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 IV Item 15. Exhibits and Financial Statement Schedules 60
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
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 7A. Qualitative and Quantitative Disclosures About Market Risk
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 2011-12-31

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

10-K 1 form10k.htm CRIMSON EXPLORATION INC. FORM 10-K 12-31-2011 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, 2011
 
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
 
SECURITIES EXCHANGE ACT OF 1934

Commission file number:  001-12108

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 whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 x
Non-accelerated filer o
Smaller reporting company o
   
(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, 2011, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $78,042,284 based on the closing sales price of $3.55 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 5, 2012, there were 45,129,407 shares of common stock outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of our Definitive Proxy Statement for the 2012 Annual Meeting, expected to be filed within 120 days of our fiscal year-end, are incorporated by reference into Part III of this Form 10-K.

 
 

 


TABLE OF CONTENTS

PART I
Item 1.
Business
4
Item 1A.
Risk Factors
14
Item 1B.
Unresolved Staff Comments
30
Item 2.
Properties
30
Item 3.
Legal Proceedings
34
Item 4.
Mine Safety Disclosures
35

PART II
Item 5.
Market For Our Common Stock
36
Item 6.
Selected Financial Data
40
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
41
Item 7A.
Qualitative and Quantitative Disclosures About Market Risk
53
Item 8.
Financial Statements and Supplementary Data
54
Item 9.
Changes In and Disagreements with Accountants and Accounting and Financial Disclosures
54
Item 9A.
Controls and Procedures
54
Item 9B.
Other Information
55

PART III
Item 10.
Directors and Executive Officers of the Registrant
56
Item 11.
Executive Compensation
56
Item 12.
Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
56
Item 13.
Certain Relationships and Related Transactions
56
Item 14.
Principal Accountant Fees and Services
56
 
Glossary of Selected Terms
57

PART IV
Item 15.
Exhibits and Financial Statement Schedules
60


 
2

 

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;
 
 
results of borrowing base redeterminations under our revolving credit agreement;
 
 
·
future methods and types of financing; and
 
 
the risks described elsewhere in this Annual Report and in the documents incorporated by reference herein.

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.”

 
3

 

PART I
 
ITEM 1.  BUSINESS
 
Company Overview

We are 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, South Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have expanded our strategic focus to include longer reserve life resource plays in South Texas (the Eagle Ford Shale oil play), Southeast Texas (the Woodbine/Georgetown oil play) and East Texas (the Haynesville, Mid-Bossier and James Lime plays).  We believe these plays provide significant long-term growth potential from multiple formations. Additionally, we have producing properties in the DJ Basin, in Weld and Adams counties Colorado, which we believe is prospective in the Niobrara Shale oil play.  Until we see improvement in natural gas prices, we will focus almost entirely on further developing our oil and liquids weighted assets.

We intend to grow reserves and production by developing our existing producing property base, developing our oil/liquids resource potential, and pursuing opportunistic acquisitions in areas where we have specific operating expertise.  We have developed a significant project inventory associated with our existing property base that should provide the opportunity for multiyear reserve growth.  Our technical team has a successful track record of adding reserves through the drill bit.  For the period January 2008 through December 2011, we have drilled 56 gross (26.9 net) wells with an overall success rate of 93%.  In our South Texas and East Texas resource plays, we have a 100% success rate on eight and six wells, respectively.  At December 31, 2011, we had 4 wells in progress.

As of December 31, 2011, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”),our independent petroleum engineering firm, in accordance with reserve reporting guidelines mandated by the Securities and Exchange Commission (“SEC”), were 200.4 Bcfe, consisting of 162.7 Bcf of natural gas and 6.3 MMBbl of crude oil, condensate and natural gas liquids, with a PV-10 of $266.5 million, and a Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) of $255.3 million.  As of December 31, 2011, 81% of our proved reserves were natural gas, 37% were proved developed and 87% were attributed to wells and properties operated by us.  We grew proved reserves to 200.4 Bcfe at December 31, 2011 from 166.5 Bcfe at December 31, 2010.  Year-end PV-10 is a non-GAAP financial measure.  A reconciliation of our Standardized Measure to PV-10 is provided under "Item 2. Properties - Proved Reserves".

The following summary table sets forth certain information with respect to our proved reserves as of December 31, 2011, as estimated by NSAI, and net production and net acreage for the twelve months ended December 31, 2011:

Region
Estimated Proved Reserves as of December 31, 2011 (MMcfe)
 
% Natural Gas
 
% Proved Developed
 
Average Daily Production for the Twelve Months Ended December 31, 2011 (Mcfe/d)
 
Net acreage at December 31, 2011
Southeast Texas
25,264
 
61%
 
85%
 
21,122
 
32,823
South Texas
66,745
 
62%
 
57%
 
13,090
 
60,479
East Texas
101,517
 
100%
 
10%
 
10,218
 
5,993
Colorado and Other
6,843
 
69%
 
62%
 
951
 
12,778
Total
200,369
         
45,381
 
112,073


 
4

 

Areas of geographic focus as of December 31, 2011 are shown on the map below:

Areas of Geographic Focus
            Our areas of primary focus include the following:
 
 
·
South Texas.  At December 31, 2011, our South Texas region included approximately 100,700 gross (60,500 net) acres, proven reserves of 66,745 MMcfe, and 282 gross (150 net) producing wells.
 
Approximately 18,400 gross (8,625 net) acres are prospective in the oil window of the Eagle Ford Shale, 89% of which is held by production.  We began development of the Eagle Ford in Bee County in 2010, and in Karnes and Zavala Counties in 2011. We have proven reserves of 16,174 MMcfe comprised of 86% liquids with  9 gross (4 net) producing wells,   Our 2012 capital budget includes approximately $23 million to drill 5 gross (2.9 net) wells in the Eagle Ford.

The remaining 93,000 gross (55,800 net) acres in South Texas are located in our conventional fields that produce primarily from the Wilcox, Frio, and Vicksburg sands.  We have proven reserves of 50,571 MMcfe comprised of 77% gas with 173 gross (146 net) producing wells.

·  
Southeast Texas.  At December 31, 2011, our Southeast Texas region included approximately 47,300 gross (32,800 net ) acres, proven reserves of 25,264 MMcfe, and 72 gross (39 net) producing wells. The Company has actively developed this area since 2008, primarily focused on the Yegua and Cook Mountain sands in Liberty County. In 2012, the Company has shifted its focus to the horizontal development of its Woodbine potential in Madison and Grimes counties, where there has recently been significant industry activity offset to our leasehold.  Our 2012 capital budget includes approximately $38 million for the drilling of 9 gross (6.5 net) horizontal Woodbine wells.

 
    ·
East Texas.  At December 31, 2011, our East Texas region included approximately 8,500 gross (6,000 net) acres, proven reserves of 101,517 MMcfe comprised of 100% gas, and 10 gross (4 net) producing wells. The Company has actively developed the Haynesville and Mid Bossier Shales in this area since 2009.  Approximately 68% of our acreage is now held by production with the majority of the remainder lease terms expiring in 2012 and 2013. The Company has no plans to drill in the area in 2012 due to low natural gas prices,

We also own interests in the following areas:

 
    ·
Colorado and Other.  This region includes approximately 20,100 gross (12,800 net) acres in the Denver Julesburg Basin in Colorado (mostly in Adams and Weld Counties), small non-operating working interests in the Fenton field area of Calcasieu Parish, Louisiana and a minor crude oil property

 
5

 

in Mississippi.  There has been a surge in activity in 2011 in the area of our Colorado acreage in pursuit of the Niobrara oil formation.  The vast majority of our acreage in this area is held by production, so we will monitor the 2012 industry activity and results of our peers in the Niobrara to develop our strategy for maximizing the value of our position in the area.

