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EX-21.1 - SUBSIDIARIES OF MILAGRO OIL & GAS, INC. - MILAGRO OIL & GAS, INC.d318781dex211.htm
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EX-99.1 - RESERVE REPORT LETTER - MILAGRO OIL & GAS, INC.d318781dex991.htm
Table of Contents

 

 

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

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to            

Commission file number: 333-177534

 

 

MILAGRO OIL & GAS, INC.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   26-1307173

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

1301 McKinney, Suite 500, Houston, Texas   77010
(Address of Principal Executive Offices)   (Zip Code)

Registrant’s telephone number, including area code (713) 750-1600

Securities registered pursuant to Section 12(b) of the Exchange Act:

None

Securities registered pursuant to Section 12(g) of the Exchange Act:

None

 

 

Indicate by check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.    Yes   ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of 15(d) of the Exchange Act.    Yes   ¨    No   x

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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  ¨

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) 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.  x

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x    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  ¨    No  x

As of March 29, 2012, there were 280,400 shares of the registrant’s common stock, par value $.01 per share, outstanding.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

     Page  

PART I

  

Items 1and 2. Description of Business and Properties

     4   

Item 1A. Risk Factors

     22   

Item 1B. Unresolved Staff Comments

     37   

Item 3. Legal Proceedings

     37   

Item 4. Mine Safety Disclosures

     37   

PART II

  

Item  5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities

     37   

Item 6. Selected Financial Data

     38   

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

     40   

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

     57   

Item 8. Financial Statements and Supplementary Data

     61   

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

     85   

Item 9A. Controls and Procedures

     85   

Item 9B. Other Information

     85   

PART III

     86   

Item 10. Directors, Executive Officers and Corporate Governance

     86   

Item 11. Executive Compensation

     88   

Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     99   

Item 13. Certain Relationships and Related Transactions, and Director Independence

     100   

Item 14. Principal Accounting Fees and Services

     102   

PART IV

     103   

Item 15. Exhibits and Financial Statement Schedules

     103   

 

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Table of Contents

Forward-Looking Statements

The information discussed in this report and our public releases include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended( the “Exchange Act”)). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and natural gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future or proposed operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

 

   

our ability to finance our planned capital expenditures;

 

   

the volatility in commodity prices for oil and natural gas;

 

   

demand for oil and natural gas;

 

   

future profitability;

 

   

our ability to continue as a going concern;

 

   

accuracy of reserve estimates;

 

   

the need to take ceiling test impairments due to lower commodity prices;

 

   

significant dependence on equity financing for acquisitions;

 

   

the ability to replace our oil and natural gas reserves;

 

   

general economic conditions;

 

   

our ability to control activities on properties that we do not operate;

 

   

pricing risks;

 

   

availability of rigs, crews, equipment and oilfield services;

 

   

our ability to retain key members of our senior management and key technical employees;

 

   

geographic concentration of our assets;

 

   

expiration of undeveloped leasehold acreage;

 

   

exploitation, development, drilling and operating risks;

 

   

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

 

   

availability of pipeline capacity and other means of transporting our oil and natural gas production;

 

   

reliance on independent experts;

 

   

our ability to integrate acquisitions with existing operations;

 

   

the sufficiency of our insurance coverage;

 

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Table of Contents
   

competition;

 

   

the possibility that the industry may be subject to future regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation);

 

   

environmental risks; and

 

   

additional staffing requirements and other increased costs associated with being a reporting company.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those in the section entitled “Risk Factors” herein. All forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

PART I

Items 1 and 2. Description of Business and Properties

Overview

We are an independent oil and gas company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. In November 2007, we acquired the Gulf Coast assets of Petrohawk Energy Corporation for approximately $825.0 million. The acquisition included properties primarily in the onshore Gulf Coast region in Texas, Louisiana and Mississippi. Since this acquisition, we have acquired additional proved producing reserves that we believe have upside potential, have implemented an active drilling, workover and recompletion program and have expanded our geographic diversity by moving into the Midcontinent area.

As of December 31, 2011, we owned interests in 1,462 gross (864.8 net) wells and had average daily net production in December 2011 of approximately 7,934 Boe/d and approximately 8,001 Boe/d for the year ended December 31, 2011. The wells that we operate provided approximately 74% of our average daily production for 2011. As of December 31, 2011, our estimated net proved reserves, as prepared by our independent reserve engineering firm, W.D. Von Gonten & Co., were 37.3 MMBoe, consisting of 136.8 Bcf of natural gas, 9.2 MMBbl of oil, and 5.3 MMBbl of NGLs. As of December 31, 2011, approximately 66.4% of our net proved reserves were natural gas and approximately 33.6% were oil and NGLs, and approximately 61% of our reserves were proved developed. Our estimated reserve to production ratio as of December 31, 2011 was 12.9 years. During 2011, we drilled eleven gross (8.5 net) wells, consisting of four gross (3.0 net) exploratory wells and seven gross (5.5 net) developments wells with an average success rate of 82%.

For the year ended December 31, 2011, we spent approximately $92.6 million in capital expenditures to support our business plan. Of this amount we spent approximately $39.5 million to drill or complete eleven gross (8.5 net) wells (consisting of four gross (3.0 net) exploratory wells and seven gross (5.5 net) developments wells with an average success rate of 82%), of which nine were successful, adding approximately 77 net Boe/d to our 2011 average daily production. We also recompleted or worked over approximately 74 gross (58.6 net) wells during 2011 at a capital cost of approximately $10.2 million, approximately $2.1 million was spent to plug and abandon wells, and spent approximately $11.9 million to acquire seismic data and additional leases primarily in Oklahoma to support the future development of our Atoka Shale properties. The remaining capital expenditures of approximately $28.9 million related primarily to acquisitions. Our workover efforts added approximately 363 Boe/d to our average daily production for 2011. Our 2012 capital budget contemplates spending approximately $14.2 million in connection with the drilling of eight additional wells, including four development wells in the Texas Gulf Coast, two development wells in the Southeast area and two non-operated wells in our Midcontinent area and approximately $11.3 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $25.0 million for acquisitions.

 

4


Table of Contents

The following table provides information with respect to our estimated net proved reserves as of December 31, 2011, as prepared by W.D. Von Gonten & Co., and our average daily production for 2011.

