Company Quick10K Filing
Crimson Exploration
10-Q 2013-06-30 Filed 2013-08-08
10-Q 2013-03-31 Filed 2013-05-08
10-K 2012-12-31 Filed 2013-03-15
10-Q 2012-09-30 Filed 2012-11-07
10-Q 2012-06-30 Filed 2012-08-08
10-Q 2012-03-31 Filed 2012-05-09
10-K 2011-12-31 Filed 2012-03-13
10-Q 2011-09-30 Filed 2011-11-09
10-Q 2011-06-30 Filed 2011-08-11
10-Q 2011-03-31 Filed 2011-05-12
10-K 2010-12-31 Filed 2011-03-18
10-Q 2010-09-30 Filed 2010-11-10
10-Q 2010-06-30 Filed 2010-08-05
10-Q 2010-03-31 Filed 2010-05-11
10-K 2009-12-31 Filed 2010-03-16

GULF 10K Annual Report

Part I
Item 1. Business
Item 1A. Risk Factors
Item 2. Properties
Item 3. Legal Proceedings
Part II
Item 5. Market for Our Common Stock
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants and Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors and Executive Officers of The Registrant
Item 11. Executive Compensation
Item 12. Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions
Item 14. Principal Accountant Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules.
Part I. Financial Information
Item 1. Financial Statements.
EX-21.1 ex21_1.htm
EX-23.1 ex23_1.htm
EX-23.2 ex23_2.htm
EX-31.1 ex31_1.htm
EX-31.2 ex31_2.htm
EX-32.1 ex32_1.htm
EX-32.2 ex32_2.htm
EX-99.1 ex99_1.htm

Crimson Exploration Earnings 2009-12-31

Balance SheetIncome StatementCash Flow
3753002251507502012201220132014
Assets, Equity
40322416802012201220132014
Rev, G Profit, Net Income
3020100-10-202012201220132014
Ops, Inv, Fin

10-K 1 form10k.htm FORM 10K-2009 form10k.htm




UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K

 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2009
 
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934

Commission file number:  000-21644

CRIMSON EXPLORATION INC.
 (Exact name of registrant as specified in its charter)

Delaware
 
20-3037840
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
     
717 Texas Avenue, Suite 2900
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)
(713) 236-7400
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act: None
 
Securities registered pursuant to Section 12(g) of the Act:  Common Stock, $0.001 par value per share
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes o No x
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.   Yes o No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
 
As of June 30, 2009, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $12,936,996 based on the closing sales price of $4.00 of the Registrant’s common stock.  For purposes of this computation, all executive officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates.  Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.
 
On March 9, 2010, there were 38,515,302 shares of common stock outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of our Definitive Proxy Statement for the 2010 Annual Meeting, expected to be filed within 120 days of our fiscal year end, are incorporated by reference into Part III.
 
 

 

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We make forward-looking statements throughout this Annual Report within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

These forward-looking statements include, but are not limited to, statements regarding:

 
·
estimates of proved reserve quantities and net present values of those reserves;
 
 
·
reserve potential;
 
 
·
business strategy;
 
 
·
estimates of future commodity prices;
 
 
·
amounts, timing and types of capital expenditures and operating expenses;
 
 
·
expansion and growth of our business and operations;
 
 
·
expansion and development trends of the oil and gas industry;
 
 
·
acquisitions of natural gas and crude oil properties;
 
 
·
production of crude oil and natural gas reserves;
 
 
·
exploration prospects;
 
 
·
wells to be drilled and drilling results;
 
 
·
operating results and working capital; and
 
 
·
future methods and types of financing.

Whenever you read a statement that is not simply a statement of historical fact (such as when we describe what we “believe,” “expect” or “anticipate” will occur, and other similar statements), you must remember that our expectations may not be correct, even though we believe they are reasonable.  We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.  We do not guarantee that the transactions and events described in this Annual Report will happen as described (or that they will happen at all).  The forward-looking information contained in this Annual Report is generally located in the material provided under the headings “Business,” “Risk Factors,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well.  These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results and trends.  For a discussion of risk factors affecting our business, see “Risk Factors.”

 
1

 

PART I
 
ITEM 1.     Business
 
Company Overview

Crimson is an independent energy company engaged in the acquisition, exploitation, exploration and development of natural gas and crude oil properties.  We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have recently expanded our strategic focus to include longer reserve life resource plays that we believe provide significant long-term growth potential in multiple formations.

We intend to grow reserves and production by developing our existing producing property base, developing our East Texas and South Texas resource potential, and pursuing opportunistic acquisitions in areas where we have specific operating expertise.  We have developed a significant project inventory of 824 gross drilling locations associated with our existing property base.  Our technical team has a successful track record of adding reserves through the drillbit.  Since January 2008, we have drilled 34 gross (15.2 net) wells with an overall success rate of 91%.

As of December 31, 2009, our estimated proved reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc., were 97.5 Bcfe, net of 7.6 Bcfe of reserves sold in December 2009, consisting of 69.9 Bcf of natural gas and 4.6 MMBbl of crude oil, condensate and natural gas liquids.  As of December 31, 2009, 72% of our proved reserves were natural gas, 70% were proved developed and 86% were attributed to wells and properties operated by us.  During the last three years, we have grown proved reserves from 46.4 Bcfe to 97.5 Bcfe.  In addition, our average daily production increased from 7.3 MMcfe/d for the twelve months ended December 31, 2006 to 40.9 MMcfe/d for the twelve months ended December 31, 2009.

Our areas of primary focus include the following:

 
·
East Texas.  Our East Texas region includes approximately 17,300 gross (12,000 net) acres acquired in 2008 and 2009 in the highly prospective and active resource play in San Augustine and Sabine Counties, where we will focus primarily on the pursuit of the Haynesville Shale, Mid-Bossier Shale and James Lime formations.  In October 2009, we participated in our first well in this area, a 52% working interest in the Devon Energy-operated Kardell #1H, a successful well in the Haynesville shale.  While drilling this well, we also identified additional prospective formations, including the Pettet and Knowles Lime.  During 2010, we intend to drill 7 gross (3.1 net) horizontal wells in this region.

 
·
Southeast Texas.  Our Southeast Texas region includes approximately 27,100 gross (15,100 net) acres in the Felicia field area in Liberty County, and in Madison and Grimes Counties. As of December 31, 2009, we owned and operated 26 gross (20 net) producing wells, representing approximately 39% of our average daily production for the twelve months of 2009.  Our interests in non-operated producing wells in this area also contributed an additional 7% of our average daily production for the twelve months of 2009.  During 2010, we plan to drill 4 gross (2.4 net) wells in this region in Liberty County.

 
·
South Texas.  Our South Texas region includes approximately 2,800 gross (1,200 net) acres in Bee County, which we believe to be prospective in the Austin Chalk and Eagle Ford Shale.  Our conventional operations in this area include approximately 87,400 gross (51,600 net) acres predominantly in Brooks, Lavaca, DeWitt, Zapata, Webb and Matagorda Counties.  As of December 31, 2009, we owned and operated 88 gross (69 net) producing wells, representing approximately 27% of our average daily production for the twelve months of 2009.  Our interests in non-operated producing wells in the area also contributed an additional 15% of our average daily production for the twelve months of 2009.  During 2010, we intend to drill 1 gross (0.4 net) horizontal well in this region to test the Eagle Ford shale.

 
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We also own interests in the following areas:

 
·
Colorado and Other.  This region includes primarily producing assets and approximately 16,900 gross (11,900 net) acres in the Denver Julesburg Basin in Colorado (mostly in Adams County) and a minor crude oil property in Mississippi.

 
·
Southwest Louisiana.  Our Southwest Louisiana region, after the sale of substantially all of our operated and certain non-operated properties in the region in December 2009, includes approximately 3,700 gross (760 net) acres, primarily in the Fenton field area of Calcasieu Parish.  In addition, we own a 15% working interest ownership in the 2007 exploratory well at West Cameron 432.

The following table sets forth certain information with respect to our estimated proved reserves as of December 31, 2009, as estimated by Netherland, Sewell & Associates, Inc., and net production and net acreage for the twelve months ended December 31, 2009.  The following table also identifies potential drilling locations as of December 31, 2009:

Region
Estimated Proved Reserves as of December 31, 2009 (MMcfe)
 
% Natural Gas
 
% Proved Developed
 
Average Daily Production for the Twelve Months Ended December 31, 2009 (Mcfe/d)
 
Net acreage at December 31, 2009
 
Identified Potential Gross Drilling Locations at December 31, 2009(1)
Southeast Texas
27,108
 
55.6%
 
84.9%
 
15,927
 
15,111
 
26
South Texas
49,186
 
79.0%
 
57.2%
 
11,018
 
52,755
 
125
East Texas(2)
1,596
 
100.0%
 
100.0%
 
836
 
11,944
 
422
Colorado and Other
5,221
 
66.2%
 
45.2%
 
556
 
11,877
 
181
Southwest Louisiana(3)
 
 
 
2,857
 
759
 
Non-operated(3)(4)
14,378
 
75.6%
 
93.8%
 
9,714
 
 
70
Total
97,489
 
71.7%
 
70.3%
 
40,908
 
92,446
 
824

 
(1)
Includes multiple drilling locations on acreage with multiple target formations.
 
(2)
We recently completed our first well on our East Texas acreage, the Kardell #1H, as a horizontal Haynesville Shale producer, in which we own a 52% working interest.  Drilling locations in this region were calculated assuming multiple independent potential formations and 120 acre spacing per potential horizontal East Texas location.
 
(3)
On December 28, 2009, we closed on the sale of substantially all of our operated and certain non-operated Southwest Louisiana properties.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Southwest Louisiana Disposition.”
 
(4)
Our non-operated properties consist primarily of our 25% working interest in the Samano field in Starr and Hidalgo Counties in South Texas, our 28% working interest in certain fields in Liberty County in Southeast Texas and our 15% working interest in West Cameron 432.

We have significantly increased our proved reserves and production through acquisitions and drilling since our recapitalization in early 2005.  In 2007, we tripled our reserve size through the acquisition from EXCO Resources, Inc. ("EXCO") of producing properties in the South Texas, Southeast Texas and Southwest Louisiana regions, adding an aggregate of approximately 95 Bcfe to our net proved reserves at a cost of $2.50 per Mcfe of proved reserves as of the effective date.  We added 21 Bcfe to our South Texas proved reserves through the Smith Production Inc. ("Smith") acquisition in 2008 at an average cost of $2.82 per Mcfe of proved reserves as of the closing date.  Our acquisitions are focused on areas in which we can leverage our geographic and geological expertise to exploit those drilling opportunities identified at the time of the acquisition and develop an inventory of additional drilling prospects that we believe will enable us to grow production and add reserves.  We intend to continue to pursue the acquisition of assets in our core areas, to continue to selectively expand our presence and exploit our positions in our East Texas and South Texas resource plays and to continue to develop exploratory opportunities through our internal prospect generation team.

During the latter half of 2008 and the full year 2009, we acquired approximately 12,000 net acres in San Augustine and Sabine Counties in East Texas, which we believe to be prospective in the Haynesville Shale, Mid-Bossier, and James Lime formations.  We have identified 422 drilling locations on our acreage targeting these formations alone.  Recent activity in the area indicates that the Pettet and Knowles Lime formations also appear

 
3

 

prospective.  We have separated our acreage into several joint development areas (“JDAs”) of varying sizes and are working with other industry players holding acreage positions in those areas to jointly develop our positions.  Our “Bruin” prospect, on which our first well, the Kardell #1H was drilled, is one such JDA.  We and Devon Energy Corporation, the operator, each contributed approximately 330 acres to the JDA in San Augustine County and drilled the Kardell #1H well.  Given the success we have had on the Kardell #1H well, we will allocate a large portion of our drilling capital budget to develop this resource play further for the next several years.