We intend to continue to selectively pursue the acquisition of assets in our core areas to expand our presence in our South Texas and Southeast Texas resource plays to exploit our oil and liquids rich positions in all of our regions, and continue to develop exploitation opportunities on our conventional properties.  Acquisition efforts will typically be 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.

Our 2012 current capital budget is approximately $73.9 million, exclusive of acquisitions, if any.  We plan to drill 14 gross (9.4 net) wells in 2012, 4 of which are already in progress. The actual number of wells drilled and the amount of our 2012 capital expenditures will depend on market conditions, availability of capital and drilling and production results.

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 and net of sublease rent, related to this office space for the twelve months ended December 31, 2011 was approximately $1.3 million.  Effective January 1, 2010, we subleased 27,144 square feet of this space to a third party for a total rental of approximately $86,000 per month through September 30, 2011.

Strategy

The key elements of our business strategy are:

·  
Enhance our portfolio by shifting capital to our oil and liquids rich opportunities.  During 2012 we will continue to pursue a drilling program that is designed to develop our multiple oil and liquids rich opportunities in proven, active areas. While we have a significant amount of unproved potential in our East Texas Haynesville/Mid-Bossier natural gas play, due to the low natural gas environment and superior economics from oil production, we have allocated all of our 2012 capital budget to oil-weighted opportunities.
 
·  
Develop our South Texas resource play.  During 2012, we expect to drill 3 wells in our Karnes and Zavala County areas, targeting the Eagle Ford oil window, and 2 wells in the Eagle Ford gas/condensate window in Bee County.  We will have separate rigs drilling in Karnes County and Zavala/Dimmitt for most of the first quarter of 2012.  If market conditions and success in the area warrant it, further acceleration of drilling could occur in the Zavala/Dimmit area, requiring additional capital that could be funded from our existing revolving credit agreement.  We currently plan to allocate substantial capital over the next several years to developing the oil and natural gas liquids resource potential we believe exists on our South Texas acreage.
 
·  
Pursue the developing Woodbine/Georgetown horizontal oil redevelopment play in our Madisonville Field in Madison and Grimes counties, Texas.  We have approximately 21,130 gross, (16,180 net) acres in Madison and Grimes counties from which we have historically focused primarily on maximizing existing production from conventional wells.  Recent horizontal drilling for oil by other operators in the Woodbine formation, adjacent to our acreage, has been very successful.  Based on those results, we believe that large portions of our asset base in the area are prospective for horizontal redevelopment of the Woodbine, Georgetown, Lewisville and other formations.  We currently plan to drill 9 wells on our acreage during 2012.
 
·  
Colorado Niobrara Shale.  Our activities in Colorado have historically been limited to the production of small amounts of oil and gas from the D & J Sands in Weld and Adams Counties.  Recent industry activity in the area has proven that the application of horizontal drilling technology for oil in the shallower Niobrara Shale may provide tremendous return possibilities.  We believe that the Niobrara is prospective in parts of our acreage.  Due to increasing activity in the area by larger industry players,
 

 
6

 

we will limit our activity in 2012 to monitoring their activity and results in the Niobrara, and then developing a strategy for maximizing the value of our position.
 
·  
Exploit our existing producing conventional property base to generate cash flows.  We believe our multi-year drilling inventory of high return exploitation opportunities on our existing producing properties provides us with a solid, dependable platform for future reserve and production growth.  We own 3D seismic data that covers substantially all of our Liberty County acreage, giving us a higher degree of confidence in the potential in this area.  During 2011, our Liberty County drilling program in the Yegua and Cook Mountain resulted in 4 gross (2.6 net) drilled wells,.  Our 2012 activity on our conventional asset base will be limited to production enhancing workover activity.  While the economics of drilling and producing in this area are high, we have not currently allocated any drilling capital to this area for 2012 due to our desire to more extensively develop our positions in the Eagle Ford Shale and the Woodbine oil redevelopment.
 
·  
East Texas resource play.  We still believe that the further exploitation of our meaningful proved undeveloped reserves, and unproved resource potential, in the Haynesville Shale, Mid-Bossier and James Lime formations existing on our 8,500 gross (6,000 net) acreage position in East Texas will provide long term reserve and production growth in the future; however we will not allocate drilling capital to this gas-oriented area until we see an improvement in the natural gas price environment and outlook.
 
·  
Pursue accretive, opportunistic acquisitions that meet our strategic and financial objectives.  We intend to continue evaluating opportunistic acquisitions of crude oil and natural gas properties, including both undeveloped and developed reserves in areas where we currently have a presence and specific operating expertise.
 
·  
Reduce commodity price exposure through hedging.  We employ the use of puts, swaps and costless collar derivative instruments to limit our exposure to commodity prices.  We currently have 7.8 Bcfe of equivalent production hedged for 2012 and 2013, consisting of 3.8 Bcf of natural gas hedges and 0.5 MBbl of crude oil hedges in place for 2012, at average floor prices of $5.00/MMBtu and $98.62/Bbl, respectively and 0.2 MBbl of crude oil hedges in place for 2013 at an average floor price of $101.25/Bbl.
 
Our Employees
 
On March 5, 2012, we had 69 full time employees, of which 20 were field personnel.  We have been able to attract and retain a talented team of industry professionals 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 of our existing asset base, as well as the continuing identification and development of new growth opportunities.  None of our employees are covered by collective bargaining agreements.  We believe our relationship with our employees is good.

Available Information

Our internet website is available under the name http://www.crimsonexploration.com. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing we make with the SEC. We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. In addition, other information such as company presentations is also available on our website. Also, our Corporate Governance Guidelines, Code of Business Conduct, Insider Trading Policy and the charters of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee are available on our website.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information

 
7

 

statements, and other information regarding issuers that file electronically with the SEC. The public can obtain any document we file with the SEC at http://www.sec.gov.

Seasonal Nature of Business

Generally, but not always, the demand for oil and natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand.

Government Regulation and Industry Matters

Federal and State Regulatory Requirements

We are a public company subject to the rules and regulations of the SEC.  These rules and regulations 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 rules and regulations 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 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.

 
8

 


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 of 1938, or NGA, 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 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

 
9

 

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

Environmental and Occupational Health and Safety Matters

Our crude oil and natural gas exploration and production operations are subject to stringent federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment, or otherwise relating to environmental protection.  Numerous governmental authorities, including the U.S. Environmental Protection Agency, or “EPA,” and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.  These laws and regulations may require the acquisition of a permit before drilling and other regulated activities commence, restrict the types, quantities and concentration of various substances that may 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; impose specific criteria addressing worker protection; and impose substantial liabilities for pollution resulting from production and drilling operations.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of orders enjoining some or all of our operations in affected areas.  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 in the future, resulting in increased costs

 
10

 

of doing business and consequently affecting profitability.  To the extent laws are enacted or other governmental action is taken that imposes more stringent and costly requirements for well drilling, construction, completion or water management activities, or operating, waste handling, disposal and cleanup, our business and prospects could be materially and adversely affected.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or 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 generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate wastes that are subject to the federal Resource Conservation and Recovery Act, as amended,  or the “RCRA”, and comparable state statutes.  The RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes and nonhazardous wastes, and the EPA and various state agencies stringently enforce the approved methods of management and disposal of these wastes.  Furthermore, while the RCRA currently exempts certain drilling fluids, produced waters, and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes, we can provide no assurance that this exemption will be preserved in the future.  For instance, in September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the continued application of this RCRA exclusion but, to date, the EPA has not taken any action on the petition.  Repeal or modification of this exclusion or similar exemptions under state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating costs, which could have a significant impact on us as well as the natural gas and oil industry in general.  In any event, these excluded wastes are subject to regulation as nonhazardous wastes.