 

                                        Total Wells                

Area

   Net
Proved
Reserves
(MMBoe)
(a)
     % of
Total
Proved
Reserves
(a)
     SEC
Pricing
PV-10
(Millions)
(a)
     NYMEX
Strip
Pricing
PV-10
(Millions)
(b)
     %
Gas
     Gross      Net      2011
Average
Daily
Production
(Boe/d) ( c)
     % of 2011
Average
Daily
Production
 

Texas Gulf Coast

     11.3         30.3         190.0         187.6         73.1         483.0         294.4         2,971.5         37.1   

Southeast

     7.4         19.8         150.6         150.1         44.5         443.0         245.1         2,182.2         27.3   

South Texas

     10.7         28.7         109.8         113.6         83.7         411.0         248.0         2,115.9         26.5   

Midcontinent

     7.9         21.2         50.8         50.7         61.6         125.0         77.3         731.3         9.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     37.3         100.0         501.2         502.0         66.4         1,462.0         864.8         8,000.9         100.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Our “SEC Pricing” net proved reserves as of December 31, 2011, were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules for a non-GAAP measure based on average prices as of the first day of each of the twelve months ended on such date. These average prices were $96.19 per Bbl for oil and $4.12 per MMBtu for natural gas for December 31, 2011. Pricing was adjusted for basis differentials by field based on our historical realized prices.
(b) Our “NYMEX Strip Pricing” net proved reserves as of December 31, 2011 were calculated using oil and natural gas prices based on average annual NYMEX forward-month contract pricing in effect on such dates. For December 31, 2011, the assumed oil prices were $99.47 per Bbl in 2012, $96.34 per Bbl in 2013, $93.26 per Bbl in 2014, $91.58 per Bbl in 2015 and $90.92 per Bbl held constant thereafter and the assumed natural gas prices were $3.26 per MMBtu in 2012, $3.95 per MMBtu in 2013, $4.34 per MMBtu in 2014, $4.58 per MMBtu in 2015 and $4.82 per MMBtu held constant thereafter. Pricing was adjusted for basis differentials by field based on our historical realized prices. The “NYMEX Strip Price” net proved reserves are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with the “SEC Pricing” net proved reserves as outlined above and do not comply with SEC pricing assumptions.
(c) Average daily production volumes are calculated by summing volumes produced during a given time period, then dividing the sum by the number of days in that time period.

Business Strategy

The key elements of our business strategy include:

Pursue asset acquisitions that leverage our exploitation capabilities and are weighted towards oil or NGLs

We plan to continue to pursue asset acquisitions which offer exploration, exploitation and development opportunities. Drawing on our management team’s experience, we seek targeted acquisitions of relatively lower risk properties that have further exploration, exploitation and development potential as well as opportunities for increased production through recompletions, workovers and cost efficiencies. In addition, we seek to acquire properties that we can operate with a strong proved developed producing component, such as our May and September 2011 acquisitions totaling an aggregate purchase price of $31.9 million (subject to purchase price adjustments) of onshore Texas Gulf Coast and South Texas properties with aggregate net proved reserves of approximately 2.8 MMBoe. We intend to focus on properties that are weighted towards oil or NGLs, provide greater geographic diversity, and contribute towards extending our current reserve to production ratio of 12.9 years.

 

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Continue our lower risk development drilling program

We intend to continue our lower risk development drilling program aimed at converting proved undeveloped oil reserves to proved developed producing reserves in order to help offset the annual production declines that are typical in the onshore Gulf Coast region. We have an inventory of 114 proved undeveloped locations, which we believe, if completed, will provide significant production replacement. We also plan to continue our focus on the workover and recompletion of existing wells. We further seek to grow our production through drilling in unconventional resource plays in the Midcontinent region. We plan to drill six development wells during 2012.

Grow our proved reserves and production

In 2011, we drilled seven gross (5.5 net) development wells, all of which were successful, adding approximately 77 Boe/d to our average daily production for 2011. During 2011, our production replacement strategy and various drilling activity enabled us to maintain a relatively flat daily production profile of approximately 8,001 Boe/d from existing reserves. We believe that our lower risk development drilling program, combined with our ongoing acquisition strategy, will assist us in meeting our goal to maintain our net proved reserves and production.

Continue our focus on cost control

We intend to continue our focus on cost control while acquiring properties, growing our reserves and seeking exploration, exploitation and development opportunities. We seek to control costs at all levels including driving down lease operating expense by maximizing compression, efficiently handling water disposal, carefully coordinating drilling and workover activity in the field and reducing overall company general and administrative costs. Although we will seek to improve our current leverage position, our future levels of indebtedness are largely dependent on a variety of factors, including our future performance. We cannot assure you that we will be able to improve our current leverage position. See “Risk Factors — We cannot assure you that we will be able to improve our leverage position.”

Actively manage our hedging program to reduce sensitivity to commodity prices

We employ the use of swaps and costless collar derivative instruments to limit our exposure to commodity price volatility. As of December 31, 2011, we had hedging contracts in place for 1,784,607 Boe from January 1, 2012 through the end of 2012 and 1,315,949 Boe during 2013. Based on the forecasted production set forth in our January 1, 2012 reserve report, we have hedged approximately 73% of our expected 2012 and 2013 proved developed producing production as of December 31, 2011. In the future, we will seek to enter into commodity price hedging contracts for additional volumes of our expected proved developed producing production.

Our Strengths

Our competitive strengths include:

Substantial undeveloped or prospective acreage to support future exploitation and development efforts

As of December 31, 2011, we had 105,264 gross (76,906 net) acres of undeveloped leasehold acreage and have identified 114 proved undeveloped drilling locations on our properties. We anticipate identifying additional locations on these properties as we pursue our exploration, exploitation and development activities. We believe the successful development of this acreage will provide us an opportunity to augment our net acreage position with additional leasing during 2012 adjacent to, or on trend with, our exploration, exploitation and development efforts.

Balanced capital expenditure strategy coupled with proactive focus on cost control positions us to maintain positive cash flow and liquidity

We intend to implement a capital expenditure program sized to be in line with our operating cash flow. We have implemented a comprehensive program of cost controls and have a proactive hedging strategy intended to provide more predictable levels of revenues. In addition, we currently operate approximately 56.9% of our properties, based on producing wells at December 31, 2011, which gives us the ability to control operations and associated costs on a majority of our properties. We believe our capital expenditure strategy, cost control plan and proactive hedging strategy will allow us to fund our growth while maintaining liquidity for our operations.

