly, the economic consequence of ownership of the common stock, except for the sale to the underwriters in this offering, the issuance by us of any securities or options to purchase common stock under existing, amended or new employee benefit plans maintained by us and the filing of or amendment to any registration statement related to the foregoing, the issuance by us of securities in exchange for or upon conversion of our outstanding securities described herein, the filing of or an amendment to any registration statement pursuant to registration rights held by third parties not subject to a lock-up agreement or certain transfers in the case of officers, directors or other stockholders in the form of bona fide gifts, intra family transfers and transfers related to estate planning matters. Notwithstanding the foregoing, if (1) during the last 17 days of such 90-day restricted period we issue an earnings release or (2) prior to the expiration of such 90-day restricted period we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day restricted period, the foregoing restrictions shall continue to apply until the expiration of the 90-day period beginning on the issuance of the earnings release; provided, however, that this sentence will not apply if, as of the expiration of the restricted period, shares of our common stock are “actively-traded securities” as defined in Regulation M. The underwriters have advised us that they do not have any present intent to release the lock-up agreements prior to the expiration of the applicable restricted period.

The underwriters may engage in over-allotment, stabilizing transactions, syndicate covering transactions, penalty bids and passive market making in accordance with Regulation M under the Securities Exchange Act of 1934, as amended. Over-allotment involves syndicate sales in excess of the offering size, which creates a syndicate short position. Covered short sales are sales made in an amount not greater than the number of shares available for purchase by the underwriters under their over-allotment option. The underwriters may close out a covered short sale by exercising their over-allotment option or purchasing shares in the open market. Naked short sales are sales made in an amount in excess of the number of shares available under the over-allotment option. The underwriters must close out any naked short sale by purchasing shares in the open market. Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. Syndicate covering transactions involve purchases of the shares of common stock in the open market after the distribution has been completed in order to cover syndicate short positions. Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the shares of common stock originally sold by such syndicate member is purchased in a syndicate covering transaction to cover syndicate short positions. Penalty bids may have the effect of deterring syndicate members from selling to people who have a history of quickly selling their shares. In passive market making, market makers in the shares of common stock who are underwriters or prospective underwriters may, subject to certain limitations, make bids for or purchases of the shares of common stock until the time, if any, at which a stabilizing bid is made. These stabilizing transactions, syndicate covering transactions and penalty bids may cause the price of the shares of common stock to be higher than it would otherwise be in the absence of these transactions. The underwriters are not required to engage in these activities, and may end any of these activities at any time.

LEGAL MATTERS

The validity of the shares of common stock to be offered hereby will be passed upon by Akin Gump Strauss Hauer & Feld LLP. Certain legal matters will be passed upon for the underwriters by Porter & Hedges, L.L.P.

EXPERTS

The balance sheet of Gulfport Energy Corporation as of December 31, 2005 and the related statements of operations, stockholders’ equity and comprehensive income and cash flows for each of the two years in the period ended December 31, 2005 appearing in Gulfport’s Annual Report on Form 10-KSB for the year ended December 31, 2005 have been audited by Grant Thornton LLP, independent registered public accounting firm, as set forth in their report with respect thereto. Such financial statements have been incorporated herein by reference in reliance upon the authority of such firm as experts in accounting and auditing.

Information included in this prospectus regarding the estimated quantities of oil and natural gas reserves and the discounted present value of future pre-tax cash flows therefrom is based upon estimates of such reserves and present values prepared by or derived from estimates included in our Annual Report on Form 10-KSB for the year ended December 31, 2005, prepared by NSAI and incorporated herein by reference. All of such information has been so included herein in reliance upon the authority of such firm as experts in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC, a registration statement on Form S-3 under the Securities Act, covering the securities offered by this prospectus. This prospectus does not contain all of the information that you can find in that registration statement and its exhibits. Certain items are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information with respect to us and the common stock offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance such statement is qualified by reference to each such contract or document filed with or incorporated by reference as part of the registration statement. We file reports, proxy and information statements and other information with the SEC. You may read any materials we have filed with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is http://www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

The SEC allows us to “incorporate by reference” into this prospectus the information we provide in other documents filed by us with the SEC. The information incorporated by reference is an important part of this prospectus. Any statement contained in a document that is incorporated by reference in this prospectus is automatically updated and superseded if information contained in this prospectus, or information that we later file with the SEC, modifies and replaces this information. We incorporate by reference the following documents that we have filed with the SEC (other than those furnished pursuant to Item 2.02 or Item 7.01 on Form 8-K):

•

Annual Report on Form 10-KSB for the fiscal year ended December 31, 2005, filed on March 31, 2006.

•

Current Report on Form 8-K filed on January 17, 2006.

•

Current Report on Form 8-K filed on February 14, 2006.

•

Current Report on Form 8-K filed on March 7, 2006.

•

Current Report on Form 8-K filed on April 26, 2006.

In addition, all documents filed by us with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (other than those furnished pursuant to Item 2.02 or Item 7.01 on Form 8-K) after the date of this prospectus and prior to the termination of this offering, will be considered to be incorporated by reference into this prospectus and to be a part of this prospectus from the dates of the filing of such documents.

You may get copies of this prospectus or any of the incorporated documents (excluding exhibits, unless the exhibits are specifically incorporated) at no charge to you by writing or calling Joel H. McNatt, General Counsel, at Gulfport Energy Corporation, 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134, or call (405) 242-4404.

Appendix A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

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

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Coalbed methane (CBM). Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by non-traditional means.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Gross acres. The total acres in which a working interest is owned.

Identified drilling locations. Total gross locations specifically identified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

A-1

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mbo. Thousand barrels of oil.

Mboe. Thousand barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

MMbo. Million barrels of oil.

MMboe. Million barrels of oil equivalent.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest (NRI). An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

PDNP. Proved developed non-producing.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

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

PUD. Proved undeveloped.

Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Proved developed reserves (PDP). Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

PV-10. Present value of future net revenues.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

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

Standardized Measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest (WI). The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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6,050,000 Shares

LOGO

Common Stock

P R O S P E C T U S

Johnson Rice & Company L.L.C.

Dahlman Rose & Company

First Albany Capital

Pritchard Capital Partners, LLC

Simmons & Company International

April 28, 2006