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 that were standard in the industry at the time, petroleum 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 petroleum hydrocarbons or wastes was not under our control.  These properties and the wastes disposed thereon may be subject to 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 may 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.

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements.  These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions.  Obtaining permits has the potential to delay the development of crude oil and natural gas projects.  Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues.  For example, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for crude oil and natural gas production and natural gas processing operations.  Among other things, these standards would require the application of reduced emission completion techniques, referred to as “green completions,” for completion of newly drilled and fractured wells in addition to existing wells that are re-fractured.  The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment in addition to leak detection requirements for natural gas processing plants.  Final action on the proposed rules is expected no later than April 3, 2012.  If finalized, these rules could require a number of

 
11

 

modifications to our operations including the installation of new equipment, which may result in significant capital expenditures and operating costs.

In response to certain scientific studies suggesting that emissions of carbon dioxide, methane and certain other gases, commonly referred to as greenhouse gases, or “GHGs,” and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions.  The EPA made findings in December 2009 that emissions of GHGs present an endangerment to public health and the environment.  Based on these findings, the EPA has adopted and implemented regulations under the existing provisions of the CAA, including one that restricts emissions of GHGs under existing provisions of the CAA.  The first regulation limits emissions of GHGs from motor vehicles and another one that requires certain Prevention of Significant Deterioration, or “PSD”, and Title V operating permit reviews for GHGs from certain large stationary sources.  This stationary source rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.  Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG.  In addition, the EPA has adopted regulations requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including certain offshore and onshore oil and natural gas production facilities, which may include certain of our facilities.

In addition, from time to time Congress has considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Although it is not possible at this time to predict when Congress may pass climate change legislation, any future federal laws or regulations that impose reporting obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.  Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our assets and operations.

The Federal Water Pollution Control Act, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States.  Any such discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by the EPA or the analogous state agency.  Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.  In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.  It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling.

The Oil Pollution Act of 1990, as amended, or the “OPA,” which amends the Clean Water Act, 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 and natural resource damages.  Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate production.  We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.  Hydraulic fracturing is typically regulated by state oil and gas commissions, but the EPA has asserted federal regulatory authority over hydraulic fracturing involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, several states, including Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating

 
12

 

to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations.  We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party pollution claims.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or the “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers.  In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
 

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 natural gas and crude oil 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 9 - “Debt" for further information.

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.   For the years ended December 31, 2011, 2010 and 2009, our top ten purchasers collectively represented approximately 83%, 80% and 72% of total revenues, respectively. Our three largest purchasers in 2011 accounted for 31%, 22% and 8% 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

 
13

 

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 natural gas and crude oil, 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 natural gas and crude oil we produce.  There is also competition between producers of natural gas and crude oil 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 natural 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 10. “Directors and Executive Officers of the Registrant,” which information is incorporated herein by reference.

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. Prices for natural gas remained low in 2011 when compared with average prices in prior years. 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

 
14

 

 
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.  A reduction in our reserves could have other adverse consequences including a possible downward redetermination of the availability of borrowings under our revolving credit agreement, which would restrict our liquidity.  Additionally, further or continued declines in prices could result in non-cash charges to earnings due to impairment write downs.  Any such write-down could have a material adverse effect on our results of operations in the period taken.

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 and South Texas resource plays and the horizontal redevelopment of the Woodbine and other formations in Southeast Texas, are more uncertain than drilling results in areas that are more developed and with longer production history.  Since new or emerging plays and new formations have limited production history, we are less able to use past drilling results in those areas to help predict our future drilling results.  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, our drilling results are subject to greater risks in these areas and could be unsuccessful.  We may be 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.  To the extent we are unable to execute our expected drilling program in these areas, 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.

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

Our future cash flows are subject to a number of variables, including the level of production from existing wells.  Initial production rates in shale plays, including the Haynesville Shale and the Eagle Ford Shale, tend to decline steeply in the first twelve months of production and are not necessarily indicative of sustained production rates.  As a result, we generally must locate and develop or acquire new crude oil or natural gas reserves to offset declines in these initial production rates.  If we are unable to do so, these declines in initial production rates may result in a decrease in our overall production and revenue over time.

Our development and exploration operations, including on our 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 undeveloped acreage 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

 
15

 

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, to further develop and exploit our current properties, or to conduct 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.

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, 2011, we had outstanding $196.0 million in principal amount of long-term debt.  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:

 
·
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

 
16

 

 
·
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.

In addition, our borrowing base on our revolving credit agreement could be reduced by our lenders and limit our availability of future borrowings, or require us to pay back current borrowings in excess of the new borrowing base. If we were required to pay back all or a portion of our debt, even if new financing were then available, it may not be on terms that are acceptable to us.  See “—Our development and exploration operations 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.”

    Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These proposed changes would include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of these or any other similar changes in U.S. Federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our preferred stock or our common stock.


 
17

 
Slower economic recovery in the U.S. and other countries may materially adversely impact our operations results.

The U.S. and other economies are recovering from a global financial crisis and recession which began in 2008.  Growth has resumed, but has been modest and at an unsteady rate.  There are likely to be significant long-term effects resulting from the financial crisis and recession, including a future global economic growth rate that is slower than what was experienced in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved.

Global economic growth drives demand for energy from all sources, including natural gas, crude oil and natural gas liquids.  NYMEX settlement prices for natural gas and crude oil prices dropped dramatically in 2009 from record levels in July 2008.  While prices of crude oil and natural gas liquids have improved, and we hedged natural gas and crude oil prices on a portion of our forecasted production from proved developed producing reserves for up to two years forward, a reduction in demand for, and the resulting lower prices of, natural gas, crude oil and natural gas liquids could adversely affect our financial condition and results of operations.

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 four 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.

We may not be able to fully realize the value of our net operating loss carryforwards for Federal income tax purposes.

            As of December 31, 2011, we had net operating loss carryforwards (“NOLs”) of approximately $169.0 million, which are available to reduce our future federal taxable income and related income tax liability.  Based upon the level of historical taxable income and our projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these NOLs to reduce future Federal net income tax obligations. Future net losses could affect our ability to realize during the appropriate carryforward periods our available net operating loss carryforwards for Federal income tax purposes and the value of the related deferred tax asset. Our ability to use our available net operating loss carryforwards and the amount of the related deferred tax asset ultimately realizable could be reduced in the future if our estimates of future taxable income during the carryforward periods are reduced.

   We currently expect we will not be able to utilize NOLs of approximately $9.1 million due to prior occurrences of an “ownership change”, as determined under Section 382 of the Internal Revenue Code, as amended.  If we were to experience a further “ownership change,” as determined under Section 382, our ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially.  An ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the highest long-term tax-exempt rate during the three months prior to the date of the ownership change.  The long-term tax-exempt rate is a rate published each month by the Internal Revenue Service.  The application of this limitation could prevent full utilization of our pre-change NOLs arising prior to their expiration. It is possible that additional issuances of our common stock within the next few years, or the sale of our common stock by our larger shareholders, could cause us to experience another ownership change, in which case any NOLs existing at the time of the change would be limited in the manner described above.  

Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in these reserve estimates or underlying assumptions or data 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

 
18

 

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, 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 63% of our total estimated proved reserves at December 31, 2011 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, 2011 was based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2011.  For crude oil and natural gas liquids volumes, the average West Texas Intermediate posted price was $92.71 per barrel.  For natural gas volumes, the average Henry Hub spot price was $4.118 per MMBtu.  The following sensitivity analyses for crude oil and natural gas do not include the volatility reducing effects of our derivative hedging instruments in place at December 31, 2011.  If crude oil prices were $1.00 per Bbl lower than the price used, our PV-10 as of December 31, 2011 would have decreased from $266.5 million to $263.5 million.  If natural gas prices were $0.10 per Mcf lower than the price used, our PV-10 as of December 31, 2011, would have decreased from $266.5 million to $258.8 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 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.