 

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Substantial internal capability and capacity to manage and absorb additional acquisitions

Our management and technical teams have significant acquisition experience in our core areas. In the last twelve months, we have successfully completed two acquisitions in our core areas of the onshore Texas Gulf Coast and the South Texas area for an aggregate purchase price of $31.9 million (subject to purchase price adjustments) which added approximately 2.8 MMBoe of proved reserves.

Ownership of a substantial inventory of reprocessed seismic data to help us identify future development and exploitation opportunities

Since 2007, we have spent approximately $20.4 million on seismic data acquisitions and have licenses for proprietary 3-D data of approximately 5,000 square miles in our core areas. We believe that 3-D seismic data is a valuable tool that can improve drilling results, reduce exploration risks and ultimately enhance production and returns. In the areas in which we operate, we also believe that 3-D seismic data provides opportunities to discover additional infield drilling locations. We believe that utilizing this technology in exploring for, developing and exploiting natural gas and oil properties has helped us reduce drilling risks, lower finding costs, lower lease operating expenses and provide for more efficient production from our properties.

Experienced management and technical team

Our management team has an average of more than 25 years of industry experience, including international and domestic public company experience, and has been involved in numerous acquisitions. Our management team has also developed relationships with major and independent industry partners, land and mineral owners, service providers, and independent prospect generators. We believe these relationships will help us to identify new acquisition opportunities, as well as provide information about new trends, prospects and technologies.

We employ 11 operational and technical professionals, including geophysicists, geologists, petroleum, drilling, production and reservoir engineers who have more than 26 years of industry expertise in their specialized, technical fields. The diversity of experience of our engineering, land, geological and geophysical teams in a wide range of settings, combined with various technical specializations, provides us with valuable technical and intellectual resources. We have assembled our teams with backgrounds that complement the areas where we focus our exploration, exploitation and development activities. By integrating their various expertise within our project teams, we believe we possess a competitive advantage in our acquisition, exploitation and development strategies.

Support from our existing sponsors

Our current equity investors include ACON Investments, Guggenheim Capital and West Coast Partners, each of whom made substantial investments in us to fund our acquisition, exploitation and development efforts. These investors also made significant investments in connection with the discharge of our prior second lien indebtedness in connection with the issuance of our Series A preferred stock. We believe that our equity sponsors provide us with management expertise and increased exposure to acquisition opportunities.

Oil and Natural Gas Reserves

W.D. Von Gonten & Co. prepared the estimates of our net proved reserves and future net cash flows (and present value thereof) attributable to such net proved reserves at December 31, 2011. Our internal controls include a bottom up approach to preparing reserves. Our area geologists and engineers provide information to our Corporate Engineering Manager who reviews the information against historical performance and who maintains and prepares our reserves database semi-annually. W.D. Von Gonten & Co. then generates an independent third party reserve report using our reserve database as a starting point. Our Corporate Engineering Manager then cross checks the independent reserve report for accuracy and reviews the results with W.D. Von Gonten & Co. Phillip R. Hunter, the registered professional engineer responsible for the reports generated by W.D. Von Gonten & Co., has over eleven years of industry experience, including data analysis and project management.

Our Corporate Engineering Manager, Vignesh Proddaturi, who is a licensed petroleum engineer licensed in the State of Texas with over seven years experience in oil and natural gas reserve estimation, is also responsible for preparing our internal semi-annual reserve report. The reserve estimates for producing properties are based on production trends, material balance calculations, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analog to offset production in the same field.

 

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Table of Contents

The following table sets forth certain information about our estimated proved reserves as of December 31, 2011.

 

     Oil
(MBbls)
     Natural
Gas
(MMcf)
     NGLs
(MBbls)
     Total
MMBoe
 

Proved Developed

     5,162         50,776         1,656         15.3   

Proved Developed Non-Producing

     1,789         32,303         305         7.5   

Proved Undeveloped

     2,210         53,702         3,340         14.5   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     9,161         136,781         5,301         37.3   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2011, our proved undeveloped reserve locations totaled 14.5 MMBoe, an 18.3% increase from our proved undeveloped reserve locations at December 31, 2010. During 2011, we spent approximately $18.2 million converting seven of our proved undeveloped reserve locations at December 31, 2010 to proved developed at December 31, 2011. The majority of the increase in our proved undeveloped reserves was the result of our interest acquisitions in 2011 and new locations identified by internally generated field studies. We expect all of our proved undeveloped reserve locations at December 31, 2011 to be developed over the next five years. Estimated future costs related to the development of these locations are expected to total approximately $190.7 million.

The estimated cash flows from our proved reserves at December 31, 2011 were as follows:

 

     Proved
Developed
(M$)
     Proved
Developed
Non-
Producing
(M$)
     Proved
Undeveloped
(M$)
     Total
Proved
(M$)
 

Estimated pre-tax future net cash flows(1)

     443,587         216,155         255,643         915,385   

Discounted pre-tax future net cash flows (PV-10)(1)

     280,170         108,432         112,597         501,199   

 

(1) PV-10 is a non-GAAP financial measure which is derived from the standardized measure of discounted future net cash flows which is the most directly comparable GAAP financial measure. Our management believes that the presentation of PV-10 is useful to investors because it is based on prices, costs and discount factors which are consistent from company to company, while the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 presents the discounted future net cash flows attributable to our net proved reserves before taking into account future corporate income taxes and our current tax situation. As a result, we believe that investors can use these non-GAAP measures as a basis for comparison of the relative size and value of our reserves to other companies. The following table reconciles undiscounted and discounted future net cash flows to the standardized measure of discounted cash flows as of December 31, 2011 using “SEC Pricing.”

 

Estimated pre-tax future net cash flows

   $ 915,385   

10% annual discount

     (414,186

Discounted pre-tax future net cash flows (PV-10)

   $ 501,199   

Future income taxes discounted at 10%

     (38,743
  

 

 

 

Standardized measure of discounted future net cash flows

   $ 462,456   
  

 

 

 

 

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Table of Contents

We have not filed any reports with other federal agencies that contain an estimate of total proved net oil and natural gas reserves.