Offices

We currently lease and sublease, through January 31, 2014, 54,939 square feet of executive and corporate office space located at 717 Texas Avenue in downtown Houston, Texas.  Rent, including parking, related to this office space for the twelve months ended December 31, 2009 was approximately $2.2 million.  Effective January 1, 2010, we have subleased to a subtenant for approximately one year, 27,144 square feet of this space for a total rental of approximately $1.0 million.

Strategy

The key elements of our business strategy are:

 
·
Develop our East Texas resource play.  We have approximately 12,000 net acres in San Augustine and Sabine Counties of East Texas, which we believe is prospective in the Haynesville Shale, Mid-Bossier Shale, James Lime, Pettet and Knowles Lime formations.  We commenced our first well (the Kardell #1H, 52% working interest) in this play in late June 2009 and completed that well in October 2009.  We believe the Kardell #1H confirms the potential of our Bruin Prospect, which is comprised of approximately 3,000 net acres in San Augustine County, resulting in over 100 potential drilling locations in multiple formations.  We are currently in the planning stages for several wells in this area and intend to further evaluate and exploit these multiple formations in 2010.  We have an additional 8,944 net acres within Sabine and San Augustine Counties, and we expect to drill our initial well on that acreage in early 2010.  We intend to allocate a substantial portion of our capital budget over the next several years to develop the significant potential that we believe exists on our East Texas acreage.  We currently have budgeted for 2010 7 gross (3.1 net) wells that will target the Haynesville and Mid-Bossier Shales, while retaining future development opportunities in shallower formations.

 
·
Develop our South Texas resource play.  We have approximately 2,800 gross (1,200 net) acres in Bee County, Texas which we believe is prospective in the Austin Chalk and Eagle Ford Shale.  We drilled our first well on this acreage, the Dubose #1, during the fourth quarter of 2009.  It was completed as a vertical well in the first quarter of 2010.  The well flowed 600 Mcf per day at 2,400 psi flowing tubing pressure on an 8/64” choke after a small fracture stimulation.  The well is currently shut-in due to limited production facilities.  Crimson is encouraged by the results from the Dubose #1 and the potential of a future Eagle Ford horizontal well, which we currently have planned for the second half of 2010.

 
·
Exploit our existing producing property base to generate cash flows.  We believe our multi-year drilling inventory of high return exploitation opportunities on our existing conventional producing properties provides us with a solid platform to continue growing our reserves and production for the next several years.  We believe these projects, if successful, will allow us to fund a larger portion of our resource plays and exploration activities from cash flows from operations.  In 2010, we intend to focus much of our exploitation drilling on our Liberty County acreage, located in Southeast Texas.  We will be targeting the Yegua and Cook Mountain formations in which we experienced an 82% success rate on 11 wells drilled in 2008 and in which industry participants have recently experienced success on wells in the area.  We own 3D seismic that covers substantially all of our Liberty County acreage, giving us a higher degree of confidence in the potential in this area.  During 2010, we intend to drill 4 gross (2.4 net) wells in this area.


 
4

 

 
·
Explore in defined producing trends.  Our exploration activities consist primarily of step-out drilling in known, producing formations in our legacy areas of South and Southeast Texas.  In 2007, we began acquiring seismic data to use in identifying new exploration prospects.  Currently, we have a library of over 4,200 square miles of 3D seismic data and over 2,500 linear miles of 2D seismic data.

 
·
Make opportunistic acquisitions that meet our strategic and financial objectives.  We may continue to seek to acquire natural gas and crude oil properties, including both undeveloped and developed reserves in areas where we have specific operating expertise.

 
·
Reduce commodity exposure through hedging.  We employ the use of swaps and costless collar derivative instruments to limit our exposure to commodity prices.  As of December 31, 2009, we had 11.6 Bcfe of equivalent production hedged, representing 6.1 Bcf and 3.2 Bcf of natural gas hedges in place and 250 MBbl and 124 MBbl of crude oil hedges in place for 2010 and 2011, respectively.  The average floor prices of our natural gas and crude oil hedges in place are $7.71/MMBtu and $83.02/Bbl in 2010 and $7.32/MMBtu and $66.50/Bbl in 2011.

Our Employees
 
On March 9, 2010, we had 74 full time employees, of which 20 were field personnel.  We have been able to attract a very talented team of industry professionals from our industry peers that have been successful in achieving significant growth and success in the past.  As such, we are well-positioned to adequately manage and develop our existing assets and also to increase our proved reserves and production through exploitation and exploration drilling.  None of our employees are covered by collective bargaining agreements.  We believe our relationship with our employees is good.

Government Regulation and Industry Matters

Federal and State Regulatory Requirements

We are a public company subject to the rules and regulations of the Securities and Exchange Commission ("SEC").  Recently enacted and proposed changes in the laws and regulations affecting public companies, including the provisions of the Sarbanes-Oxley Act of 2002 and rules adopted by the SEC, have resulted in increased costs to us.  The new rules could make it more difficult for us to obtain certain types of insurance, including director and officer liability insurance, and we may be forced to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage.  The impact of these events could also make it more difficult for us to attract and retain qualified persons to serve on our board of directors, our board committees or as executive officers.

Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the release of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require that we acquire permits before commencing drilling; restrict the substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; or require remedial measures to mitigate pollution from current or former operations.  Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties.  These laws and regulations have been changed frequently in the past.  In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance.  It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly different from those we currently expect.  Existing laws and regulations could be changed or reinterpreted, and any such changes or interpretations could have an adverse effect on our business.

Industry Regulations

The availability of a ready market for natural gas, crude oil and natural gas liquids production depends upon numerous factors beyond our control.  These factors include regulation of natural gas, crude oil and natural gas liquids production, federal and state regulations governing environmental quality and pollution control, state limits

 
5

 

on allowable rates of production by well or proration unit, the amount of natural gas, crude oil and natural gas liquids available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels.  For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations.  State and federal regulations generally are intended to prevent waste of natural gas, crude oil and natural gas liquids, protect rights to produce natural gas, crude oil and natural gas liquids between owners in a common reservoir, control the amount of natural gas, crude oil and natural gas liquids produced by assigning allowable rates of production and control contamination of the environment.  Pipelines are subject to the jurisdiction of various federal, state and local agencies.  We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.  The following discussion summarizes the regulation of the United States oil and gas industry.  We believe that we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although there can be no assurance that this is or will remain the case.  Moreover, such statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and there can be no assurance that such changes or reinterpretations will not materially adversely affect our results of operations and financial condition.  The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

Regulation of Natural Gas, Crude Oil and Natural Gas Liquids Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels.  Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling of crude oil and natural gas properties.  In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases.  In areas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project, if the operator owns less than 100% of the leasehold.  In addition, state conservation laws which establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these regulations may limit the amount of natural gas, crude oil and natural gas liquids we can produce from our wells and may limit the number of wells or the locations at which we can drill.  The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability.  Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price of natural gas produced by us, and the manner in which such production is transported and marketed.  Under the Natural Gas Act, or NGA, of 1938, the Federal Energy Regulatory Commission, or the FERC, regulates the interstate transportation and the sale in interstate commerce for resale of natural gas.  Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act, or the Decontrol Act, deregulated natural gas prices for all “first sales” of natural gas, including all sales by us of our own production.  As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect.  However, the Decontrol Act did not affect the FERC’s jurisdiction over natural gas transportation.

Under the provisions of the Energy Policy Act of 2005, or the 2005 Act, the NGA has been amended to prohibit market manipulation by any person, including marketers, in connection with the purchase or sale of natural gas, and the FERC has issued regulations to implement this prohibition.  The Commodity Futures Trading Commission, or CFTC, also holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas.  With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market

 
6

 

manipulation laws and related regulations enforced by FERC and/or the CFTC.  These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation.

Under the 2005 Act, the FERC has also established regulations that are intended to increase natural gas pricing transparency through, among other things, new reporting requirements and expanded dissemination of information about the availability and prices of gas sold.  To the extent that we enter into transportation contracts with interstate pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such interstate capacity.  Any failure on our part to comply with the FERC’s regulations or an interstate pipeline’s tariff could result in the imposition of civil and criminal penalties.

Our natural gas sales are affected by intrastate and interstate gas transportation regulation.  Following the Congressional passage of the Natural Gas Policy Act of 1978, or the NGPA, the FERC adopted a series of regulatory changes that have significantly altered the transportation and marketing of natural gas.  Beginning with the adoption of Order No. 436, issued in October 1985, the FERC has implemented a series of major restructuring orders that have required pipelines, among other things, to perform “open access” transportation of gas for others, “unbundle” their sales and transportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to other shippers.  As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties.  We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.  It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business.  We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities.  We do not believe that we will be affected by any such new or different regulations materially differently than any other seller of natural gas with which we compete.

In the past, Congress has been very active in the area of gas regulation.  However, as discussed above, the more recent trend has been in favor of deregulation, or “lighter handed” regulation, and the promotion of competition in the gas industry.  There regularly are other legislative proposals pending in the Federal and state legislatures that, if enacted, would significantly affect the petroleum industry.  At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us.  Similarly, and despite the trend toward federal deregulation of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas.  Again, we do not believe that we will be affected by any such new legislative proposals materially differently than any other seller of natural gas with which we compete.

Oil Price Controls and Transportation Rates

Sales prices of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices.  Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission, or the FTC, prohibiting manipulative or fraudulent conduct in the wholesale petroleum market.  The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of up to $1 million per day per violation.  Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.

The price we receive from the sale of these products may be affected by the cost of transporting the products to market.  Much of the transportation is through interstate common carrier pipelines.  Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations.  The FERC’s regulation of crude oil transportation rates may tend to increase the cost of transporting crude oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year.  Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry.  In March 2006, to implement the second of the required five-yearly re-determinations, the FERC established an upward adjustment in the index to track oil pipeline cost changes.  The FERC determined that the Producer Price Index for Finished Goods plus 1.3 percent (PPI plus 1.3 percent) should be the oil pricing index for the five-year period beginning July 1, 2006.  We are not able at this time to predict the effects of these regulations or

 
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FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.

Environmental Regulations

Various federal, state and local authorities regulate our operations with regard to air and water quality, release of substances and other environmental matters.  These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from current or former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations.  In addition, various laws and regulations require that well, pipeline, and facility sites be abandoned and reclaimed.  Public interest in the protection of the environment has increased dramatically in recent years.  The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.  To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

We generate wastes that may be subject to the federal Resource Conservation and Recovery Act, as amended, or the RCRA, and comparable state statutes.  The U.S. Environmental Protection Agency, or the EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes.  Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as “hazardous wastes,” and therefore be subject to more rigorous and costly operating and disposal requirements.