 
19

 

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.  However, even when used and properly interpreted, 3D seismic 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, oil spills, pipeline and tank ruptures encountering naturally occurring radioactive materials, and discharges of toxic gases, brine, well stimulation and completion fluids, or other pollutants into the surface and subsurface environment;

 
·
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 or of water used in hydraulic fracturing activities;

 
·
compliance with environmental and other regulatory requirements;

 
·
natural disasters; and

 
20

 

 
·
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
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.


 
21

 

We may incur substantial impairment of proved properties.

If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and/or natural gas prices decline, we may be required to record additional non-cash impairment write-downs in the future, which would result in a negative impact to our financial results. Furthermore, any sustained decline in oil and/or natural gas prices may require us to make further impairments. We review our proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and natural gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis.
 
 
Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. For the years ended December 31, 2011, 2010 and 2009, we recorded impairments related to oil and gas properties of zero, $0.5 million and $5.7 million, respectively.
 
 
Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.

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:

 
·
the nature and timing of drilling and operational activities;

 
·
the timing and amount of capital expenditures;

 
·
the operator’s expertise and financial resources;

 
·
the operator’s ability to procure drilling and completion services;

 
·
the approval of other participants in drilling wells; and

 
·
the operator’s selection of suitable technology.

A majority of our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a few geographic areas, mostly within the state of Texas, making us vulnerable to risks associated with operating in those few geographic areas.
 
 
The majority of our estimated proved reserves at December 31, 2011 and our production during 2011 were associated with our Southeast Texas, South Texas and East Texas properties. Accordingly, if the level of production from these properties substantially declines or is otherwise subject to a disruption in our operations resulting from operational problems, government intervention (including potential regulation or limitation of the use of high pressure fracture stimulation techniques in these formations) or natural disasters, it could have a material adverse effect on our overall production level and our revenue.

 
22

 


If our access to sales 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, or the demand for equipment and services is greater than the supply in certain areas, 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 operations and financial condition.

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 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 instruments to hedge commodity price exposure to declining prices on our crude oil, natural gas and natural gas liquids production.  We typically use a combination of puts, swaps and costless collars.

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 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.

 
23

 

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 management team and employees.  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.

We are subject to complex federal, state, local and other laws 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.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In December 2009, the EPA determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the CAA including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires construction and operating permit reviews of GHGs from certain large stationary sources. The stationary source rule addresses the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.

 
24

 

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis.  The EPA has also adopted regulations requiring the reporting of GHG emissions from specified large GHG emission sources in the United States including certain onshore and offshore oil and natural gas production facilities, which may include certain of our operations.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  The adoption of legislation or regulatory programs to reduce emissions of GHGs from our operations could require us to incur increased costs to reduce emissions of GHGs and could have an adverse effect on our business, financial condition and results of operations.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.  Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We routinely use hydraulic fracturing techniques in many of our drilling and completion programs  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities.  In the event that new or more stringent federal, state, or local legal restrictions relation to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

Our operations are subject to environmental and occupational health and safety matters.

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of a permit before conducting drilling ,underground injection or other regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations.  Numerous governmental authorities, such as the EPA the OSHA and analogous

 
25

 

state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions.  Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices.  Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken.  Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations.  Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition.  We may not be able to recover some or any of these costs from insurance.  See “Item 1. Business—Environmental Regulations.”

The adoption of financial reform legislation by the United States Congress in 2010 could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity prices, interest rates and other risks associated with our business.

In 2010, the United States Congress adopted comprehensive financial reform legislation that changes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, of the Dodd-Frank Act was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission, or the CFTC, the SEC and other regulators  to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment.  The CFTC and the SEC have not completed all the rulemaking the Dodd-Frank Act directs them to carry out.  The regulators have granted temporary relief from the general effective date for various requirements of the Dodd-Frank Act, and also have indicated they may phase in implementation of many of its requirements.  The CFTC has proposed regulations under the Dodd-Frank Act to set position limits for certain futures and option contracts in the major energy markets, and for swaps that are their economic equivalents.  Certain bona fide hedging transactions or positions would be exempt from these position limits.  The CFTC adopted these proposed regulations with modifications on October 18, 2011, but it is not possible at this time to predict when these regulations will become effective.  The CFTC’s proposed regulations would specify new margin requirements and clearing and trade-execution requirements in connection with certain derivative activities.  It is not clear what the financial regulations will provide.  The legislation and new regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  The new legislation and any new regulations could significantly increase the cost of some derivative contracts (including through requirements to post collateral, or providing other credit support which could adversely affect our available liquidity), materially alter the terms of some derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the new legislation and new regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Increased volatility may make us less attractive to certain types of investors.  Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

 
26

 

Risks Related to an Investment in Our Common Stock

Two stockholders hold 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 those stockholders’ interests may conflict with the interests of our other stockholders.

Of the approximately 45.1 million shares of our common stock outstanding at December 31, 2011, approximately 15.5 million shares are beneficially held by OCM GW Holdings, LLC (“Oaktree Holdings”) and 6.6 million shares are beneficially held by America Capital Energy Corporation (“ACEC”).  As a result, Oaktree Holdings owns or controls outstanding common stock representing, in the aggregate, an approximate 34.4% voting interest in us and ACEC owns or controls outstanding common stock representing, in the aggregate, an approximate 14.7% voting interest in us.  As a result of this stock ownership, Oaktree Holdings and ACEC 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, ACEC and their respective affiliates engage, from time to time in the ordinary course of their respective businesses, in trading securities of, and investing in, energy companies.  As a result, conflicts may arise between the interests of Oaktree Holdings or ACEC, on the one hand, and the interests of our other stockholders, on the other hand.  Either Oaktree Holdings or ACEC may, from time to time, compete directly or indirectly with us or prevent us from taking advantage of corporate opportunities.  Either Oaktree Holdings or ACEC 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 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;

 
·
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.

 
27

 

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, 2011, we had approximately 1.7 million options to purchase shares of our common stock outstanding, of which 0.1 million were vested.

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;


 
28

 

 
·
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 and ACEC, 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

 
·
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 the authority to issue “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, 2011, there were approximately 45.3 million and 45.1 million shares of common stock issued and outstanding, respectively.  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.

 
29

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

As of December 31, 2011, we operated a majority of our producing wells and held an average 45% 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, and primarily in Texas.  As of December 31, 2011, our properties were located in the following regions: East Texas, Southeast Texas, South Texas and Colorado and Other.  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 our resource plays depending on commodity price environment, drilling and service costs, success rates and capital availability.

Proved Reserves

Estimates of proved reserves and future net revenue as of December 31, 2011, 2010, and 2009 were prepared by NSAI in accordance with the definitions and regulations of the SEC. The scope and results of their procedures are summarized in a report 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 estimates of proved reserves and future net revenue are reviewed by our corporate reservoir engineering department that is independent of the operating departments.  The corporate reservoir engineering department interacts with geoscience, operating, accounting and marketing departments to review the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates.  All relevant data is compiled in a computer database application to which only authorized personnel are given access rights. Our Senior Vice President - Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for reviewing any reserves estimates prepared by an independent petroleum engineering firm. Our Senior Vice President - Engineering has a Bachelor of Science degree in Petroleum Engineering from the University of Texas and over 35 years of industry experience with positions of increasing responsibility. He reports directly to our President and Chief Executive Officer. Reserves are also reviewed internally with senior management and presented to our Board of Directors in summary form on a quarterly basis.


 
30

 

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.