Core Areas

Texas Gulf Coast

Our Texas Gulf Coast properties are principally located onshore in Lavaca, Colorado, Goliad, Wharton and Matagorda Counties, with concentrated efforts in the Frio, Miocene and Yegua trends. Our two core areas within our Texas Gulf Coast region are the Magnet Withers and Lions fields. Since January 1, 2008, we have drilled 44 gross (32.6 net) wells on our Texas Gulf Coast properties and we have completed 36 of those wells. As of December 31, 2011, we had interests in 483 gross (294.4 net) wells in this area, with an average net working interest of 60.9% and average daily net production in December 2011 of approximately 2,971.5 Boe/d. We operate approximately 59.3% of our properties in the Texas Gulf Coast based on producing wells at December 31, 2011. In 2011, we drilled two development wells in the Texas Gulf Coast area, as well as performed 27 production enhancing workovers. We currently anticipate drilling four development wells in this area in 2012, all of which will be at the Magnet Withers field.

At December 31, 2011, net proved reserves attributable to the Magnet Withers field were approximately 2.6 Bcf of natural gas and 3.6 MMBbl of oil and NGLs. Our properties within the Magnet Withers field account for 11% of our total net proved reserves. During 2011, our average daily net production from Magnet Withers averaged 669 Boe/d, including approximately 0.4 MMcf/d of natural gas and approximately 596 Bbl/d of oil and NGLs, down from 1,170 Boe/d during 2010.

Magnet Withers is a regional sized low relief four way closure created by rolling into an up to the basin fault. The field is located in the Frio trend of Upper Gulf Coast of Texas and was discovered in the 1930s. Production to date is approximately 134 MMBbl of oil and 1,417 Bcf of natural gas. Shallow Miocene production, above 4,800 feet, is dry gas that produces by depletion and water drive. The deeper Frio production from 4,800 feet to a depth of 7,400 feet is oil that produces dominantly by strong water drive. The field is non-pressured, although pressure does develop below the base of the Frio in the Vicksburg Shale section. Magnet Withers is largely un-faulted except along its eastern flank and reservoirs are generally continuous with some stratigraphic restrictions. The main field oil play, the Frio 1, was originally an associated oil reservoir with a large gas cap that produced by water drive. Blow down of the gas cap in this interval has resulted in a lowered reservoir pressure but has left significant volumes of un-drained oil in off-structure accumulations which have been targeted by recent drilling.

At December 31, 2011, net proved reserves attributable to the Lions field were approximately 7.3 Bcf of natural gas including 2.2 Bcf of which that is attributable to our acquisition in May 2011 as described below. The Lions field accounts for 3.2% of our total net proved reserves. During 2011, our daily net production from the Lions field averaged 533 Boe/d, including approximately 3.2 MMcf of natural gas, down from 727 Boe/d during 2010.

The Lions field is a structurally controlled three way fault accumulation with strong stratigraphic influence. The leading fault creates the predominant trap with associated en-echelon faulting as a fault system providing additional complexity and compartmentalization. Production is from sands in the Lower Wilcox intervals between 13,500 feet down to the Cretaceous Glide Plane at 16,000 feet. The section is over-pressured and produces essentially dry gas. The main field pay is the Upper Corona Sand which was discovered in 2004. Field development relies on seismic interpretation. Multiple wells have been drilled since discovery of the field, targeting high structural positions along the several trapping faults mapped within the field. Production from the Lions field to date is approximately 84 Bcf of natural gas.

In May 2011, we acquired an additional small working interest in the Lions field for $3.9 million adding 0.4 MMBoe at $10.6 /Boe.

Southeast

Our Southeast properties are principally located in St. Martin, Vermilion and Cameron Parishes of Louisiana, Covington, Jefferson Davis, Marion and Wayne Counties of Mississippi and Jefferson, Chambers and Liberty Counties of Texas. Our two core areas are the Gueydan Dome and West Lake Verret field in Louisiana. Since 2008, we have drilled 16 gross (10.7 net) wells on our Southeast properties and have completed 12 of those wells. As of December 31, 2011, we had interests in 443 gross (245.1 net) wells in this area, with an average working interest of 55.3% and average net daily production in December 2011 of approximately 2,182.2 Boe/d. We operate approximately 45.1% of our properties in the Southeast area based on producing wells at December 31, 2011. In 2011, we drilled two development wells and performed 8 production enhancing workovers. We currently anticipate drilling two development wells in West Lake Verret field in 2012.

 

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At December 31, 2011, net proved reserves attributable to the Gueydan Dome were approximately 0.3 Bcf of natural gas with 0.4 MMBbl of oil and NGLs. The Gueydan Dome accounts for 1.3% of our total net proved reserves. During 2011, our average daily net production from the Gueydan Dome averaged 255 Boe/d, including approximately 0.1 MMcf/d of natural gas and approximately 244 Bbl/d of oil, down from 333 Boe/d during 2010.

The Gueydan Dome is a piercement salt dome located in the Salt Dome Province of Louisiana. First discovered in the 1930s, the field is located on dry land. Production is predominantly oil with associated gas that produces by a strong water drive. The field produces from both the Miocene and Frio sections. Shallow Miocene and Upper Frio intervals between 1,800 feet and 4,000 feet produce in an overall four way faulted structure that drapes across a deeper seated salt piercement. The deeper production, and the main Alliance Sand oil play, while stratigraphic, are trapped by salt piercement and associated radial faulting. The bulk of production is from normally pressured reservoirs in the field although some pressured reservoir production is found below 10,000 feet. Production to date on Gueydan Dome totals approximately 15 MMBbl of oil and 29 Bcf of natural gas.

At December 31, 2011, net proved reserves attributable to the West Lake Verret field were approximately 0.5 Bcf of natural gas with 1.2 MMBbl of oil. West Lake Verret accounts for approximately 3.3% of our total net proved reserves. During 2011, our average daily net production from West Lake Verret averaged 303 Boe/d, including approximately 0.4 MMcf/d of natural gas and approximately 240 Bbl/d of oil, down from 436 Boe/d during 2010. West Lake Verret was shut in from May 10, 2011 to August 8, 2011 due to flooding of the Atchafalaya Basin. As a result, full field production was not realized until November 1, 2011. The December 31, 2011 West Lake Verret net exit production rate was 358 Boe/d.