We currently own or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas.  Although we believe that we have used good operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for recycling or disposal.  In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control.  These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, as amended, or the CERCLA, RCRA and analogous state laws as well as state laws governing the management of crude oil and natural gas wastes.  Under such laws, which impose strict, joint and several liability, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

Our operations may be subject to the Clean Air Act, as amended, or the CAA, and comparable state and local requirements.  Amendments to the CAA adopted in 1990 contain provisions that have resulted in the gradual imposition of pollution control requirements with respect to air emissions from our operations.  The EPA and states developed and continue to develop regulations to implement these requirements.  We may be required to incur capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.  However, we do not believe our operations will be materially adversely affected by any such requirements.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, which would establish an economy-wide cap-and-trade program to reduce “greenhouse gas” emissions, including carbon dioxide and methane by 17 percent from 2005 levels by the year 2020 and 80 percent by the year 2050.  The U.S. Senate is considering a number of comparable measures.  One such measure, the Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been reported out of the Senate Committee on Energy and Natural Resources, but has not yet been considered by the full Senate and also includes a cap-and-trade system for controlling greenhouse gas emissions in the United States.  Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases.  The number of emission allowances issued each year

 
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would decline as necessary to meet overall emission reduction goals.  As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.  The ultimate outcome of these bills remains uncertain, and such bills would have to undergo reconciliation before being adopted as law.  Any laws or regulations that may be adopted to restrict or reduce emissions of U.S. greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.  In addition, at least 20 states have already taken legal measures to control emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  In California, for example, the California Global Warming Solutions Act of 2006 requires the California Air Resources Board to adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020.

Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of crude oil or natural gas we produce.  Although we would not be impacted to a greater degree than other similarly situated producers of natural gas, crude oil and natural gas liquids, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the crude oil and natural gas we produce.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate carbon dioxide, or CO2, emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities.  On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change.  On September 15, 2009, the EPA proposed a rule in anticipation of finalizing its findings to reduce emissions of greenhouse gases from motor vehicles, which rule is expected to be adopted in March 2010.  Additionally, while the EPA’s proposed findings do not specifically address stationary sources, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.  On September 23, 2009, the EPA finalized a greenhouse gas reporting rule establishing a national greenhouse gas emissions collection and reporting program.  The EPA rules will require covered entities to measure greenhouse gas emissions commencing in 2010 and submit reports commencing in 2011.  On September 30, 2009, the EPA proposed new thresholds for greenhouse gas emissions that define when CAA permits under the New Source Review, or NSR, and Title V operating permits programs would be required.  Under the Title V operating permits program, the EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide CO2e (carbon dioxide equivalency) for existing industrial facilities.  Facilities with greenhouse gas emissions below this threshold would not be required to obtain an operating permit.  Under the Prevention of Significant Deterioration, or PSD, portion of the NSR, the EPA is proposing a major stationary source threshold of 25,000 tpy CO2e.  This threshold level would be used to determine if a new facility or a major modification at an existing facility would trigger PSD permitting requirements.  The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e.  Existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.  The EPA is requesting comment on a range of values in this proposal, with the intent of selecting a single value for the greenhouse gas significance level.  These proposals, along with new federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the crude oil and natural gas we produce.

The U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the FRAC Act, to amend the federal Safe Drinking Water Act, or the SDWA, to repeal an exemption from regulation for hydraulic fracturing.  If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities.  If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements.  The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific

 
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chemicals used in the fracturing process could adversely affect groundwater.  Although the legislation is still being developed, we do not expect the FRAC Act to have a material effect on our business because we contract out all of our hydraulic fracturing work due to the specialized nature of the activity and the extensive capital investment required.

Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil to prepare and implement spill prevention, control, and countermeasure, or the SPCC, and response plans relating to the possible discharge of crude oil into surface waters.  SPCC plans at our producing properties were developed and implemented in 1999.  In December 2008, the EPA amended the SPCC rule.  On November 5, 2009, the EPA signed a notice amending certain requirements of the SPCC regulations to address concerns from the regulatory community raised since the release of the December 2008 amendments.  The new SPCC rule is expected to be effective January 14, 2010.  Although the EPA has not yet issued a final notice containing the new rules, it is clear that there will be changes impacting oil production facilities.  These changes should not have a material adverse effect on us.  The Oil Pollution Act of 1990, as amended, or the OPA, contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.  The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters.  Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.  Our operations are also subject to the federal Clean Water Act, as amended, or the CWA, and analogous state laws.  In accordance with the CWA, the state of Louisiana has issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997.  Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground.

CERCLA, also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment.  These potentially responsible persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site.  Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and 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.

We also are subject to a variety of federal, state and local permitting and registration requirements relating to the protection of the environment.  Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse effect on us.

Title to Properties

We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and gas industry.  Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties.  As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records).  Detailed investigations, including a title opinion rendered by a licensed attorney, are typically made before commencement of drilling operations.

We have granted mortgage liens on substantially all of our crude oil and natural gas properties to secure our revolving credit agreement and second lien credit agreement.  These mortgages and the credit agreements contain substantial restrictions and operating covenants that are customarily found in credit agreements of this type.  See Note 10 — “Debt" for further information.


 
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Marketing

We sell a significant portion of our natural gas production to purchasers pursuant to sales agreements which contain a primary term of up to two years and crude oil production to purchasers under sales agreements with primary terms of up to one year.  The sales prices for natural gas are tied to industry standard published index prices, subject to negotiated price adjustments, while the sale prices for crude oil are tied to industry standard posted prices subject to negotiated price adjustments.

Our purchasers are engaged in the natural gas and crude oil business throughout the world.  Historically, we have been dependent upon a few purchasers for a significant portion of our revenue.  For the years ended December 31, 2009, 2008 and 2007, our top ten purchasers collectively represented approximately 72%, 71% and 73% of total revenues, respectively. Our three largest purchasers in 2009 accounted for 28%, 9% and 7% of total revenues, respectively. This concentration of purchasers may increase our overall exposure to credit risk, and our purchasers will likely be similarly affected by changes in economic and industry conditions. Our financial condition and results of operations could be materially adversely affected if one or more of our significant purchasers fails to pay us or ceases to acquire our production on terms that are favorable to us or at all.  However, we believe our current purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Competition

The oil and gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources.  Many of these companies explore for, produce and market crude oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis.  The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining purchasers and transporters for the crude oil and natural gas we produce.  There is also competition between producers of crude oil and natural gas and other industries producing alternative energy and fuel.  Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations.  Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing gas and crude oil and may prevent or delay the commencement or continuation of a given operation.  The effect of these risks cannot be accurately predicted.

Insurance Matters

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive.  A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations or cash flows.

Executive Officers
 
See Item 9. “Directors and Executive Officers of the Registrant,” which information is incorporated herein by reference.

 
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ITEM 1A.  Risk Factors
 
Risks Related to Our Business
 
Natural gas, crude oil and natural gas liquids prices are volatile, and a decline in prices can significantly affect our financial results and impede our growth.

Our revenue, cash flow from operations and future growth depend upon the prices and demand for natural gas, crude oil and natural gas liquids.  The markets for these commodities are very volatile.  Even relatively modest drops in prices can significantly affect our financial results and impede our growth.  Changes in natural gas, crude oil and natural gas liquids prices have a significant impact on the value of our reserves and on our cash flow.  In addition, periods of sustained lower prices may compel us to reduce our capital expenditures and budget for drilling.  Prices for natural gas, crude oil and natural gas liquids may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, crude oil and natural gas liquids and a variety of additional factors that are beyond our control, such as:

 
·
the domestic and foreign supply of natural gas, crude oil and natural gas liquids;

 
·
the price of foreign imports;

 
·
worldwide economic conditions;

 
·
political and economic conditions in oil producing countries, including the Middle East and South America;

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

 
·
the level of consumer product demand;

 
·
weather conditions;

 
·
technological advances affecting energy consumption;

 
·
availability of pipeline infrastructure, treating, transportation and refining capacity;

 
·
domestic and foreign governmental regulations and taxes; and

 
·
the price and availability of alternative fuels.

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

Our East Texas leases must be drilled before expiration, generally within three years, in order to hold the leases by production.  In the highly competitive market for Haynesville Shale acreage, failure to drill sufficient wells timely to hold this acreage will result in a substantial renewal cost, or if renewal is not feasible, loss of lease investment and prospective drilling opportunities in the Haynesville Shale, as well as in the Mid-Bossier Shale, James Lime, Pettet and Knowles Lime formations.

Our East Texas leases have three year terms which require that an initial producing well be drilled prior to expiration date or the lease will terminate.  Most of our leases in this area were signed in late 2008.  Generally, once an initial well is drilled and completed as a producer, the lease is extended for the duration of production subject to payment of royalties and additional wells may be drilled on that lease.  During 2010, we intend to devote approximately 68% of our capital expenditure budget to this region.  The leases in this area are extremely

 
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fragmented and much of the leased acreage is not contiguous.  In many cases, contiguous leases owned by us are not large enough to accommodate horizontal drilling to the Haynesville Shale, which usually involves a horizontal lateral of between 4,000 to 5,000 feet within lease lines.  In other cases, leases may be from fractional interest land owners and may not comprise a sufficient aggregate percentage working interest to make such a well economical.  As a result, in order to realize the drilling opportunities in the Haynesville Shale, Mid-Bossier Shale, James Lime, Pettet and Knowles Lime formations, we and other similarly situated major lease owners and operators in East Texas will need to cooperate and negotiate joint drilling operations to drill initial wells prior to lease expirations.  These negotiations may include the right to act as operator for jointly owned wells.  If we do not reach agreements with other major lease owners and operators to drill wells prior to lease expirations, or if we are unable to drill timely sufficient wells to hold our acreage, we will lose the drilling opportunities and investment in the expiring leases unless we can successfully negotiate to renew the leases.  We may not be able to renew the expired leases, or if renewed, the cost of releasing could be substantial, particularly if development in this area proves successful.

Part of our strategy involves drilling in new or emerging plays; therefore, our drilling results in these areas are not certain.

The results of our drilling in new or emerging plays, such as in our East Texas resource play, are more uncertain than drilling results in areas that are more developed and have established production.  Since new or emerging plays and new formations have limited or no production history, we are less able to use past drilling results in those areas to help predict our future drilling results.  Accordingly, our drilling results are subject to greater risks in these areas and could be unsuccessful.  To the extent we are unable to execute our expected drilling program in these areas, because of disappointing drilling results, capital constraints, lease expirations, access to adequate gathering systems or pipeline take-away capacity, availability of drilling rigs and other services or otherwise, and/or natural gas, crude oil and natural gas liquids price declines, our return on investment may not be as attractive as we anticipate and our common stock price may decrease.  We could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future if our drilling results are unsuccessful.

The results of our planned drilling in our East Texas and South Texas resource plays, which are newly emerging plays with limited drilling and production history, are subject to more uncertainties than our drilling program in our more established areas of operation in the onshore South Texas and U.S. Gulf Coast regions and may not meet our expectations for reserves or production.

In October 2009, we completed drilling our first well in the Haynesville Shale in East Texas, for which we were not operator, and in late January 2010, we completed a vertical test well in Bee County, South Texas in the Eagle Ford Shale.  The presence of the Haynesville Shale in the East Texas area where we own leases was determined after the activity in the north Louisiana portion of the Haynesville Shale play and, therefore is not yet as defined.  Part of our drilling strategy to maximize recoveries from the Haynesville Shale involves the drilling of horizontal wells using completion techniques that have proven to be successful in other shale formations.  Our direct experience with horizontal drilling of these shale plays is limited.  The ultimate success of these drilling and completion strategies and techniques in these formations will be better evaluated over time as more wells are drilled and production profiles are better established.  Accordingly, the results of our future drilling in the emerging shale plays are more uncertain than drilling results in our more established areas of operation with established reserves and production history.

Initial production rates in shale plays, and particularly in the Haynesville Shale, tend to decline steeply in the first twelve months of production and are not necessarily indicative of sustained production rates.

Initial production rates in shale plays, and particularly in the Haynesville Shale, tend to decline steeply in the first twelve months of production and are not necessarily indicative of sustained production rates.