   
2011
   
2010
   
2009
 
                   
Natural Gas (MMcf)
                 
Developed
    53,024       60,325       49,075  
Undeveloped
    109,676       75,350       20,785  
Total
    162,700       135,675       69,860  
                         
Crude Oil (MBbl)
                       
Developed
    1,845       1,403       1,274  
Undeveloped
    1,889       761       690  
Total
    3,734       2,164       1,964  
                         
Natural Gas Liquids (MBbl)
                       
Developed
    1,637       1,898       1,977  
Undeveloped
    907       1,075       664  
Total
    2,544       2,973       2,641  
                         
Total MMcfe
                       
Developed
    73,916       80,130       68,581  
Undeveloped
    126,453       86,368       28,908  
Total
    200,369       166,498       97,489  
                         
Proved developed reserves percentage
    37%       48%       70%  
PV-10 (in millions)
  $ 266.5     $ 239.7     $ 176.4  
Standardized Measure (in millions)
  $ 255.3     $ 226.5     $ 176.4  
Estimated reserve life (in years)
    12.1       12.9       7.1  
Prices utilized in estimates (1):
                       
Natural gas ($/MMBtu)
  $ 4.12     $ 4.38     $ 3.87  
Crude oil ($/Bbl)
  $ 92.71     $ 75.96     $ 57.65  
Natural gas liquids ($/Bbl)
  $ 47.84     $ 40.38     $ 30.77  
Average production cost ($/Mcfe) (2)
  $ 0.80     $ 1.16     $ 1.16  


(1)  
 Under SEC rules, prices used in determining our proved reserves 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).    Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules.  All prices, under both sets of rules, are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.

(2)  
Average production cost includes oil and gas operating and workover expense and excludes ad valorem and severance taxes.

PV-10

PV-10 at year-end is a non-GAAP financial measure and represents the 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 because it does not include the effects of income taxes or non-property related expenses such as general and administrative expenses and debt service or depreciation, depletion and amortization on future net revenues.  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.

 
31

 

            The following table provides a reconciliation of our Standardized Measure to PV-10:
 
   
December 31,
 
   
2011
   
2010
   
2009
 
         
(in millions)
       
Standardized measure of discounted future net cash flows
$
255.3
 
$
226.5
 
$
176.4
 
Present value of future income taxes discounted at 10%
 
11.2
   
13.2
   
 
PV-10
$
266.5
 
$
239.7
 
$
176.4
 

           The following table reflects our estimated proved reserves by category as of December 31, 2011.

   
Natural Gas (MMcf)
   
Crude Oil (MBbl)
   
Natural Gas Liquids (MBbl)
   
Total (MMcfe)
   
% of Total Proved
   
PV-10
 
                                 
(in millions)
 
Proved developed producing
    40,937       1,635       1,182       57,839       29%     $ 181.6  
Proved developed non-producing
    12,087       210       455       16,077       8%       25.7  
Proved undeveloped
    109,676       1,889       907       126,453       63%       59.2  
            Total
    162,700       3,734       2,544       200,369       100%     $ 266.5  

Our estimated net proved reserves as of December 31, 2011, were approximately 81% natural gas, 8% natural gas liquids and 11% crude oil and condensate.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 12.1 years based on our proved reserves as of December 31, 2011 and production for the twelve months ended December 31, 2011.  During 2011, 14 gross (7.9 net) operated and non-operated wells were drilled, 13 of which were successful.  We abandoned one well without reaching full depth due to mechanical failure and did not conclude if hydrocarbons were in place.  In 2012, we currently expect to drill 14 gross (9.4 net) wells, 4 of which were in progress as of December 31, 2011.

Proved Developed Reserves

Total proved developed reserves decreased from 80.1 Bcfe at December 31, 2010 to 73.9 Bcfe at December 31, 2011.  The change in proved developed reserves was attributable to 12.6 Bcfe of new natural gas, crude oil and natural gas liquids reserves added from drilling, offset by 2.2 Bcfe in negative performance revisions and 16.6 Bcfe related to 2011 production.

Proved Undeveloped Reserves

From December 31, 2010 to December 31, 2011, total proved undeveloped reserves increased from 86.4 Bcfe to 126.5 Bcfe.  The increase in proved undeveloped reserves was attributable to 57.3 Bcfe from 2011 drilling, offset in part by a 9.0 Bcfe reduction in proved undeveloped reserves that we do not plan to develop within five years, 6.3 Bcfe in negative performance revisions on related developed reserves and 1.9 Bcfe in negative price revisions.  The 9.0 Bcfe reduction in proved undeveloped reserves due to the five-year rule relate primarily to conventional natural gas reserves in South Texas that we do not plan to drill within five years, because of the current low natural gas price environment and outlook and our strategic change in focus to oil-weighted resource plays.

All of our current proved undeveloped locations represented in our year-end reserve report are scheduled to be drilled within five years.  Development costs related to proved undeveloped reserves are projected to be $291.8 million for the next five years.  Our financial resources are expected to be sufficient to drill all of the remaining 126.5 Bcfe of proved undeveloped reserves within the five year period and we are currently committed to doing so.

 

 
32

 

Significant Properties

Summary proved reserve information for our properties as of December 31, 2011, by region, is provided below.

   
Proved Reserves
   
PV-10 (1)
 
Regions
 
Natural Gas
   
Crude Oil
   
Natural Gas Liquids
   
Total
   
Amount
 
   
(MMcf)
   
(MBbl)
   
(MBbl)
   
(MMcfe)
   
(in millions)
 
Southeast Texas
    15,413       865       777       25,264     $ 97.0  
South Texas
    41,079       2,511       1,767       66,745       150.2  
East Texas
    101,517                   101,517       7.0  
Colorado & Other
    4,691       359             6,843       12.3  
Total
    162,700       3,734       2,544       200,369     $ 266.5  

(1)  
Under new SEC rules, prices used in determining our proved reserves as of December 31, 2011 and 2010 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). Prices for natural gas liquids in the table represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SEC rules.   All prices are adjusted for quality, energy content, transportation fees and regional price differentials in determining proved reserves.

(2)  
Standardized Measure for total proved reserves at December 31, 2011 was $255.3.

Production, Price and Cost History

See “Part I, Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Productive Wells

The following table shows the number of producing wells we owned by location at December 31, 2011:

 
Crude Oil
 
Natural Gas
 
Gross Wells
 
Net Wells
 
Gross Wells
 
Net Wells
Southeast Texas
16
 
7.8
 
56
 
31.8
South Texas
24
 
11.0
 
258
 
138.4
East Texas
 
 
10
 
4.5
Colorado & Other
26
 
16.0
 
30
 
7.8
Total
66
 
34.8
 
354
 
182.5

In addition, as of December 31, 2011, we had 142 inactive wells and 19 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, 2011.

 
Developed
 
Undeveloped
 
Gross Acres
 
Net Acres
 
Gross Acres
 
Net Acres
Southeast Texas
20,926
 
11,215
 
26,370
 
21,608
South Texas
81,004
 
44,402
 
19,719
 
16,077
East Texas
5,361
 
4,094
 
3,116
 
1,899
Colorado & Other
10,550
 
5,715
 
9,560
 
7,063
Total
117,841
 
65,426
 
58,765
 
46,647


 
33

 

            If production is not established or if we take no action to extend the terms of our leases, undeveloped acreage will expire over the next three years as follows:

   
Year ending December 31,
   
2012
   
2013
   
2014
   
Net Acres
   
Net Acres
   
Net Acres
Southeast Texas
 
562
   
3,898
   
5,248
South Texas
 
1,192
   
910
   
189
East Texas
 
265
   
664
   
343
Colorado & Other
 
   
   
            Total
 
2,019
   
5,472
   
5,780

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, 2011.