West Lake Verret was discovered in the 1930s and is a large structurally trapped accumulation located in the Miocene Trend of Louisiana. It is located in the waters of the Atchafalaya Basin. The field is an overall faulted four way closure which resulted from salt evacuation, leaving a central graben with rimming faults. Production is predominantly oil and associated gas that produces with a water drive from stacked pay intervals between 800 feet and 12,500 feet. The bulk of the production is from the non-pressured section above 11,500 feet. In the main field pays, the J through R sand sections, the field produces high side to faults that are down to the central basin graben which in itself produces as a faulted four way trap. Shallow production, above 2,800 feet, is restricted to faulted high side and low relief four way traps on the western flank of the overall field closure that are structurally detached from the deeper field pays. Overpressured production is predominantly gas with associated liquids in the AA through PP Sands and is limited to the central portion of the field. Since discovery at the West Lake Verret field, overall field production to date has totaled approximately 77 MMBbl of oil and 307 Bcf of natural gas. In addition to our properties in Louisiana, Mississippi and Texas, our Southeast area includes a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to jurisdiction of the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement.

South Texas

Our South Texas properties are principally located in Starr, Hidalgo, Live Oak and Bee Counties, with concentrated efforts in the Vicksburg and Wilcox trends. Our two core areas are the Nabors and La Reforma fields. Since January 1, 2008, we have drilled 28 gross (18.7 net) wells on our South Texas properties and have completed 20 of those wells. As of December 31, 2011, we had interests in 411 gross (248.0 net) producing wells in this area, with an average working interest of 60.3% and average daily net production in December 2011 of approximately 2,115.9 Boe/d. We operate approximately 55.4% of our properties in the South Texas area based on producing wells at December 31, 2011. In 2011, we drilled one well and participated in one non-operated development well and one non-operated exploratory well in the South Texas area and performed 8 production enhancing workovers. We do not anticipate drilling any wells in this area in 2012.

At December 31, 2011, net proved reserves attributable to the Nabors field were approximately 7.4 Bcf of natural gas with 0.4 MMBbl of oil and NGLs. Nabors accounts for 4.4% of our total net proved reserves. During 2011, our average daily net production from Nabors averaged 616 Boe/d, including approximately 2.8 MMcf/d of natural gas, 144 Bbl/d of oil and NGLs, down from 891 Boe/d during 2010.

 

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Nabors is a high side closure with several inter-field faults breaking up the productive reservoirs. Production is overpressured and from numerous Vicksburg sands, ranging from 9,200 feet to 11,300 feet. First production began in 2000 and to date the field has produced 12 Bcf of natural gas and 106 MMBbl of oil. The Vicksburg reservoirs at Nabors are complex. We have been developing these reservoirs using seismic and stratigraphic interpretations to define locations that target un-depleted high structural prospects.

At December 31, 2011, net proved reserves attributable to La Reforma were approximately 11.8 Bcf of natural gas with 1.1 MMBbl of oil and NGLs. La Reforma accounts for 8.2% of our total net proved reserves. During 2011, our average daily production from La Reforma averaged 255 Boe/d, including approximately 1.0 MMcf/d of natural gas, 85 Bbl/d of oil and NGLs, up from 204 Boe/d during 2010.

In September 2011, we acquired additional interests in fields in the area that includes La Reforma for approximately $28 million and added 2.4 MMBoe at $11.60/Boe.

The La Reforma field is located in the Vicksburg and Frio trends of South Texas. La Reforma is a broad faulted four way feature that is productive in multiple high side fault traps on both the upthrown and downthrown portions of a large down to the coast fault. Production is from the Frio and Vicksburg sections and is stratigraphically complex. The Frio formation was discovered in 1938, while the Vicksburg formation was discovered later in 1949. The Frio produces both oil and natural gas while the Vicksburg only produces gas and condensate. Oil, natural gas and condensate ratios vary greatly between reservoirs. Drainage areas in the Vicksburg and Frio are small. Both produce in multiple intervals from depths ranging between 4,500 feet to 6,500 feet in the Frio and from 7,400 feet to 11,200 feet in the Vicksburg. Production to date from both reservoirs totals approximately 4 MMBbl of oil and 293 Bcf of natural gas and numerous wells remain to be drilled in each reservoir.

Midcontinent

On December 8, 2010, we completed an approximately $44.5 million purchase of certain North Texas assets from RWG Energy, Inc., a subsidiary of RAM Energy Resources, Inc. The assets acquired in the transaction are located in Jack and Wise Counties, Texas, focused on the Barnett Shale and Bend Conglomerate trend in the Fort Worth Basin, with net proved reserves of approximately 7.9 MMBoe as of December 31, 2011 and an average working interest of 61.9% and average daily net production in December 2011 of approximately 731.3 Boe/d including 1.8 MMcf of natural gas, 49 Bbl of oil and 334 Bbl of NGLs. We operate approximately 75.4% of our properties in the Midcontinent area based on producing wells at December 31, 2011. We are the operator of the Boonesville Bend Conglomerate properties, which account for approximately 75.4% of the properties, based on producing wells at December 31, 2011, and EOG Resources, Inc. and Devon Energy operate the deeper Barnett Shale properties. We have an average working interest of 26.1% with a corresponding average net revenue interest of 19.1% in the Barnett Shale and an average working interest of 73.4% with a corresponding net revenue interest of 52% in the Boonesville properties. The Fitzgerald #1H development well operated by Devon started production in 2012.

The Fort Worth Basin is a natural gas prone region with multiple pay zones ranging in depth from 1,000 feet to 9,000 feet. The Fort Worth Basin has experienced a drilling boom in the last several years as natural gas prices increased along with advances in fracturing technology that have unlocked natural gas reserves from the Barnett Shale. The Barnett Shale is a thick blanket type formation covering the entire Basin. The natural gas reserves in place are significant; however, due to the extremely low permeability of the shale, it has been technically difficult to recover these reserves. Recent advances in hydraulic fracturing and horizontal well technology have enabled economic recovery of additional natural gas reserves in the Fort Worth Basin.

According to the U.S. Geological Survey, an estimated 26.7 trillion cubic feet of undiscovered natural gas, 98.5 MMBbl of undiscovered oil and 1.1 BBbl of undiscovered NGLs remain within the 54,000 square mile Bend Arch-Fort Worth Basin Province. According to the U.S. Geological Survey, more than 98%, or approximately 26.2 trillion cubic feet of this undiscovered natural gas, is contained in the Barnett Shale.