 
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Our development and exploration operations, including on our East Texas resource play acreage, require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.

The oil and gas industry is capital intensive.  We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas, crude oil and natural gas liquids reserves.  We intend to finance our future capital expenditures primarily with cash flow from operations and borrowings under our revolving credit agreement.  Our cash flow from operations and access to capital is subject to a number of variables, including:

 
·
our proved reserves;

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

 
·
the prices at which natural gas, crude oil and natural gas liquids are sold; and

 
·
our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower natural gas, crude oil and natural gas liquids prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to further develop and exploit our current properties, or for exploratory activity.  In order to fund our capital expenditures, we may need to seek additional financing.  Our credit agreements contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders.  Our lenders may withhold this consent in their sole discretion.  In addition, if our borrowing base is redetermined resulting in a lower borrowing base under our revolving credit agreement, we may be unable to obtain financing otherwise available under our revolving credit agreement.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital resources.”

Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us, or at all.  In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly.  Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers.  The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.

The impairment of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry specifically, with members of our bank group.  These transactions could expose us to credit risk in the event of default of our counterparty.  We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges.  We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business.  In addition, if any lender under our credit agreement is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit agreement.

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business.

As of December 31, 2009, we had outstanding debt of $191.0 million under our credit agreements.  Our substantial level of indebtedness increases the possibility that we may be unable to pay, when due, the principal of, interest on, or other amounts due in respect of our indebtedness.  Our substantial indebtedness, combined with our other financial obligations and contractual commitments, could have other important consequences, including the following:

 
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·
funds available for our operations and general corporate purposes or for capital expenditures will be reduced as a result of the dedication of a portion of our consolidated cash flow from operations to the payment of the principal and interest on our indebtedness;

 
·
we may be more highly leveraged than certain of our competitors, which may place us at a competitive disadvantage;

 
·
certain of the borrowings under our debt agreements have floating rates of interest, which causes us to be vulnerable to increases in interest rates;

 
·
our degree of leverage could make us more vulnerable to downturns in general economic conditions;

 
·
our ability to plan for, or react to, changes in our business and the industry in which we operate may be limited; and

 
·
our ability to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, investments, debt service requirements and other general corporate requirements may be reduced.

In addition, our revolving credit agreement and second lien credit agreement contain a number of significant covenants that place limitations on our activities and operations, including those relating to:

 
·
creation of liens;

 
·
hedging;

 
·
mergers, acquisitions, asset sales or dispositions;

 
·
payments of dividends;

 
·
incurrence of additional indebtedness; and

 
·
certain leases and investments outside of the ordinary course of business.

Our credit agreements require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests.  Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests.  These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary or desirable corporate activities.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could also result in a default under our credit agreements.  A default, if not cured or waived, could result in all of our indebtedness becoming immediately due and payable.  If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital resources” for further information regarding future compliance with these covenants.  Even if new financing were then available, it may not be on terms that are acceptable to us.  See “—Recent market events and conditions, including disruptions in the U.S. and international credit markets and other financial systems and the deterioration of the U.S. and global economic conditions, could, among other things, impede access to capital or increase the cost of capital, which would have an adverse effect on our ability to fund our working capital and other capital requirements” and “—Our development and exploration operations, including on our East Texas resource play acreage, require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.”

 
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Changes to current laws may affect our ability to take certain deductions.

Substantive changes to the existing federal income tax laws have been proposed that, if adopted, would affect, among other things, our ability to take certain deductions related to our operations, including depletion deductions, deductions for intangible drilling and development costs and deductions for United States production activities.  These changes, if enacted into law, could negatively affect our financial condition and results of operations.

Recent changes in the financial and credit markets may impact economic growth and natural gas, crude oil and natural gas liquids prices may continue to be adversely affected by general economic conditions.

Based on a number of economic indicators, global economic activity slowed substantially in recent years.  A continued slowing of global economic growth or lack of significant improvement in the global economy (and, in particular, in the United States) will likely reduce demand for natural gas, crude oil and natural gas liquids, which in turn could likely result in lower prices for natural gas, crude oil and natural gas liquids.  NYMEX settlement prices for natural gas and crude oil prices dropped dramatically from record levels of approximately $13 per MMbtu and $145 per barrel, respectively, in July 2008 to below $3 per MMbtu in August 2009 and below $34 per barrel in December 2008.  While prices have improved from those low levels, a reduction in demand for, and the resulting lower prices of, natural gas, crude oil and natural gas liquids could adversely affect our results of operations.

Recent market events and conditions, including disruptions in the U.S. and international credit markets and other financial systems and the deterioration of the U.S. and global economic conditions, could, among other things, impede access to capital or increase the cost of capital, which would have an adverse effect on our ability to fund our working capital and other capital requirements.

Recent market events and conditions, including unprecedented disruptions in the credit and financial markets and the deterioration of economic conditions in the U.S. and internationally have had a significant material adverse impact on a number of financial institutions and have limited access to capital and credit for many companies.  These disruptions could, among other things, make it more difficult for us to obtain, or increase our cost of obtaining, capital and financing for our operations.  Access to additional capital may not be available on terms acceptable to us or at all.  Difficulties in obtaining capital and financing or increased costs for obtaining capital and financing for our operations would have an adverse effect on our ability to fund our working capital and other capital requirements.

We have incurred net losses in the past and there can be no assurance that we will be profitable in the future.

We have incurred net losses in three of the last five fiscal years.  We cannot assure you that our current level of operating results will continue or improve.  Our activities could require additional debt or equity financing.  Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of natural gas, crude oil and natural gas liquids, rates of production, timing of capital expenditures and drilling success.  Negative changes in these variables could have a material adverse effect on our business, financial condition, results of operations and the market value of our common stock.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions could materially reduce the estimated quantities and present value of our reserves.

The process of estimating natural gas, crude oil and natural gas liquids reserves is complex.  It requires interpretations of available technical data and many estimates, including estimates based upon assumptions relating to economic factors.  Any significant inaccuracies in these interpretations or estimates could materially reduce the estimated quantities and present value of reserves shown in this Annual Report.  See “Item 1. Business” for information about our natural gas, crude oil and natural gas liquids reserves.

In order to prepare our estimates, we must project production rates and timing of development expenditures.  We must also analyze available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary.  The process also requires economic assumptions about matters such as natural gas,

 
16

 

crude oil and natural gas liquids prices, drilling and operating expenses, the amount and timing of capital expenditures, taxes and the availability of funds.

Actual future production, natural gas, crude oil and natural gas liquids prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, crude oil and natural gas liquids reserves most likely will vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas, crude oil and natural gas liquids prices and other factors, many of which are beyond our control.

Approximately 30% of our total estimated proved reserves at December 31, 2009 were proved undeveloped reserves.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.  The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves.  Although cost and reserve estimates attributable to our natural gas, crude oil and natural gas liquids reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated.

The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas, crude oil and natural gas liquids reserves.

You should not assume that the present value of future net revenues from our proved reserves referred to in this Annual Report is the current market value of our estimated natural gas, crude oil and natural gas liquids reserves.  In accordance with the requirements of the SEC, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the estimate, held flat for the life of the properties.  Actual future prices and costs may differ materially from those used in the present value estimate.  The present value of future net revenues from our proved reserves as of December 31, 2009 was based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009.  For crude oil and natural gas liquids volumes, the average West Texas Intermediate posted price was $57.65 per barrel.  For natural gas volumes, the average Henry Hub spot price was $3.87 per MMBtu.  If crude oil prices were $1.00 per Bbl lower than the price used, our PV-10 as of December 31, 2009 would have decreased from $176.4 million to $174.4 million.  If natural gas prices were $0.10 per Mcf lower than the price used, our PV-10 as of December 31, 2009, would have decreased from $176.4 million to $172.4 million.  Any adjustments to the estimates of proved reserves or decreases in the price of crude oil or natural gas may decrease the value of our common stock.  PV-10 is a non-GAAP financial measure.  A reconciliation of our Standardized Measure of Discounted Net Cash Flows to PV-10 is provided under "Item 2. Properties — Proved Reserves".

Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and changes in governmental regulations or taxation.  The timing of both the production and the incurrence of expenses in connection with the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves.  In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor.  The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of natural gas, crude oil and natural gas liquids.  In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the results of our drilling operations.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are uncertain.  For example, we have over 4,200 square miles of 3D data in the South Texas and Gulf Coast regions and including 1,130 square miles of 3D data in the Lobo trend in South Texas that our internal prospect generation team uses to develop drilling opportunities in these areas.  However, even when used and properly interpreted, 3D seismic

 
17

 

data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators.  They do not allow the interpreter to know if hydrocarbons are present or producible economically.  Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our professionals.

In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses due to such expenditures.  As a result, our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve.

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

Our drilling and operating activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs.  Drilling for natural gas, crude oil and natural gas liquids can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit.  In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 
·
unusual or unexpected geological formations and miscalculations;

 
·
pressures;

 
·
fires;

 
·
explosions and blowouts;

 
·
pipe or cement failures;

 
·
environmental hazards, such as natural gas leaks, pipeline ruptures and discharges of toxic gases;

 
·
loss of drilling fluid circulation;

 
·
title problems;

 
·
facility or equipment malfunctions;

 
·
unexpected operational events;

 
·
shortages of skilled personnel;

 
·
shortages or delivery delays of equipment and services;

 
·
compliance with environmental and other regulatory requirements;

 
·
natural disasters; and

 
·
adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life; severe damage to or destruction of property, natural resources and equipment; pollution; environmental contamination; clean-up responsibilities; loss of wells; repairs to resume operations; and regulatory fines or penalties.

Insurance against all operational risks is not available to us.  Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented.  We carry limited environmental insurance, thus, losses could occur for uninsurable or uninsured risks or in amounts in excess

 
18

 

of existing insurance coverage.  The occurrence of an event that is not covered in full or in part by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Our acquisition strategy may subject us to greater risks.

The successful acquisition of properties requires an assessment of recoverable reserves, future natural gas, crude oil and natural gas liquids prices, operating costs, potential environmental and other liabilities, and other factors beyond our control.  Such assessments are necessarily inexact and their accuracy uncertain.  In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices.  Such a review, however, will not reveal all existing or potential problems, costs and liabilities, nor will it permit us, as the buyer, to become sufficiently familiar with the properties to assess their capabilities or deficiencies fully.  We may not inspect every well and, even when an inspection is undertaken, structural and environmental problems may not necessarily be observable.

We may be unable to successfully integrate the properties and assets we acquire with our existing operations.

Integration of the properties and assets we acquire may be a complex, time consuming and costly process.  Failure to timely and successfully integrate these assets and properties with our operations may have a material adverse effect on our business, financial condition and result of operations.  The difficulties of integrating these assets and properties present numerous risks, including:

 
·
acquisitions may prove unprofitable and fail to generate anticipated cash flows;

 
·
we may need to (i) recruit additional personnel and we cannot be certain that any of our recruiting efforts will succeed and (ii) expand corporate infrastructure to facilitate the integration of our operations with those associated with the acquired properties, and failure to do so may lead to disruptions in our ongoing businesses or distract our management; and

 
·
our management’s attention may be diverted from other business concerns.

We are also exposed to risks that are commonly associated with acquisitions of this type, such as unanticipated liabilities and costs, some of which may be material.  As a result, the anticipated benefits of acquiring assets and properties may not be fully realized, if at all.

When we acquire properties, in most cases, we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities.

We generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties, and in these situations we cannot assure you that we will identify all areas of existing or potential exposure.  In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, we cannot assure you that the seller will be able to fulfill its contractual obligations.  In addition, the competition to acquire producing natural gas, crude oil and natural gas liquids properties is intense and many of our larger competitors have financial and other resources substantially greater than ours.  We cannot assure you that we will be able to acquire producing natural gas, crude oil and natural gas liquids properties that have economically recoverable reserves for acceptable prices.

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

We do not operate a significant portion of the properties in which we own an interest.  As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties.  The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues.  The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including:

 
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·
the nature and timing of drilling and operational activities;

 
·
the timing and amount of capital expenditures;

 
·
the operator’s expertise and financial resources;

 
·
the approval of other participants in drilling wells; and
 
 
·
the operator’s selection of suitable technology.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Market conditions or the unavailability of satisfactory natural gas, crude oil and natural gas liquids transportation arrangements may hinder our access to natural gas, crude oil and natural gas liquids markets or delay our production.  The availability of a ready market for our natural gas, crude oil and natural gas liquids production depends on a number of factors, including the demand for and supply of natural gas, crude oil and natural gas liquids and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties.  Our failure to obtain such services on acceptable terms could materially harm our business.  Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities.  Such restrictions on our ability to sell our natural gas, crude oil and natural gas liquids may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production.

Unless we replace our natural gas, crude oil and natural gas liquids reserves, our reserves and production will decline, which would adversely affect our cash flows, our ability to raise capital and the value of our common stock.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced.  Producing natural gas, crude oil and natural gas liquids reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  Our future natural gas, crude oil and natural gas liquids reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.  The value of our common stock and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production.  We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.

The potential lack of availability or high cost of drilling rigs, equipment, supplies, personnel and crude oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

When the prices of natural gas, crude oil and natural gas liquids increase, we typically encounter an increase in the cost of securing drilling rigs, equipment and supplies.  In addition, larger producers may be more likely to secure access to such equipment by offering more lucrative terms.  If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our results of operation and financial condition.


 
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Our hedging activities could result in financial losses or reduce our income.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, crude oil and natural gas liquids, as well as interest rates, we currently, and may in the future, enter into derivative arrangements for a significant portion of our natural gas, crude oil and/or natural gas liquids production and our debt that could result in both realized and unrealized hedging losses.  We utilize financial commodity price hedge instruments to minimize exposure to declining prices on our crude oil, natural gas and natural gas liquids production.  As of December 31, 2009, we had 11.6 Bcfe of equivalent production hedged representing 6.1 Bcf and 3.2 Bcf of natural gas hedges in place and 250 MBbl and 124 MBbl of crude oil hedges in place for 2010 and 2011, respectively.  We typically use a combination of swaps and costless collars.  The average floor price of our natural gas and crude oil hedges in place is $7.71/MMBtu and $83.02/Bbl in 2010 and $7.32/MMBtu and $66.50/Bbl in 2011.  As of December 31, 2009, we had entered into interest rate swap agreements with a total notional amount of $200.0 million related to our indebtedness.  Under our interest rate swap agreements, we receive interest at a floating rate equal to one-month LIBOR and pay interest at a fixed rate of 1.50% for $50.0 million and pay interest at 2.90% for $150.0 million.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period.  If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended.  If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity.  As a result of our interest rate swap agreements, we may fail to benefit when rates fall, to the extent we have agreed to pay interest at a fixed rate, or face a greater degree of exposure when rates increase, to the extent we have agreed to pay interest at a floating rate.  As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Competition in the oil and gas industry is intense, and many of our competitors have resources that are greater than ours.

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing natural gas, crude oil and natural gas liquids, and securing equipment and trained personnel.  Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours.  Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit.  Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment.  Also, there is substantial competition for capital available for investment in the oil and gas industry.  Our larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position.  We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

We depend on our senior management team and other key personnel.  Accordingly, the loss of any of these individuals could adversely affect our business, financial condition and the results of operations and future growth.

Our success is largely dependent on the skills, experience and efforts of our people.  The loss of the services of one or more members of our senior management team or of our other employees with critical skills needed to operate our business could have a negative effect on our business, financial conditions and results of operations and future growth.  Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel.  Competition for these types of personnel is intense and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.


 
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We are subject to complex federal, state, local and other law and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our operations are subject to complex and stringent laws and regulations.  In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities.  We may incur substantial costs in order to maintain compliance with these existing laws and regulations.  In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.  For instance, we may be unable to obtain all necessary permits, approvals and certificates for proposed projects.  Alternatively, we may have to incur substantial expenditures to obtain, maintain or renew authorizations to conduct existing projects.  If a project is unable to function as planned due to changing requirements or public opposition, we may suffer expensive delays, extended periods of non-operation or significant loss of value in a project.  All such costs may have a negative effect on our business and results of operations.

Our business is subject to federal, state and local regulations as interpreted and enforced by governmental agencies and other bodies vested with much authority relating to the exploration for, and the development, production, transportation and marketing of, natural gas, crude oil and natural gas liquids.  Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on us.

We are subject to complex existing and pending environmental laws and regulations that could give rise to substantial liabilities or otherwise adversely affect our cost, manner or feasibility of doing business.

Recent and future environmental laws and regulations, including additional federal, regional and state restrictions on greenhouse gas (“GHG”) emissions that may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil, natural gas and natural gas liquids we produce.  The U.S. Environmental Protection Agency (“EPA”) has issued a notice of finding and determination that emission of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act.  To this end, EPA has recently issued a mandatory GHG reporting rule that will require operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually on a facility-by-facility basis. The rule will require covered entities to measure GHG emissions commencing in 2010 and submit reports commencing in 2011.  In addition, EPA has proposed a stationary source GHG permitting rule that would establish “significance levels” for major GHGs that would trigger review and permitting requirements.  Similarly, the House of Representatives has approved the “American Clean Energy and Security Act of 2009,” or “ACESA,” that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs, and the Senate is currently considering similar legislation.  At the state level, more than one-third of the states, including California, have begun taking actions either individually or through multi-state regional initiatives to control and/or reduce emissions of GHGs.  The State of California has adopted legislation that caps California's greenhouse gas emissions at 1990 levels by 2020, and the California Air Resources Board is currently developing mandatory reporting regulations and early action measures to reduce GHG emissions prior to January 1, 2012.  Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.  It is not possible, at this time, to estimate accurately how these regulations would impact our business.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process.  Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations.  This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production.  Sponsors of these bills, which are currently pending in the Energy and Commerce Committee and the Environmental and Public Works Committee of the House of Representatives and Senate, respectively, have asserted that chemicals used in the fracturing process could adversely affect drinking water

 
22

 

supplies.  The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.  In addition, this legislation, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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

We may incur substantial costs and liabilities as a result of environmental, health and safety requirements applicable to our crude oil and natural gas operations and other activities.  These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations that cover, among other things, emissions into the air and water, habitat and endangered species protection, the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground injection wells, and wetlands protection.  These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time.  Failure to comply with environmental, health and safety laws or regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining or limiting our current or future operations.  Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.  In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations.  Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs.  Therefore, the costs to comply with environmental, health, or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.  See “Item 1. Business—Environmental Regulations.”

If we are unable to successfully prevent or address material weaknesses in our internal control over financial reporting, or any other control deficiencies, our ability to report our financial results on a timely and accurate basis and to comply with disclosure and other reporting requirements may be adversely affected.

While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances.  Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all errors and all fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.  For example, for the quarter ended March 31, 2007, our management concluded that our historical documentation of related tax positions could have resulted in a material misstatement to our annual or interim financial statements and, accordingly, concluded that this deficiency was a material weakness.  Although this material weakness was subsequently remedied, if we are unable to successfully prevent or address these and other material weaknesses in our internal control systems, our ability to report our financial results on a timely and accurate basis and to comply with disclosure and other reporting requirements may be adversely affected.


 
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The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions.  ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions.  ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations.  Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform.  The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products.  The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants.  In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all over-the-counter (“OTC”) derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards.  Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements.  Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Risks Related to an Investment in Our Common Stock

One stockholder holds a significant number of our shares, which will limit your ability to influence corporate activities and may adversely affect the market price of our common stock, and that stockholder’s interests may conflict with the interests of our other stockholders.

Of the approximately 38.5 million shares of our common stock outstanding at December 31, 2009, 15.5 million shares are held by OCM GW Holdings, LLC (“Oaktree Holdings”).  As a result, Oaktree Holdings owns or controls outstanding common stock representing, in the aggregate, an approximate 40.3% voting interest in us.  As a result of this stock ownership, Oaktree Holdings will possess significant influence over matters requiring approval by our stockholders, including the adoption of amendments to our certificate of incorporation and bylaws and significant corporate transactions.  Such ownership and control may also have the effect of delaying or preventing a future change of control, impeding a merger, consolidation, takeover or other business combination or discouraging a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company.

Oaktree Holdings and its affiliates engage, from time to time in the ordinary course of their respective businesses, in the trading securities of, and investing in, energy companies.  As a result, conflicts may arise between the interests of Oaktree Holdings, on the one hand, and the interests of our other stockholders, on the other hand.  Oaktree Holdings may, from time to time, compete directly or indirectly with us or prevent us from taking advantage of corporate opportunities.  Oaktree Holdings may also pursue acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us.

The price of our common stock may fluctuate significantly, and you could lose all or part of your investment.

Volatility in the market price of our common stock price may prevent you from being able to sell your common stock at or above the price you paid for your common stock.  The market price for our common stock could fluctuate significantly for various reasons, including:

 
·
our operating and financial performance and prospects;

 
·
our quarterly or annual earnings or those of other companies in our industry;

 
24

 

 
·
conditions that impact demand for natural gas, crude oil and natural gas liquids;

 
·
future announcements concerning our business;

 
·
changes in financial estimates and recommendations by securities analysts;

 
·
actions of competitors;

 
·
market and industry perception of our success, or lack thereof, in pursuing our growth strategy;

 
·
strategic actions by us or our competitors, such as acquisitions or restructurings;

 
·
changes in government and environmental regulation;

 
·
general market, economic and political conditions;

 
·
changes in accounting standards, policies, guidance, interpretations or principles;

 
·
sales of common stock by us or members of our management team; and

 
·
natural disasters, terrorist attacks and acts of war.

In addition, in recent years, the stock market has experienced significant price and volume fluctuations.  This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industry.  The changes frequently appear to occur without regard to the operating performance of the affected companies.  Hence, the price of our common stock could fluctuate based upon factors that have little or nothing to do with our company, and these fluctuations could materially reduce our share price.

We have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

Our board of directors presently intends to retain all of our earnings for the expansion of our business; therefore, we have no plans to pay regular dividends on our common stock.  Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends, and other considerations that our board of directors deems relevant.  Also, the provisions of our revolving credit agreement and second lien credit agreement restrict the payment of dividends.  Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.

Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.

Future sales or the availability for sale of substantial amounts of our common stock in the public market could adversely affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity securities.

We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments.  If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial.  We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.

As of December 31, 2009, we had approximately 2.0 million options to purchase shares of our common stock outstanding, of which 1.2 million were vested.


 
25

 

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock.  Sales of substantial amounts of our common stock (including shares of our common stock issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

Our organizational documents may impede or discourage a takeover, which could deprive our investors of the opportunity to receive a premium for their shares.