   
2011
 
2010
 
2009
Gross Wells
           
Development
 
11
 
9
 
5
Exploratory
 
2
 
1
 
1
Dry
 
1
 
1
 
1
Total
 
14
 
11
 
7
             
Net Wells
           
Development
 
6.32
 
3.91
 
2.00
Exploratory
 
1.03
 
 
0.52
Dry
 
0.55
 
0.62
 
0.39
Total
 
7.90
 
4.53
 
2.91

At December 31, 2011, we had 4 wells in progress.  All dry (unsuccessful) wells drilled in the last three years were development wells.

Property Dispositions

The following table shows oil and gas property dispositions for the past three years ended December 31, 2011:

   
2011
   
2010
   
2009
 
Oil and gas properties
$
 
$
2,601,997
 
$
42,995,459
 
Accumulated DD&A
 
   
(1,406,066
)
 
(23,158,221
)
Oil and gas properties, net
$
 
$
1,195,931
 
$
19,837,238
 

The dispositions resulted in net losses of zero, $1.1 million and $6.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

ITEM 3.  LEGAL PROCEEDINGS

    From time to time, we are involved in litigation relating to claims arising out of our properties or operations or from disputes with vendors in the normal course of business, including the matters discussed below.

    Mineral interest owners in East Texas (Haynesville Shale) filed two causes of action against us on May 26, 2009 and August 26, 2009, respectively, in the District Court for San Augustine County, Texas alleging breach of contract for not paying lease bonuses on certain prospective oil and gas leases that were pursued by our leasing agent but never taken by Crimson.  The damages alleged are currently approximately $3.2 million and we have received approximately $2.0 million in written demands from other mineral interest owners 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,

 
34

 

financial position, results of operations or cash flows, although we cannot guarantee that a material adverse effect will not occur.

    The holders of oil and gas leases in South Louisiana filed suit against Crimson and several co-defendants alleging failure to act as a reasonably prudent operator, failure to explore, waste, breach of contract, etc. in connection with two wells in Jefferson Davis Parish, Louisiana.  Many of the alleged improprieties occurred prior to our ownership of an interest in the wells at issue, although we may have assumed liability otherwise attributable to our predecessors-in-interest through the acquisition documents relating to the acquisition of our interest in these wells.  The damages currently alleged are approximately $13.4 million.  We and our co-defendants are vigorously defending this lawsuit and we believe that we have meritorious defenses.  We do not believe this suit 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.

In November 2010, we and several predecessor operators were named in a lawsuit filed by an entity alleging that it owns a working interest in a productive formation that has not been recognized by us or by predecessor operators to which we have granted indemnification rights.  In dispute is whether ownership rights in specific depths were transferred through a number of decade-old poorly documented transactions.  The maximum amount asserted in the suit filed could be determined at up to approximately $4.9 million.  We are vigorously defending this lawsuit and believe we have meritorious defenses.  We currently do not believe that this claim 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.

While many of these matters involve inherent uncertainty and we are unable at the date of this report to estimate an amount of possible loss with respect to these matters, we believe that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations.

ITEM 4.  MINE SAFETY DISCLOSURES

    Not applicable.

 
35

 

PART II
 
ITEM 5.  MARKET FOR OUR COMMON STOCK

Our common stock is currently 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 NASDAQ.  The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

 
   
High
   
Low
 
          2011
           
      First Quarter
  $ 4.73     $ 3.29  
      Second Quarter
    4.27       3.14  
      Third Quarter
    3.84       2.00  
      Fourth Quarter
    3.30       2.02  
                 
          2010
               
      First Quarter
  $ 4.74     $ 2.58  
      Second Quarter
    4.00       2.50  
      Third Quarter
    3.24       2.15  
      Fourth Quarter
    4.53       2.50  
                 

Between January 1, 2012 and March 5, 2012, our common stock traded at prices between $2.60 and $3.55 per share.

 
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, 2011 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, 2006 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

Stock Performance Chart Form 10-K 12-31-2011
 
   
Crimson
   
S&P 500 Index
   
DJ US Expl & Prod Index*
 
December 31, 2006
  $ 100.00     $ 100.00     $ 100.00  
December 31, 2007
  $ 294.40     $ 103.53     $ 142.61  
December 31, 2008
  $ 49.60     $ 63.69     $ 84.67  
December 31, 2009
  $ 70.08     $ 78.62     $ 117.70  
December 31, 2010
  $ 68.16     $ 88.67     $ 136.27  
December 31, 2011
  $ 45.76     $ 88.67     $ 129.51  

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 5, 2012, there were approximately 45.3 million shares of Common Stock issued and 45.1 million shares of Common Stock outstanding held by approximately 255 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.  Continental Stock Transfer & Trust Company, 17 Battery Place, New York, NY 10004, (212) 509-4000 is our transfer agent for our Common Stock.

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

 
37

 

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.  Our revolving credit agreement and second lien credit agreement each contain customary covenants restricting our ability to pay dividends.  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
 
On February 18, 2011, we completed an option exchange program (the “Exchange Program”) pursuant to which we exchanged outstanding employee stock options previously granted under our 2005 Stock Incentive Plan with an exercise price greater than $5.00 per share, vested and unvested (the “Eligible Options”), for new, unvested options to purchase Common Stock (the “New Options”).

The Exchange Program was effected with certain employees, including each of our named executive officers.  Under the Exchange Program, a total of 1,093,240 Eligible Options with a weighted average exercise price of $11.24 per share were exchanged for 1,093,240 New Options with an exercise price of $5.00 per share.

Under the terms of the Exchange Program, New Options which will have an exercise price per share equal to the greater of $5.00 per share and the closing price per share of Crimson common stock on The NASDAQ Global Market on the last business day of the Exchange Offer.  Therefore, since the Closing Price of the Common Stock on February 18, 2011 was $3.95, the exercise price per share of the New Options was fixed at $5.00 per share.

The fair value of the Eligible Options exchanged, calculated using the Black-Scholes valuation model, was $1.8 million immediately prior to the exchange and the fair value of the New Options was calculated at $2.7 million.  Therefore, the $0.9 million incremental value of the New Options over the Eligible Options and the $0.2 million of unrecognized compensation expense for the original award, or $1.1 million, will be amortized on a straight line basis, over the four-year vesting period of the New Options, or approximately $22,000 per month.

The Second Amendment to the Amended and Restated 2005 Stock Incentive Plan, approved by shareholders at the Annual Shareholders’ Meeting on May 17, 2011, increased the annual limitation on option share grants to 750,000 shares thereby allowing the balance of Mr. Keel’s Eligible Options to be exchanged.  The remaining 175,000 Eligible Options that were held by Mr. Keel, which had a weighted average exercise price of $9.70, were exchanged on June 16, 2011 under the same terms as the Exchange Program.  This final transaction completed the Exchange Program.


 
38

 

The table below sets forth the number of vested Eligible Options exchanged for an equivalent number of unvested New Options, and the weighted average exercise price of such Eligible Options held by each of our named executive officers at that time.


   
Eligible Options
   
Weighted Average
Exercise Price
 
Allan D. Keel
    675,000     $ 11.38  
E. Joseph Grady
    225,000     $ 11.38  
Thomas H. Atkins
    38,300     $ 11.60  
Jay S. Mengle
    45,000     $ 11.60  
Tracy Price
    90,000     $ 11.60  
     Total
    1,073,300     $ 11.42  

The following table sets forth certain information regarding our equity compensation plans as of December 31, 2011.

Plan Category
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(A)
   
Weighted-average exercise price of outstanding options, warrants and rights
(B)
   
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column
(A)(C)
 
Equity compensation plans approved by security holders
    1,712,461     $ 4.18       2,096,079  
                         
         Total
    1,712,461     $ 4.18       2,096,079  

Our equity compensation plan with outstanding options that has been approved by our stockholders to date is our Amended and Restated 2005 Stock Incentive Plan (“2005 Plan ”).