In 2011, we significantly expanded our exploratory acreage position in Western Oklahoma bringing our total net acreage to approximately 50,000 acres in the Midcontinent region. The majority of the new leases were procured with six year primary terms in an area known as our Harper Trend. Also during the year, we drilled two new exploratory wells with horizontal completions and reentered a well drilled in 2010 with a horizontal completion. The primary targets were various zones in the Atoka Shale. Oil and natural gas shows were encountered in each of the three wells. Two of the wells are producing with less than 10 Bbl/d as of December 31, 2011 and the third well is deemed non-commercial.

 

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We continue to evaluate the potential of the acreage in several known producing horizons including the Cottage Grove, Oswego, Cleveland, Marmaton, Bartlesville, Novi/Atoka and Mississippian formations.

Markets and Customers

We sell our oil and natural gas under fixed or floating market contracts. Customers purchase all of our oil and natural gas at current market prices. The terms of the arrangements generally require customers to pay us within 30 days after the production month ends. As a result, if our customers were to default on their payment obligations to us, near-term earnings and cash flows would be adversely affected. However, due to the availability of other markets and pipeline connections, we do not believe that the loss of these customers, or any other single customer, would adversely affect our ability to market our production.

Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control, including:

 

   

the extent of domestic production and imports of oil and natural gas;

 

   

the proximity of our natural gas production to pipelines;

 

   

the availability of capacity in such pipelines;

 

   

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

 

   

the availability of alternative fuel sources;

 

   

the effects of inclement weather;

 

   

state and federal regulation of oil and natural gas production; and

 

   

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

We cannot assure you that we will be able to market all of the oil or natural gas we produce or that favorable prices can be obtained for the oil and natural gas we produce. We do not currently maintain any commitments to deliver a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements.

In view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we are unable to predict future oil and natural gas prices and demand or the overall effect such prices and demand will have on our business and results of operations. During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 16% and Shell Trading (US) Company accounting for 17%. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 19% and Enterprise Crude Oil, LLC accounting for 11% and Plains Marketing, L.P. accounting for 6%. During 2009, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 16%, Enterprise Crude Oil, LLC accounting for 8% and Plains Marketing LP accounting for 8%. These percentages do not consider the effects of commodity hedges. We do not believe that the loss of any of our oil or natural gas purchasers would have a material adverse effect on our operations due to the availability of other potential purchasers. None of our agreements has fixed volume delivery requirements and we have not failed to meet any delivery obligation over the last three years.

 

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Sales Volumes, Prices and Production Costs

The following table sets forth our sales volumes, the average prices we received before hedging, the average prices we received including hedging settlement gains (losses), the average prices we received including hedging settlements and unrealized gains (losses) and average production costs associated with our sale of oil and natural gas for the periods indicated. We account for our hedges using mark-to-market accounting, which requires that we record both derivative settlements and unrealized gains (losses) in our consolidated statement of operations within a single income statement line item. We have elected to include both derivative settlements and unrealized gains (losses) within revenues.

 

     Year Ended December 31,  
     2011      2010      2009  

Sales volumes:

        

Oil volumes (MBbls)

        

Texas Gulf Coast

     288         270         211   

Southeast

     407         488         607   

South Texas

     87         112         120   

Midcontinent

     13         2         —     
  

 

 

    

 

 

    

 

 

 

Total oil

     795         872         938   

Natural gas volumes (MMcf)

        

Texas Gulf Coast

     4,773         6,486         9,133   

Southeast

     2,287         2,799         3,398   

South Texas

     3,549         4,286         5,932   

Midcontinent

     732         86         49   
  

 

 

    

 

 

    

 

 

 

Total natural gas

     11,341         13,657         18,512   

NGL volumes (MBbls)

        

Texas Gulf Coast

     1         7         6   

Southeast

     8         7         3   

South Texas

     94         111         166   

Midcontinent

     132         14         —     
  

 

 

    

 

 

    

 

 

 

Total NGL

     235         139         175   

Total Oil Equivalent (MBoe)

     2,920         3,287         4,198   
  

 

 

    

 

 

    

 

 

 

 

     Year Ended December 31,  
     2011      2010      2009  

Average oil prices based on sales volumes:

        

Oil price (per Bbl)

   $ 103.06       $ 78.58       $ 57.21   

Oil price including derivative settlement gains (losses) (per Bbl)

   $ 94.96       $ 78.64       $ 60.90   

Average natural gas prices based on sales volumes:

        

Natural gas price (per Mcf)

   $ 3.93       $ 4.39       $ 3.79   

Natural gas price including derivative settlement gains (losses) (per Mcf)

   $ 6.02       $ 7.27       $ 5.99   

Average NGL prices based on sales volumes:

        

NGL prices (per Bbl)

   $ 49.74       $ 41.14       $ 27.99   

NGL prices including derivative settlement gains (losses) (per Bbl)

   $ 48.93       $ 41.14       $ 27.99   

Average equivalent prices based on sales volumes:

        

Oil equivalent price (per Boe)

   $ 47.33       $ 40.83       $ 30.68   

Oil equivalent price including derivative settlement gains (losses) (per Boe)

   $ 53.16       $ 52.80       $ 41.19   

Oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)

   $ 53.02       $ 47.81       $ 36.78   

Average production costs (per Boe) based on sales volumes:

        

Lease operating expenses (including costs for operating and maintenance and workover expense)

   $ 12.04       $ 10.43       $ 7.75   

Taxes other than income

   $ 3.40       $ 3.32       $ 2.15   

 

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Oil and Natural Gas Drilling Activity

The following table sets forth the wells drilled and completed by us during the periods indicated:

 

     2011      2010      2009  
     Gross      Net      Gross      Net      Gross      Net  

Exploration:

                 

Productive

     2.0         2.0         4.0         2.1         0.0         0.0   

Non-productive

     2.0         1.0         2.0         1.5         1.0         0.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4.0         3.0         6.0         3.6         1.0         0.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Development:

                 

Productive

     7.0         5.5         6.0         5.8         1.0         0.0   

Non-productive

     0.0         0.0         0.0         0.0         0.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     7.0         5.5         6.0         5.8         1.0         0.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Productive Wells

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

 

     Oil      Natural Gas  
     Gross      Net      Gross      Net  

Texas Gulf Coast

     79.0         56.4         253.0         128.9   

Southeast

     110.0         78.2         114.0         26.7   

South Texas

     44.0         30.9         252.0         133.7   

Midcontinent

     47.0         33.8         75.0         41.3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     280.0         199.3         694.0         330.6   
  

 

 

    

 

 

    

 

 

    

 

 

 

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage by location as of December 31, 2011:

 

     Leasehold Acreage  
     Developed      Undeveloped  
     Gross      Net      Gross      Net  

Texas Gulf Coast

     59,387         54,341         27,717         18,444   

Southeast

     55,323         48,006         2,054         2,097   

South Texas

     52,595         46,516         7,776         3,647   

Midcontinent

     30,007         27,948         67,717         52,718   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     197,312         176,811         105,264         76,906   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Undeveloped Acreage Expirations

The table below summarizes by year our undeveloped acreage scheduled to expire.