Provisions of our certificate of incorporation and bylaws may make it more difficult for, or prevent a third party from, acquiring control of us without the approval of our board of directors.  These provisions:

 
·
permit us to issue, without any further vote or action by the stockholders, additional shares of preferred stock in one or more series and, with respect to each such series, to fix the number of shares constituting the series and the designation of the series, the voting powers (if any) of the shares of the series, and the preferences and relative, participating, optional, and other special rights, if any, and any qualification, limitations or restrictions of the shares of such series;

 
·
require special meetings of the stockholders to be called by the Chairman of the Board, the Chief Executive Officer, the President, or by resolution of a majority of the board of directors;
 
·
require business at special meetings to be limited to the stated purpose or purposes of that meeting;

 
·
require that stockholder action be taken at a meeting rather than by written consent, unless approved by our board of directors;

 
·
require that stockholders follow certain procedures, including advance notice procedures, to bring certain matters before an annual meeting or to nominate a director for election; and

 
·
permit directors to fill vacancies in our board of directors.

The foregoing factors, as well as the significant common stock ownership by Oaktree Holdings, could discourage potential acquisition proposals and could delay or prevent a change of control.

We are subject to the Delaware business combination law.

We are subject to the provisions of Section 203 of the Delaware General Corporation Law.  In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.

Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders.  Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock.  Under Section 203, a business combination between us and an interested stockholder is prohibited unless:

 
·
our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status;

 
·
upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or


 
26

 

 
·
the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.

This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock.  With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law.

We have “blank check” preferred stock.

Our certificate of incorporation authorizes the board of directors to issue preferred stock without further stockholder action in one or more series and to designate the dividend rate, voting rights and other rights preferences and restrictions.  The issuance of preferred stock could have an adverse impact on holders of common stock.  Preferred stock is senior to common stock.  Additionally, preferred stock could be issued with dividend rights senior to the rights of holders of common stock.  Finally, preferred stock could be issued as part of a “poison pill,” which could have the effect of deterring offers to acquire our company.

The holders of our common stock do not have cumulative voting rights, preemptive rights or rights to convert their common stock to other securities.

We are authorized to issue 200.0 million shares of common stock, $0.001 par value per share.  As of December 31, 2009, there were 38.5 million shares of common stock issued and outstanding.  Since the holders of our common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock present, in person or by proxy, will be able to elect all of the members of our board of directors.  The holders of shares of our common stock do not have preemptive rights or rights to convert their common stock into other securities.

ITEM 2.     Properties
 
As of December 31, 2009, we operated a majority of our producing wells and held an average 52% working interest.  Gross wells are the total wells in which we own a working interest.  Net wells are the sum of the fractional working interests we own in gross wells.  Substantially all of our properties are located onshore in Texas.  As of December 31, 2009, our properties were located in the following regions: East Texas, Southeast Texas, South Texas, Southwest Louisiana and Colorado and Other, although we separately classify all of our non-operated properties in our Non-Operated region.  Given our success in 2009 with the first well on our East Texas acreage, the Kardell #1H, we intend to allocate a substantial portion of our drilling capital budget in the next several years to the development of the significant potential that we believe exists in this area.

Proved Reserves
 
Estimates of proved reserves at December 31, 2009, 2008, and 2007 were prepared by Netherland, Sewell & Associates, Inc. (Netherland, Sewell), our independent consulting petroleum engineers in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The scope and results of their procedures are summarized in a letter which is included as an exhibit to this Annual Report on Form 10-K. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The estimated proved reserves were reviewed by our Corporate Reservoir Engineering group and by certain members of our senior management team. We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates.


 
27

 

The following tables reflect our estimated proved reserves at December 31 for each of the preceding three years.  The 2009 information reflects the disposition of substantially all of our Southwest Louisiana properties, resulting in the disposition of 7,631 MMcfe in 2009.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Southwest Louisiana Disposition.”

   
2009
   
2008
   
2007
 
Crude Oil (MBbl)
                 
Developed
    1,274       1,616       2,266  
Undeveloped
    690       948       637  
Total
    1,964       2,564       2,903  
                         
Natural Gas (MMcf)
                       
Developed
    49,075       66,712       67,997  
Undeveloped
    20,785       29,457       23,242  
Total
    69,860       96,169       91,239  
                         
Natural Gas Liquids (MBbl)
                       
Developed
    1,977       2,423       2,684  
Undeveloped
    664       976       906  
Total
    2,641       3,399       3,590  
                         
Total MMcfe
                       
Developed
    68,581       90,946       97,697  
Undeveloped
    28,908       41,001       32,500  
Total
    97,489       131,947       130,197  
                         
Proved developed reserves percentage
    70 %     69 %     75 %
PV-10 (in millions)
  $ 176.4     $ 291.0     $ 531.4  
Estimated reserve life (in years)
    7.1       6.9       9.8  
Prices utilized in estimates:
                       
Natural gas ($/MMBtu)
  $ 3.87     $ 5.71     $ 6.80  
Crude oil ($/Bbl)
  $ 57.65     $ 41.00     $ 92.50  


Under new SEC rules, prices used in determining our proved reserves as of December 31, 2009 are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted).  Prior to the new rules, natural gas prices were based on the Henry Hub spot price at year end and crude oil prices were based upon the West Texas Intermediate posted price at year end.  All prices, under both sets of rules, are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.  Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules.  Use of the new 12-month average pricing rules at December 31, 2009 resulted in proved reserves of approximately 97,489 MMcfe and PV-10 of $176.4 million.  Use of the old year-end pricing rules would have resulted in proved reserves of approximately 114,633 MMcfe at December 31, 2009 and PV-10 of $305.0 million.


 
28

 

PV-10

PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and productions costs, discounted at 10% per annum to reflect timing of future cash flows and using pricing assumptions in effect at the end of the period.  PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes.  Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our natural gas and crude oil properties.  PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.  The following table provides a reconciliation of our Standardized Measure to PV-10:

   
December 31,
 
   
2009
   
2008
   
2007
 
         
(in millions)
       
Standardized measure of discounted net cash flows
$
176.4
 
$
260.9
 
$
399.5
 
Present value of future income taxes discounted at 10%
 
   
30.1
   
131.9
 
PV-10
$
176.4
 
$
291.0
 
$
531.4
 

The following table reflects our estimated proved reserves by category as of December 31, 2009.

   
Crude Oil (MBbl)
   
Natural Gas (MMcf)
   
Natural Gas Liquids (MBbl)
   
Total (MMcfe)
   
% of Total Proved
   
PV-10
 
                                 
(In millions)
 
Proved developed producing
    812       35,198       1,413       48,551       49.8 %   $ 101.7  
Proved developed non-producing
    462       13,877       564       20,031       20.5 %     38.8  
Proved undeveloped
    690       20,785       664       28,907       29.7 %     35.9  
Total
    1,964       69,860       2,641       97,489       100.0 %   $ 176.4  

Our estimated net proved reserves as of December 31, 2009, were approximately 71.7% natural gas, 16.2% natural gas liquids and 12.1% crude oil and condensate.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 7.1 years based on our proved reserves as of December 31, 2009 and production for the twelve months ended December 31, 2009, excluding the production associated with the Southwest Louisiana properties that were sold in December 2009.  During 2009, 3 gross (1.65 net) operated wells and 3 gross (0.87 net) non-operated wells were drilled, all of which were successes.  We also drilled one gross (0.52  net) non-operated well in our East Texas acreage, which was a success.  In 2010, we currently expect to drill 12 gross (5.9 net) wells.  Also, as of December 31, 2009, we had identified 41 proved undeveloped drilling locations and 783 other unproved drilling locations.

Proved Developed Reserves

From December 31, 2008 to 2009, total proved developed reserves decreased from 90.9 Bcfe to 68.6 Bcfe.  Of the decrease in proved developed reserves, 14.9 Bcfe was a result of 2009 production, 4.0 Bcfe was the result of negative price revisions, 2.0 Bcfe was the result of negative performance revisions and 3.3 Bcfe was attributable to the sale of our producing properties in Southwest Louisiana.  We expect to recover substantially all of the reserves lost to price changes with improvement in future pricing assumptions.  Offsetting the decrease in reserves were new proved developed reserves added of 2.1 Bcfe from drilling.

Proved Undeveloped Reserves

From December 31, 2008 to 2009, total proved undeveloped reserves decreased from 41.0 Bcfe to 28.9 Bcfe.  Of the decrease in proved undeveloped reserves, 7.1 Bcfe was the result of negative price revisions, 4.4 Bcfe was attributable to the sale of our producing properties in Southwest Louisiana and 0.6 Bcfe related to other reserve

 
29

 

revisions.  We expect to recover substantially all of the reserves lost to price changes with improvement in future pricing assumptions.

Due to the low natural gas price environment in 2009 and limited capital availability, we did not actively pursue development of any of our undeveloped locations in 2009.  Our 2010 plans include development of one or more undeveloped locations.  All of our undeveloped locations have been added within the last five years, almost half of which were added in May 2007 with our acquisition of Gulf Coast assets from EXCO.  Our financial resources allow us the flexibility to drill all of the remaining undeveloped locations within a five year period from the time the locations were acquired.

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth as of December 31 for each of the preceding three years, the estimated future net cash flow from and standardized measure of discounted future net cash flows of our proved reserves, which were prepared in accordance with the rules and regulations of the SEC and the Financial Accounting Standards Board.  Future net cash flow represents future gross cash flow from the production and sale of proved reserves, net of crude oil, natural gas and natural gas liquids production costs (including production taxes, ad valorem taxes and operating expenses) and future development costs.  The calculations used to produce the figures in this table are based on current cost and price factors at December 31 for each year.  Future income taxes were estimated using future cash inflows, future tax depletion expense on existing producing properties and available net operating loss carryforwards that existed at year end.  We cannot assure you that the proved reserves will all be developed within the periods used in the calculations or that those prices and costs will remain constant.  A standardized measure of discounted future net cash flows is not required to be presented for interim financial presentation dates.

   
2009
   
2008
   
2007
 
                   
Future cash inflows
  $ 475,007,800     $ 749,121,400     $ 1,125,374,500  
Future production and development costs:
                       
Production
    156,581,500       214,969,100       258,028,900  
Development
    55,021,500       86,068,300       65,779,100  
Future cash flows before income taxes
    263,404,800       448,084,000       801,566,500  
Future income taxes
          (46,695,950 )     (198,920,968 )
Future net cash flows after income taxes
    263,404,800       401,388,050       602,645,532  
10% annual discount for estimated timing of cash flows
    (86,982,100 )     (140,485,818 )     (203,122,453 )
Standardized measure of discounted future net cash flows
  $ 176,422,700     $ 260,902,233     $ 399,523,079  

 
Under new SEC rules, prices used in determining our proved reserves as of December 31, 2009 are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted).  Prior to the new rules, natural gas prices were based on the Henry Hub spot price at year end and crude oil prices were based upon the West Texas Intermediate posted price at year end.  All prices are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.

 
30

 

 
Significant Properties
 
Summary information on our properties by region with proved reserves is provided below as of December 31, 2009.

   
Productive Wells
   
Proved Reserves
   
PV-10 (1)
Regions
 
Gross
Productive Wells
   
Net
Productive Wells
   
Crude Oil
   
Natural Gas
   
Natural Gas Liquids
   
Total
   
Amount
               
(MBbl)
   
(MMcf)
   
(MBbl)
   
(MMcfe)
      ($000)
Southeast Texas
    26.0       19.7       1,005       15,079       1,000       27,108      $ 73,749
South Texas
    88.0       69.1       431       38,860       1,290       49,186       65,481
East Texas
    1.0       0.5             1,596             1,596       2,688
Colorado & Other
    19.0       13.7       294       3,456             5,221       5,301
Non-Operated (2)
    163.0       40.2       234       10,869       351       14,378       29,204
Total
    297.0       143.2       1,964       69,860       2,641       97,489     $ 176,423

 
(1)
Under new SEC rules, prices used in determining our proved reserves as of December 31, 2009 are based upon an unweighted 12-month first day of the month average price per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted).  Prior to the new rules, natural gas prices were based on the Henry Hub spot price at year end and crude oil prices were based upon the West Texas Intermediate posted price at year end.  All prices are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.
 