As of December 31, 2011 we had outstanding options and awards for 1,712,461 shares of Common Stock at a weighted-average exercise price of $4.18 per share under our 2005 Plan.  As of December 31, 2011 the aggregate number of shares of our Common Stock that may be issued and outstanding pursuant to the exercise of awards under our 2005 Plan may not exceed 5,852,500 shares.

Awards covering a total of 2,096,079 shares of Common Stock were currently available to be issued under our 2005 Plan as of December 31, 2011.  During the first quarter 2012, we issued restricted stock awards for 948,000 shares of Common Stock and we issued stock option awards for 20,000 shares of Common Stock to employees.  As a result, we have 1,128,079 shares available to be awarded pursuant to the 2005 Plan as of March 5, 2012.

Our 2005 Stock Incentive Plan (“2005 Plan”) has been authorized with the issuance of up to approximately 5.8 million shares of Common Stock pursuant to awards under the plan.  We also issued 250,000 shares of restricted Common Stock to our executive officers outside of these plans.  Approximately 1.7 million (0.1 million vested) stock options and 1.2 million unvested restricted shares were outstanding at December 31, 2011.  Option awards outstanding have exercise prices ranging from $2.13 to $7.90 per share.  In 2011 and 2010, respectively, 354,051and 326,364 shares of restricted Common Stock vested, of which 46,215 and 33,600 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, 2011, we had approximately 2.1 million shares of Common Stock available for future grant under the 2005 Plan.

Recent Sales of Unregistered Securities

As shown in the table below, during 2011, 2010 and 2009 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

 
39

 

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
                   
12/22/2010
 
Common Stock
 
ACEC
 
1,750,000
$
5.00
Private Placement
                   
10/26/2010
 
Common Stock
 
ACEC
 
4,250,000
$
5.00
Private Placement
                   
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
                   

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, 2011.  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,
 
   
2011
   
2010
   
2009
   
2008
   
2007
 
Statement of Operations Data
                             
                               
Operating revenues
  $ 114,357,505     $ 96,541,967     $ 112,447,646     $ 186,768,273     $ 109,543,208  
Income (loss) from operations (1)
    2,412,240       (14,314,897 )     (387,836 )     46,095,294       33,616,299  
Net income (loss)
    (15,845,382 )     (30,844,897 )     (34,069,990 )     46,203,218       (430,517 )
Dividends on preferred stock
                (4,522,645 )     (4,234,050 )     (4,453,872 )
Net income (loss) available to common stockholders
    (15,845,382 )     (30,844,897 )     (38,592,635 )     41,969,168       (4,884,389 )
Net income (loss), per share
                                       
Basic
  $ (0.35 )   $ (0.78 )   $ (4.91 )   $ 7.81     $ (1.13 )
Diluted
  $ (0.35 )   $ (0.78 )   $ (4.91 )   $ 4.46     $ (1.13 )
Weighted average shares outstanding
                                       
Basic
    44,788,551       39,397,486       7,861,054       5,371,377       4,330,282  
Diluted
    44,788,551       39,397,486       7,861,054       10,360,348       4,330,282  

            (1)   Non-cash equity-based compensation charges were $1.9 million, $1.8 million and $2.4 million, in 2011, 2010 and 2009, respectively.

   
Year Ended December 31,
 
   
2011
   
2010
   
2009
   
2008
   
2007
 
Balance Sheet Data
                             
                               
Current assets
  $ 21,072,180     $ 27,562,216     $ 24,710,943     $ 46,347,553     $ 36,481,565  
Total assets
    436,325,874       412,686,826       424,804,034       511,545,789       398,935,074  
Current liabilities
    67,086,136       47,370,072       33,486,034       83,989,610       48,879,245  
Noncurrent liabilities
    199,734,040       181,785,783       208,587,112       305,933,376       280,402,748  
Stockholders’ equity
    169,505,698       183,530,971       182,730,888       121,622,803       69,653,081  

 
40

 

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

We are 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, South Texas and Colorado regions, which are generally characterized by high rates of return in known, prolific producing trends.  We have expanded our strategic focus to include longer reserve life resource plays in East Texas and South Texas that we believe provide significant long-term growth potential in multiple formations.  We are also focusing on further developing our oil/liquid weighted assets.

We intend to grow reserves and production by developing our existing producing property base, pursuing out Southeast Texas Woodbine horizontal oil redevelopment, 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 associated with our existing property base.  Our technical team has a successful track record of adding reserves through the drill bit.  Since January 2008 and through December 2011, we have drilled 56 gross (26.9 net) wells with an overall success rate of 93%.  At December 31, 2011, we had 4 wells in progress.

As of December 31, 2011, our proved reserves, as estimated by NSAI in accordance with reserve reporting guidelines mandated by the SEC, were 200.4 Bcfe, consisting of 162.7 Bcf of natural gas and 6.3 MMBbl of crude oil, condensate and natural gas liquids with a PV-10 of $266.5 million.  As of December 31, 2011, 81% of our proved reserves were natural gas, 37% were proved developed and 87% were attributed to wells and properties operated by us.  During 2011 we grew proved reserves to 200.4 Bcfe at December 31, 2011 from 166.5 Bcfe at December 31, 2010.

Results of Operations

The following is a discussion of our consolidated results of operations, financial condition and capital resources.  You should read this discussion in conjunction with our Consolidated Financial Statements and the Notes thereto contained elsewhere in this Form 10-K.  Comparative results of operations for the periods indicated are discussed below.
 
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
 
Revenues

   
Year Ended December 31,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Product revenues:
 
(in millions, except percentages)
 
Natural gas sales
  $ 56.7     $ 59.9     $ (3.2 )   -5.3%  
Crude oil sales
    36.8       22.0       14.8     67.3%  
Natural gas liquids sales
    20.2       14.0       6.2     44.3%  
Product revenues
  $ 113.7     $ 95.9     $ 17.8     18.6%  

   Natural Gas, Crude Oil and Natural Gas Liquids Sales.  Revenues from the sale of crude oil, natural gas and natural gas liquids, net of the realized effects of our hedging instruments, were $113.7 million in 2011 compared to $95.9 million in 2010, an increase due primarily to a 28% increase in production, offset in part by an 8% decrease in realized commodity prices.

 
41

 

Production

   
Year Ended December 31,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Sales volumes:
                       
Natural gas (Mcf)
    11,675,602       9,285,574       2,390,028     25.7%  
Crude oil (Bbl)
    396,760       260,289       136,471     52.4%  
Natural gas liquids (Bbl)
    417,956       346,327       71,629     20.7%  
Natural gas equivalents (Mcfe)
    16,563,898       12,925,270       3,638,628     28.2%  

    Production was approximately 16.6 Bcfe in 2011 compared to 12.9 Bcfe in 2010.  On a daily basis, we produced an average of 45,381 Mcfe per day in 2011 compared to an average of 35,412 Mcfe per day in 2010, an increase of approximately 28% primarily due to the success of our drilling and workover programs in South Texas, Southeast Texas and East Texas.

Average Sales Prices

   
Year ended December 31,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Average sales prices (before hedging):
                       
Natural gas (Mcf)
  $ 3.89     $ 4.35     $ (0.46 )   -10.6%  
Crude oil (Bbl)
    101.55       79.05       22.50     28.5%  
Natural gas liquids (Bbl)
    48.96       40.57       8.39     20.7%  
Natural gas equivalents (Mcfe)
    6.41       5.80       0.61     10.5%  

   
Year ended December 31,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Average sales prices (after hedging):
                       
Natural gas (Mcf)
  $ 4.85     $ 6.45     $ (1.60 )   -24.8%  
Crude oil (Bbl)
    92.65       84.61       8.04     9.5%  
Natural gas liquids (Bbl)
    48.35       40.57       7.78     19.2%  
Natural gas equivalents (Mcfe)
    6.86       7.42       (0.56 )   -7.5%  

    Natural gas, crude oil and natural gas liquids prices are reported net of the realized effect of our hedging agreements.  We realized gains of $11.3 million on our natural gas hedges and losses of $3.8 million on our crude oil and natural gas liquids hedges in 2011, compared to realized gains of $19.5 million on our natural gas hedges and $1.4 million on our crude oil hedges in 2010.  The decrease in realized hedging results for 2011 was due to the expiration in 2010 of more favorable natural gas hedges put in place during a higher commodity price environment.