 

      Acres Expiring  

Twelve Months Ending:

   Gross      Net  

December 31, 2012

     4,963         3,207   

December 31, 2013

     1,929         1,912   

December 31, 2014

     10,487         4,229   

December 31, 2015

     —           —     

December 31, 2016

     9,976         9,113   

December 31, 2017 and thereafter

     77,909         58,445   
  

 

 

    

 

 

 

Total

     105,264         76,906   
  

 

 

    

 

 

 

We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the primary term of such a lease. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and may allow additional acreage to expire in the future.

Title to Properties

We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

 

   

royalties and other burdens and obligations, express or implied, under oil and gas leases;

 

   

overriding royalties and other burdens created by us or our predecessors in title;

 

   

a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

 

   

back-ins and reversionary interests existing under purchase agreements and leasehold assignments;

 

   

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements, pooling, unitization and communitization agreements, declarations and orders; and

 

   

easements, restrictions, rights-of-way and other matters that commonly affect property.

 

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To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind that we own.

Federal Regulations

Sales and Transportation of Natural Gas. Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”) and Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of natural gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since 1985, FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action FERC will take on these matters. Some of FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that FERC’s actions will have a materially different effect on us as compared to other natural gas producers, gatherers and marketers with which we compete.

The Outer Continental Shelf Lands Act (the “OCSLA”) requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction. Therefore, we do not believe that any action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable market prices.

Natural gas continues to supply a significant portion of North America’s energy needs and we believe the importance of natural gas in meeting this energy need will continue. The impact of the ongoing economic downturn on natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage oil and natural gas exploration and development in the United States. The 2005 EPA directs FERC and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. On January 20, 2006, FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. Therefore the rules reflect a significant expansion of FERC’s enforcement authority. We do not anticipate that these rules will affect us any differently than other producers of natural gas.

 

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Sales and Transportation of Crude Oil. Our sales of crude oil, condensate and NGLs are not currently regulated, and are subject only to applicable contract provisions negotiated by us and out counterparties. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport oil, condensate and NGLs is generally less restrictive than FERC’s regulation of natural gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and NGLs are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of FERC under the ICA, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus 1%. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.

Federal Offshore Leases. We have an ownership interest in facilities on the Outer Continental Shelf located on federal oil and natural gas leases, which are administered by the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement, pursuant to the OCSLA. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed regulations and orders that are subject to interpretation and change.

For offshore operations, lessees must obtain approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency (the “EPA”), lessees must obtain a permit prior to the commencement of drilling. In 2010, changes to these regulations were adopted to impose a variety of new measures intended to help prevent a disaster similar to the Deepwater Horizon incident in the future. Offshore operators, including those operating in deepwater, outer continental shelf waters and shallow waters, where we have operations, must now comply with strict new safety and operating requirements. For example, before being allowed to resume drilling in deepwater, outer continental shelf operators must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, including those rules recently placed into effect, such as rules relating to well casing and cementing, blowout preventers, safety certification, emergency response, and worker training. Operators of all offshore waters also must demonstrate the availability of adequate spill response and blowout containment resources.

To cover the various obligations on the Outer Continental Shelf, lessees are generally required to have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, operations on federal leases may be required to be suspended or terminated. We have a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to this jurisdiction. Any such suspension or termination of our operations could materially and adversely affect our financial condition, cash flows and results of operations.

The Office of Natural Resources Revenue (the “ONRR”) in the U.S. Department of the Interior administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued under the OCSLA. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as of the regulations promulgated by ONRR. ONRR regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases provide that ONRR will collect royalties based upon the market value of oil produced from federal leases. On September 30, 2010, the Royalty in Kind program, which accepted oil and natural gas in lieu of cash as royalty payments, was terminated. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay . However, we do not believe that these regulations or any future amendments will affect our business in a way that materially differs from the way it affects other oil and natural gas producers, gatherers and marketers.

Federal, State or American Indian Leases. Operations on federal, state or American Indian onshore oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, certain on-site security regulations and must also obtain permits issued by the Bureau of Land Management (the “BLM”) or other appropriate federal or state agencies.

 

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The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and natural gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and natural gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. If any of our equity holders is deemed to be a citizen of a non-reciprocal country, then our interests in federal onshore oil and natural gas leases may be cancelled. Any such cancellation could have a material adverse effect on our financial condition, cash flows and results of operations.

State Regulations

Most states regulate the production and sale of oil and natural gas, including:

 

   

requirements for obtaining drilling permits;

 

   

the method of developing new fields;

 

   

the spacing and operation of wells;

 

   

the prevention of waste of oil and natural gas resources; and

 

   

the plugging and abandonment of wells.

The rate of production may be regulated and the maximum daily production allowable from both oil and natural gas wells may be established on a market demand or conservation basis or both.

We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such natural gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates that we could charge for natural gas, the transportation of natural gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority.

Legislative Proposals

In the past, governments at both the federal and state level have been very active in the area of natural gas regulation. New legislative proposals in the United States Congress and the various state legislatures, if enacted, could significantly affect the petroleum industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, such proposals might have on our operations.

Environmental Regulations

General. Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

 

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Our activities with respect to exploration and production of oil and natural gas, including the drilling of wells, are subject to stringent environmental regulation by state and federal authorities, including the EPA. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in oil and natural gas production operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such as spills or other unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and natural gas production, would result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We own or lease numerous properties that have been used for production of oil and natural gas for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed of or released on, under, or from these properties. In addition, many of these properties have been operated by third parties that controlled the treatment of hydrocarbons and solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and natural gas wastes and properties have become more strict over time. Under these laws, 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 by prior owners or operators) or to perform remedial plugging operations to prevent future contamination.