(2)
On December 28, 2009, we closed on the sale of substantially all of our operated and certain non-operated Southwest Louisiana properties.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Southwest Louisiana Disposition.”


 
31

 

Production, Price and Cost History

The following table sets forth information associated with our proved reserves regarding production volumes of crude oil, natural gas and natural gas liquids and certain price and cost information as of December 31 for each of the preceding three years.  In addition, the following table includes all fields that represent 15% or more of proved reserves within our one geographical area, the United States of America:

     
2009
     
2008
     
2007
Production volumes
                     
Natural gas (Mcf):
                     
Cage Ranch Field
   
1,148,559
     
1,102,049
     
489,086
Felicia Field
   
3,858,557
     
6,394,598
     
3,735,673
Speaks Field
   
1,280,718
     
1,184,088
     
741,283
Other US
   
4,126,607
     
4,454,774
     
4,101,735
Total natural gas (Mcf)
   
10,414,441
     
13,135,509
     
9,067,777
Crude oil (Bbl):
                     
Cage Ranch Field
   
23,912
     
16,559
     
9,482
Felicia Field
   
137,545
     
228,281
     
127,996
Speaks Field
   
6,077
     
8,301
     
7,591
Other US
   
159,173
     
245,002
     
263,795
Total crude oil (Bbl)
   
326,707
     
498,143
     
408,864
Natural gas liquids (Bbl):
                     
Cage Ranch Field
   
60,959
     
51,508
     
25,114
Felicia Field
   
250,936
     
345,726
     
205,970
Speaks Field
   
14,839
     
25,251
     
162
Other US
   
99,361
     
93,867
     
54,661
Total natural gas liquids (Bbl)
   
426,095
     
516,352
     
285,907
                       
Total (Mcfe)
   
14,931,253
     
19,222,479
     
13,236,403
Average sales price (1)
                     
Natural gas per mcf:
                     
Cage Ranch Field
 
$
4.13
   
$
8.65
   
$
6.30
Felicia Field
   
4.04
     
9.12
     
6.86
Speaks Field
   
3.81
     
7.89
     
6.26
Other US
   
3.92
     
8.99
     
6.86
Total natural gas per mcf
   
3.97
     
8.92
     
6.78
Crude oil per barrel:
                     
Cage Ranch Field
 
$
49.45
   
$
90.87
   
$
79.70
Felicia Field
   
54.20
     
104.01
     
77.52
Speaks Field
   
50.75
     
106.14
     
80.53
Other US
   
60.77
     
98.97
     
72.48
Total crude oil per barrel
   
56.99
     
101.13
     
74.38
Natural gas liquids per barrel:
                     
Cage Ranch Field
 
$
29.52
   
$
49.97
   
$
48.93
Felicia Field
   
27.86
     
53.89
     
52.00
Speaks Field
   
15.33
     
47.07
     
61.17
Other US
   
40.33
     
53.37
     
42.52
Total natural gas liquids per barrel
   
30.57
     
53.07
     
49.92
                       
Average sales price per Mcfe
 
$
7.49
   
$
9.66
   
$
8.25
                       
Average production costs per Mcfe (2)
                     
Cage Ranch Field
 
$
1.81
   
$
2.40
   
$
2.65
Felicia Field
   
0.75
     
0.60
     
0.89
Speaks Field
   
1.40
     
1.51
     
1.37
Other US
   
1.37
     
1.42
     
0.67
Average production costs per Mcfe
   
1.16
     
1.08
     
0.91

 
(1)
Average sales prices are shown exclusive of the settled amounts of our natural gas, crude oil and natural gas liquids hedge contracts.
 
(2)
Average production cost includes natural gas, crude oil and natural gas liquids operating costs and expense workovers, and excludes production and ad valorem taxes.
 
 
 
32

 
 
Productive Wells
 
The following table shows the number of producing wells we owned by location at December 31, 2009:
 
   
Crude Oil
   
Natural Gas
 
   
Gross Wells
   
Net Wells
   
Gross Wells
   
Net Wells
 
Southeast Texas
    6       5.25       20       14.41  
South Texas
    1       0.59       87       68.51  
East Texas
                1       0.52  
Colorado & Other
    13       8.86       6       4.82  
Non-operated (1)
    15       2.80       148       37.45  
Total
    35       17.50       262       125.71  
 
 
(1)
On December 28, 2009, we closed on the sale of substantially all of our operated and certain non-operated Southwest Louisiana properties.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Southwest Louisiana Disposition.”

In addition, as of December 31, 2009, we had 118 inactive wells and 18 salt water disposal wells.

Developed and Undeveloped Acreage
 
Developed acreage is acreage spaced or assigned to productive wells.  Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would form the basis to determine whether the property is capable of production of commercial quantities of natural gas, crude oil and natural gas liquids.  Gross acres are the total acres in which we own a working interest.  Net acres are the sum of the fractional working interests we own in gross acres.  The following table shows the approximate developed and undeveloped acreage that we have an interest in, by location, at December 31, 2009.
 
   
Developed
   
Undeveloped
 
   
Gross Acres
   
Net Acres
   
Gross Acres
   
Net Acres
 
Southeast Texas
    23,283       12,818       3,865       2,293  
South Texas
    74,523       39,866       15,646       12,889  
East Texas
    512       362       16,739       11,582  
Colorado & Other
    7,370       5,185       9,560       6,692  
Southwest Louisiana (1)
    3,672       759              
Total
    109,360       58,990       45,810       33,456  
 
 
(1)
On December 28, 2009, we closed on the sale of substantially all of our operated and certain non-operated Southwest Louisiana properties.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Southwest Louisiana Disposition.”


 
33

 

Drilling Results
 
The following table shows the results of the wells drilled and completed for operated and non-operated properties for each of the last three fiscal years ended December 31, 2009.  No crude oil wells were drilled during this time period.
 
   
2009
   
2008
   
2007
 
Gross Gas Wells
                 
Development
    5       20       9  
Exploratory
    2       5       8  
Dry
          2       4  
Total
    7       27       21  
                         
Net Gas Wells
                       
Development
    2.13       10.74       1.07  
Exploratory
    0.90       1.05       1.65  
Dry
          0.80       0.72  
Total
    3.03       12.59       3.44  
 
At December 31, 2009, we had one exploratory well in progress.

Costs Incurred

The following table shows the costs incurred in our crude oil and gas producing activities for the past three years ended December 31, 2009:

   
2009
   
2008
   
2007
Property Acquisitions:
               
Proved
  $ (493,532 )   $ 60,765,315     $ 238,036,360
Unproved
    1,833,949       57,203,337       30,407,525
Development Costs
    11,398,237       86,685,192       30,814,788
Exploration Costs
    11,815,450       2,520,389       13,405,017
Total
  $ 24,554,104     $ 207,174,233     $ 312,663,690

These costs include crude oil and gas property acquisition, exploration and development activities regardless of whether the costs were capitalized or charged to expense, including lease rental expenses and geological and geophysical expenses and changes to the long-lived asset related to our asset retirement obligation.

Property Dispositions

The following table shows crude oil and gas property dispositions for the past three years ended December 31, 2009:

   
2009
   
2008
   
2007
Oil and gas properties
  $ 42,995,459     $ 21,765,688      $
Accumulated DD&A
    (23,158,221 )     (1,659,588 )    
Oil and gas properties, net
  $ 19,837,238     $ 20,106,100      $

The dispositions resulted in a net loss of $6.8 million and a net gain of $15.2 million for 2009 and 2008, respectively.


 
34

 

ITEM 3.     Legal Proceedings

From time to time, we are involved in litigation relating to claims arising out of our operations or from disputes with vendors in the normal course of business.  During the second quarter of 2009, holders of oil and gas leases in East Texas (Haynesville Shale) filed two causes of action against us alleging breach of contract for not paying lease bonuses on certain oil and gas leases taken by our leasing agent.  The damages alleged are approximately $2.4 million and we have received approximately $300,000 in written demands from other holders of leases in this area that we believe may contemplate legal proceedings.  We are vigorously defending these lawsuits, and believe we have meritorious defenses.  We do not believe that these claims will have a material adverse effect on our business, financial position, results of operations or cash flows, although we cannot guarantee that a material adverse effect will not occur.


 
35

 

PART II
 
ITEM 5.     MARKET FOR OUR COMMON STOCK

Until December 16, 2009 our common stock was traded on the Over-the-Counter Bulletin Board (the “OTCBB”) under the symbol “CXPO.OB.”  Effective December 17, 2009, our common stock began trading on the NASDAQ Global Market under the symbol “CXPO.”

The following table sets forth the range of high and low bid quotation prices per share of our common stock as reported by the OTCBB, except for the fourth quarter 2009 which was reported by NASDAQ.  The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

 
   
High
   
Low
 
2009
           
First Quarter
  $ 4.60     $ 0.80  
Second Quarter
    4.65       1.75  
Third Quarter
    4.30       2.26  
Fourth Quarter
    8.25       3.57  
                 
2008
               
First Quarter
  $ 18.50     $ 9.10  
Second Quarter
    17.50       8.20  
Third Quarter
    16.20       7.23  
Fourth Quarter
    7.43       2.85  
                 
2007
               
First Quarter
  $ 6.20     $ 5.25  
Second Quarter
    7.55       5.25  
Third Quarter
    8.35       7.15  
Fourth Quarter
    19.35       7.65  
                 


 
36

 

 
Stock Performance Chart
 
The following chart compares the yearly percentage change in the cumulative total stockholder return on our Common Stock during the five years ended December 31, 2009 with the cumulative total return of the Standard and Poor’s 500 Stock Index and of the Dow Jones U.S. Exploration and Production Index.  The comparison assumes $100 was invested on December 31, 2004 in our Common Stock and in each of the foregoing indices and assumes reinvestment of dividends.  We paid no dividends on our Common Stock during such five-year period.

Comparison of Five-Year Cumulative Total Return Among Crimson Exploration,
S&P 500 Index and the Dow Jones U.S. Exploration and Production Index
   
Crimson
   
S&P 500 Index
   
DJ US Expl & Prod Index
 
December 31, 2004
  $ 100.00     $ 100.00     $ 100.00  
December 31, 2005
  $ 98.90     $ 103.00     $ 164.11  
December 31, 2006
  $ 68.68     $ 117.03     $ 171.73  
December 31, 2007
  $ 202.20     $ 121.16     $ 244.91  
December 31, 2008
  $ 34.07     $ 74.53     $ 145.40  
December 31, 2009
  $ 48.13     $ 92.01     $ 202.12  

General

The following descriptions are summaries of material terms of our common stock, preferred stock, certificate of incorporation and bylaws.  This summary is qualified by reference to our certificate of incorporation, bylaws and the designations of our preferred stock, which are filed as exhibits to this Annual Report on Form 10-K, and by the provisions of applicable law.

Common Stock
 
We are authorized to issue up to 200.0 million shares of Common Stock, par value $0.001 per share.  As of March 9, 2010, there were 38.5 million shares of Common Stock issued and outstanding and held by approximately 275 record holders.  On December 22, 2009, all shares of preferred stock, including accumulated dividends, were converted into Common Stock in conjunction with our equity offering.  Fidelity Transfer Company, 8915 South 700 East #102, Sandy, Utah 84070, (801) 562-1300 is our current transfer agent for our Common Stock.  We will be changing our transfer agent for our Common Stock on April 1, 2010 to Continental Stock Transfer & Trust Company, 17 Battery Place, New York, NY 10004.