Costs and Expenses

   
Year ended December 31,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Selected Operating Expenses:
 
(in millions, except percentages)
 
Lease operating expenses
  $ 13.3     $ 15.0     $ (1.7 )   -11.3%  
Production and ad valorem taxes
    6.7       6.1       0.6     9.8%  
Exploration expenses
    1.0       1.0           0.0%  
General and administrative(1)
    17.1       18.7       (1.6 )   -8.6%  
Operating expenses
    38.1       40.8       (2.7 )   -6.6%  
Depreciation, depletion & amortization
    56.9       45.0       11.9     26.4%  
Share-based compensation
    1.9       1.8       0.1     5.6%  
Selected operating expenses
  $ 96.9     $ 87.6     $ 9.3     10.6%  

            (1)  Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.

 
42

 


   
Year ended December 31,
             
   
2011
   
2010
   
Change
   
Percent Change
 
Selected Costs ($ per Mcfe):
 
(in millions, except percentages)
 
Lease operating expenses
  $ 0.80     $ 1.16     $ (0.36 )   -31.0%  
Production and ad valorem taxes
    0.41       0.47       (0.06 )   -12.8%  
Exploration expenses
    0.06       0.07       (0.01 )   -14.3%  
General and administrative(1)
    1.03       1.45       (0.42 )   -29.0%  
Operating expenses
    2.30       3.15       (0.85 )   -27.0%  
Depreciation, depletion & amortization
    3.44       3.48       (0.04 )   -1.1%  
Share-based compensation
    0.12       0.14       (0.02 )   -14.3%  
Selected costs
  $ 5.86     $ 6.77     $ (0.91 )   -13.4%  

            (1)  Total general and administrative costs on the Consolidated Statements of Operations include share-based compensation.

    Lease Operating Expenses.  Lease operating expenses in 2011 were $13.3 million ($0.80 per Mcfe) compared to $15.0 million ($1.16 per Mcfe) in 2010, a decrease primarily due to non-core properties sold in 2010, sales tax refunds and lower expense workover costs in 2011.

    Production and Ad Valorem Tax Expenses.  Production and ad valorem tax expenses in 2011 were $6.7 million compared to $6.1 million in 2010, an increase due to higher production and field commodity prices in 2011.

    Exploration Expenses. Exploration expenses were $1.0 million in 2011 compared to $1.0 million in 2010.

    Depreciation, Depletion and Amortization (“DD&A”).  DD&A expense in 2011 was $56.9 million compared to $45.0 million in 2010, an increase primarily due to higher production, offset in part by a slightly lower DD&A rate.

    Impairment and Abandonment of Oil and Gas Properties.  Non-cash impairment and abandonment of oil and gas properties in 2011 was $15.0 million compared to $22.3 million in 2010, primarily due to the impairment of expiring unproved leasehold cost in East Texas.  Non-cash impairment expenses include amortization of individually insignificant properties.

   General and Administrative (“G&A”) Expenses.  Total G&A expenses were $19.1 million ($1.15 per Mcfe) in 2011 compared to $20.5 million ($1.58 per Mcfe) in 2010, which includes non-cash stock expense of $1.9 million ($0.12 per Mcfe) and $1.8 million ($0.14 per Mcfe) in 2011 and 2010, respectively.  G&A expenses decreased primarily due to lower personnel costs and lower legal and other professional fees.

    Loss on Sale of Assets.  The loss on sale of assets during 2010 of $1.1 million was primarily the result of the sale of our non-core Palo Pinto properties in Southeast Texas and the final settlement on the 2009 sale of our non-core Southwest Louisiana properties.

    Interest Expense.  Interest expense was $25.1 million ($1.52 per Mcfe) in 2011 compared to $22.3 million ($1.73 per Mcfe) in 2010.  Total interest expense increased primarily due to the refinancing and expanding of our second lien credit agreement in December 2010.  Interest expense capitalized in 2011 and 2010 was approximately $0.2 million and $0.1 million, respectively.

    Other Financing Costs.  Other financing costs were $1.7 million in 2011 compared with $4.3 million in 2010.  These expenses are comprised primarily of the amortization of deferred costs associated with our credit facilities.  In 2010 we wrote off $2.0 million in debt issuance costs associated with the $150 million second lien credit facility that was refinanced in December 2010.

    Unrealized Loss on Derivative Instruments.  The non-cash unrealized gain in 2011 was $0.5 million compared with a non-cash unrealized loss of $6.5 million in 2010.  Unrealized gain or loss on derivative instruments is the change in the fair value of our commodity price hedging contracts and our interest rate swaps during the period.  Unrealized gain or loss will vary period to period, and will be a function of hedges in place, the strike prices of those hedges and the forward curve pricing for the commodities and interest rates being hedged.

 
43

 

    Income Taxes.  Our net loss before taxes was $23.9 million in 2011 compared to $47.5 million in 2010.  After adjusting for permanent tax differences, we recorded an income tax benefit of $8.1 million in 2011, compared to $16.6 million in 2010.
 
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenues

   
2010
   
2009
   
Change
   
Percent Change
 
Product Revenues:
 
(in millions, except percentages)
 
Natural gas sales
  $ 59.9     $ 71.5     $ (11.6 )   -16.2%  
Crude oil sales
    22.0       27.3       (5.3 )   -19.4%  
Natural gas liquids sales
    14.0       13.0       1.0     7.7%  
Product revenues
  $ 95.9     $ 111.8     $ (15.9 )   -14.2%  

Production

    Natural Gas, Crude Oil and Natural Gas Liquids Sales.  Revenues from the sale of natural gas, crude oil and natural gas liquids, net of the realized effects of our hedging instruments, were $95.9 million in 2010 compared to $111.8 million in 2009, a decrease primarily due to lower production.

   
2010
   
2009
   
Change
   
Percent Change
 
Sales volumes:
                       
Natural gas (Mcf)
    9,285,574       10,414,441       (1,128,867 )   -10.8%  
Crude oil (Bbl)
    260,289       326,707       (66,418 )   -20.3%  
Natural gas liquids (Bbl)
    346,327       426,095       (79,768 )   -18.7%  
Natural gas equivalents (Mcfe)
    12,925,270       14,931,253       (2,005,983 )   -13.4%  

Sales volumes decreased to 12.9 Bcfe in 2010 from 14.9 Bcfe in 2009.  On a daily basis we produced an average of 35,412 Mcfe in 2010 compared to an average of 40,908 Mcfe in 2009.  Lower production volumes are primarily attributed to three factors: (i) the sale of our Southwest Louisiana properties in December 2009 (approximately 1,115,000 Mcfe for 2009); (ii) the loss of approximately 161,000 Mcfe resulting from the shut-in of our Liberty County fields for seven days in mid-June 2010 due to a purchaser pipeline rupture and for two weeks in April 2010 for purchaser plant maintenance; and (iii) natural field decline as a result of limited capital expenditure activity in 2009.

Average Sales Prices

   
2010
   
2009
   
Change
   
Percent Change
 
Average sales prices (before hedging):
                       
Natural gas (Mcf)
  $ 4.35     $ 3.97     $ 0.38     9.6%  
Crude oil (Bbl)
    79.05       56.99       22.06     38.7%  
Natural gas liquids (Bbl)
    40.57