 
37

 

Holders of Common Stock are entitled to one vote for each share held on record on each matter submitted to a vote of stockholders and, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities (including preferential distribution and dividend rights of holders of preferred stock).  Holders of Common Stock have no cumulative rights.  The holders of a plurality of the outstanding shares of the Common Stock have the ability to elect all of the directors.

Holders of Common Stock have no preemptive or other rights to subscribe for shares.  Holders of Common Stock are entitled to such dividends as may be declared by the Board out of funds legally available therefor.  We have never paid cash dividends on the Common Stock and do not anticipate paying any cash dividends in the foreseeable future.
 
Preferred Stock
 
Our board of directors is authorized, without further stockholder action, to issue preferred stock in one or more series and to designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series.  Any preferred stock that might be issued would be senior to our Common Stock regarding liquidation.  The holders of the preferred stock do not have voting rights or preemptive rights, nor are they subject to the benefits of any retirement or sinking fund.  We are authorized to issue up to 10.0 million shares of preferred stock.  On December 22, 2009, all outstanding shares, and accumulated dividends, of preferred stock that had not previously converted were converted into Common Stock in conjunction with our public offering of Common Stock.

Share-Based Compensation
 
At December 31, 2009, we had outstanding employee stock options, under our 2004 Stock Option and Compensation Plan, to purchase 16,000 (all vested) shares of Common Stock.  On February 28, 2005, we established our 2005 Stock Incentive Plan (“2005 Plan”) and authorized the issuance of up to approximately 2.9 million shares of Common Stock pursuant to awards under the plan.  In the third quarter 2008, our Board of Directors and a majority of our stockholders approved an amendment and restatement of our 2005 Stock Incentive Plan that provided for an increase in the number of shares of Common Stock available for award under our 2005 Stock Incentive Plan to approximately 3.9 million shares.  We also issued 250,000 shares of restricted Common Stock to our executive officers outside of these plans.  Approximately 2.0 million (1.2 million vested) stock options and 1.5 million (0.2 million vested) restricted shares were outstanding at December 31, 2009.  Option awards outstanding under both plans have exercise prices ranging from $2.40 to $16.55 per share.  In 2009 and 2008, respectively, 127,243 and 85,318 shares of restricted Common Stock vested, of which 40,921 and 20,625 shares were withheld by us to satisfy the employees’ tax liability resulting from the vesting of these shares, as provided for in the restricted stock agreement, with the remaining shares being released to the employees and associated directors.  At December 31, 2009, we had approximately 0.6 million shares of Common Stock available for future grant under the 2005 Plan.

 
38

 

 
Recent Sales of Unregistered Securities
 
As shown in the table below, during 2009, 2008 and 2007 we issued Common Stock not registered under the Securities Act of 1933 (the "Act"), as amended, in transactions we believe are exempt under Section 4(2) of the Act due to the limited number of persons involved and their relationship with us or in the case of conversions, exempt under Section 3(a)(9) of the Act.  No underwriters were used, and no underwriting discounts or commissions were paid in connection with the sales.

Date
Class
Holder(s)
 
Underlying
Shares
   
Exercise/
Conversion
Price
 
Consideration
                   
12/22/2009
Common Stock
Existing Stockholders
    11,800,735     $ 5.00  
Series G Preferred Stock Conversion
                       
12/22/2009
Common Stock
Existing Stockholders
    300,001     $ 3.50  
Series H Preferred Stock Conversion
                       
7/11/2008
Common Stock
Existing Stockholders
    14,286     $ 9.00  
Series H Preferred Stock Conversion
                       
2/7/2008
Common Stock
Existing Stockholder
    34,821     $ 9.00  
Series G Preferred Stock Conversion
                       
12/20/2007
Common Stock
Existing Stockholder
    50,000     $ 80.00  
Series D Preferred Stock Conversion
                       
10/05/2007
Common Stock
Accredited Investors
    2,818    
                          NA
 
Director Compensation
                       
9/28/2007
Common Stock
Accredited Investors
    250,000    
                         NA
 
Compensation to Company’s Executive Officers
                       
5/29/2007
Common Stock
Existing Stockholder
    428,572     $ 3.50  
Series H Preferred Stock Conversion
                       
5/29/2007
Common Stock
Existing Stockholder
    291,247     $ 9.00  
Series E Preferred Stock Conversion
                       
5/8/2007
Common Stock
Accredited Investor
    750,000    
                          NA
 
EXCO Acquisition


 
39

 

We withheld the following shares of Common Stock to satisfy tax withholding obligations during the fourth quarter 2009 from the distributions described below.  These shares may be deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this item.

Period
 
Total Number of Shares Purchased (1)
   
Average price Paid Per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
   
Maximum Number (or Approximate Dollar Value) of Shares That May Be Purchased Under the Plan or Programs
 
October 1-31, 2009
    208     $ 3.70       208         (1)
November 1-30, 2009
                        (1)
December 1-31, 2009
                        (1)
Total
    208               208          
                                 

 
 
(1)
Shares were withheld from employees to satisfy certain tax withholding obligations due in connection with grants of stock under our 2005 Stock Incentive Plan.  The 2005 Stock Incentive Plan provides from the withholding of shares to satisfy tax obligations.
 
ITEM 6.     Selected Financial Data
 
The following table sets forth our selected consolidated financial data for the last five years ended as of December 31.  This data should be read in conjunction with our Consolidated Financial Statements and the accompanying notes in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Form 10-K.

   
Year Ended December 31,
 
     
2009
     
2008
     
2007
     
2006
     
2005
 
Statement of Operations Data
                                       
                                         
Operating revenues
 
$
112,447,646
   
$
186,768,273
   
$
109,543,208
   
$
21,659,481
   
$
17,682,808
 
Income (loss) from operations (1)
   
(387,836
)
   
46,095,294
     
33,616,299
     
(2,458,685
)
   
637,823
 
Net income (loss)
   
(34,069,990
)
   
46,203,218
     
(430,517
)
   
1,858,944
     
(3,543,239
)
Dividends on preferred stock
   
(4,522,645
)
   
(4,234,050
)
   
(4,453,872
)
   
(3,648,925
)
   
(3,562,472
)
Net income (loss) available to common stockholders
   
(38,592,635
)
   
41,969,168
     
(4,884,389
)
   
 (1,789,981
)
   
 (7,105,711
)
Net income (loss), per share
                                       
Basic
 
$
(4.91
)
 
$
7.81
   
$
(1.13
)
 
$
(0.55
)
 
$
(2.66
)
Diluted
 
$
(4.91
)
 
$
4.46
   
$
(1.13
)
 
$
(0.55
)
 
$
(2.66
)
Weighted average shares outstanding
                                       
Basic
   
7,861,054
     
5,371,377
     
4,330,282
     
3,231,000
     
2,673,882
 
Diluted
   
7,861,054
     
10,360,348
     
4,330,282
     
3,231,000
     
2,673,882
 

(1)
Non-cash equity-based compensation charges were $2.4 million, $5.4 million and $4.7 million, in 2009, 2008 and 2007, respectively.

 
40

 


      Year Ended December 31,  
Balance Sheet Data
      2009         2008         2007         2006         2005  
                                         
Current assets
 
$
24,710,943
   
$
46,347,553
   
$
36,481,565
   
$
4,231,983
   
$
5,825,078
 
Total assets
   
424,804,034
     
511,545,789
     
398,935,074
     
84,702,722
     
63,114,949
 
Current liabilities
   
33,486,034
     
83,989,610
     
48,879,245
     
10,932,155
     
6,855,735
 
Noncurrent liabilities
   
208,587,112
     
305,933,376
     
280,402,748
     
12,444,784
     
3,453,952
 
Stockholders’ equity
 
 
182,730,888
     
121,622,803
     
69,653,081
     
61,325,783
     
52,805,262
 

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

You should read the following discussion of our results of operations and financial condition with the “Selected Historical Consolidated Financial Data” and the historical financial statements and related notes included elsewhere in this Annual Report.  This discussion contains forward-looking statements and involves numerous risks and uncertainties, including, but not limited to, those described in the “Risk Factors” section of this Annual Report.  Actual results may differ materially from those contained in any forward-looking statements.

Overview

Crimson is an independent energy company engaged in the acquisition, exploitation, exploration and development of natural gas and crude oil properties.  We have historically focused our operations in the onshore U.S. Gulf Coast and South Texas regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have recently expanded our strategic focus to include longer reserve life resource plays that we believe provide significant long-term growth potential in multiple formations.

In late 2008 and 2009, we acquired approximately 12,000 net acres in East Texas where we completed our first well, the Kardell #1H, in October 2009, which targeted the Haynesville Shale.  In addition to the Haynesville Shale, we believe this acreage is equally prospective in the Mid-Bossier Shale, James Lime, Pettet and Knowles Lime formations where industry participants have drilled successful wells on adjacent acreage.

In 2007, we acquired approximately 2,800 gross (1,200 net) acres in South Texas, which we believe is prospective in the Austin Chalk and the Eagle Ford Shale.  We drilled our first well on this acreage, the Dubose #1, during the fourth quarter of 2009.  It was completed as a vertical well in the first quarter of 2010.  The well flowed 600 Mcf per day at 2,400 psi flowing tubing pressure on an 8/64” choke after a small fracture stimulation.  The well is currently shut-in due to limited production facilities.  Crimson is encouraged by the results from the Dubose #1 and the potential of a future Eagle Ford horizontal well, which we currently have planned for the second half of 2010.

We intend to grow reserves and production by developing our existing producing property base, developing our East Texas and South Texas resource potential, and pursuing opportunistic acquisitions in areas where we have specific operating expertise.  We have developed a significant project inventory of 824 gross drilling locations associated with our existing property base.  Our technical team has a successful track record of adding reserves through the drillbit.  Since January 2008, we have drilled 34 gross (15.2 net) wells with an overall success rate of 91%.

As of December 31, 2009, our proved reserves, as estimated by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc., in accordance with new reserve reporting guidelines mandated by the SEC, were 97.5 Bcfe, consisting of 69.9 Bcf of natural gas and 4.6 MMBbl of crude oil, condensate and natural gas liquids.  As of December 31, 2009, 72% of our proved reserves were natural gas, 70% were proved developed and 86% were attributed to wells and properties operated by us.  During the last three years, we have grown proved reserves from 46.4 Bcfe to 97.5 Bcfe.  In addition, our average daily production increased from 7.3 MMcfe/d for the twelve months ended December 31, 2006 to 40.9 MMcfe/d for the twelve months ended December 31, 2009.


 
41

 

Recent Developments

Equity Offering

On December 22, 2009, we closed on a public offering of 20.0 million shares of Common Stock at $5.00 per share.  Cash proceeds, net of underwriting fees, of $94.0 million from this offering were used to repay $84.0 million in outstanding indebtedness under our revolving credit agreement and our $10.0 million unsecured promissory note.  Also, on December 17, 2009, we began trading our Common Stock on The NASDAQ Global Market under the ticker symbol “CXPO”.

Amendments to Revolving Credit Agreement

Effective December 7, 2009, we entered into an amendment to our revolving credit agreement that, among other things, amended certain of our financial covenants to improve our financial flexibility and redetermined our borrowing base at January 1, 2010 to $105.0 million.  See ̶