We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (the “RCRA”) and state statutes. The EPA has limited the disposal options for certain hazardous wastes. Furthermore, it is possible that certain wastes generated by our oil and natural gas operations that are currently exempt from regulation as “hazardous wastes” may in the future become regulated as “hazardous wastes” under RCRA or other applicable statutes, and therefore may become subject to more rigorous and costly management and disposal requirements.

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the owner and operator of a site and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. Certain state statutes impose similar liability. Neither we nor, to our knowledge, our predecessors have been designated as a potentially responsible party by the EPA under CERCLA or by any state under a similar state law.

Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in certain United States waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulations. If a party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.

The OPA currently establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs plus $75 million, and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges and other factors. We believe we currently have established adequate financial responsibility. While financial responsibility requirements under OPA may be amended to impose additional costs on us, the impact of any change in these requirements should not be any more burdensome to us than to other similarly situated companies.

 

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Clean Water Act. The Clean Water Act (the “CWA”) regulates the discharge of pollutants into waters of the United States and adjoining shorelines, including wetlands, and requires a permit for the discharge of pollutants, including petroleum and dredged or fill materials, into such waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry operations into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain facilities that store or otherwise handle oil to prepare and implement Spill Prevention, Control and Countermeasure Plans and Facility Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide civil and criminal penalties and liabilities for spills to both surface and groundwater and require permits that set limits on discharges to such waters. We believe we are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on us.

Safe Drinking Water Act. The underground injection of oil and natural gas wastes is regulated by the Underground Injection Control (“UIC”) Program, authorized by the federal Safe Drinking Water Act (“SDWA”). The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In Oklahoma, Louisiana, Mississippi and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to comply with our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits and authorizations.

Our exploration and production activities may involve the use of hydraulic fracturing techniques to stimulate wells and maximize production. Hydraulic fracturing entails the injection of pressurized fracturing fluids. In 2005, UIC provisions of the SDWA were amended to exclude hydraulic fracturing from the definition of “underground injection” under certain circumstances. However, the repeal of this exclusion has been advocated by certain organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, or have been proposed in recent sessions of Congress. Citing concerns over the potential for hydraulic fracturing to impact drinking water, human health and the environment, and in response to a congressional mandate, the EPA has commissioned a study to identify potential risks associated with hydraulic fracturing. The EPA finalized its plan for the study in November 2011. The initial study results are expected to be available by late 2012 and the final report is scheduled to be completed by 2014. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, require the public disclosure of chemicals used in the hydraulic fracturing process, or otherwise regulate operations using hydraulic fracturing. For example, Texas adopted a law requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic fracturing process. Also, the EPA has proposed new emission standards that would apply to operations at newly constructed or reconstructed hydraulically-fractured wells. Depending on the results of the EPA study and other developments related to the impact of hydraulic fracturing, our drilling activities could be subjected to new or enhanced federal, state and/or local regulatory requirements governing hydraulic fracturing and such requirements, if adopted, could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.

Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The EPA has proposed new rules to address air emissions from the oil and natural gas industry which, among other things, would require installation of equipment to capture certain gases released from new or refitted wells. The proposals would revise New Source Performance Standards for volatile organic compounds and sulfur dioxide, impose controls on toxics emitted at oil and natural gas wells and their associated production facilities, and limit fugitive emissions from the production, storage and transport equipment. In addition, states impose requirements to address emissions from certain production and associated facilities. We have complied and will continue to comply with these regulations as applicable to our operations. Due to the uncertainties surrounding proposed regulations, we are unable to predict the financial impact going forward.

Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary fines and/or correction of any identified deficiencies. Alternatively, civil and criminal liability can be imposed for non-compliance. Any such action could require us to forego construction or operation of certain air emission sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit application were denied, we would have enough permitted or permittable capacity to continue our operations without a material adverse effect on any particular producing field.

 

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Climate Change. According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases (“GHG”) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (“CAA”) definition of an “air pollutant”, and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The EPA has promulgated rules requiring owners or operators of certain petroleum and natural gas systems that emit 25,000 metric tons or more of GHG per year from a facility to report such emissions and we are subject to this reporting requirement. In addition, the EPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on our current operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Further, apart from these developments, recent judicial decisions that have allowed certain tort claims alleging property damage, to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

Coastal Coordination. There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (the “CZMA”) was passed to preserve and, where possible, restore the natural resources of the coastal zone of the United States. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development.

The Louisiana Coastal Zone Management Program (the “LCZMP”) was established to protect, develop and, where feasible, restore and enhance coastal resources of the State of Louisiana. Under the LCZMP, coastal use permits are required for certain activities, even if the activity only partially infringes on the coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and natural gas, and pipelines for the gathering, transportation or transmission of oil, natural gas and other minerals require such permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and natural gas activities. The LCZMP and its requirement to obtain coastal use permits may result in our having to satisfy additional permitting requirements and could potentially cause project schedule constraints.

The Texas Coastal Coordination Act (the “CCA”) provides for coordination among local and state authorities to protect coastal resources through regulating land use, water and coastal development and establishes the Texas Coastal Management Program (the “CMP”) that applies in the 19 Texas counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the CMP. This review process may affect agency permitting and may add a further regulatory layer to some of our projects.

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. OSHA hazard communication standards, the EPA community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens.

Competition

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

 

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Operating Hazards and Uninsured Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including unexpected drilling conditions, low oil and natural gas prices, title problems, pressure or irregularities in formations, delays by project participants, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements, shortages or delays in the delivery of equipment and services and increases in the cost for such equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, mechanical failures, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and those of others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, loss of surface equipment at well locations, trespass or surface damage attributable to seismic operations, business interruption, loss of revenues due to low commodity prices or loss of revenues due to well failure. Furthermore, in certain circumstances in which insurance is available, we may not purchase it. The occurrence of an event that is not covered, or not fully covered by insurance, could have a material adverse effect on our business, financial condition, results of operations and cash flows in the period such event may occur.

Employees

As of December 31, 2011, we had 114 employees. We have a land department staff that includes four landmen, an exploration staff that includes three geologists, one geophysicist and one geological technician and an operations staff that includes seven engineers. We believe that our relationships with our employees are satisfactory.

Offices

We currently lease and sublease, through Hydro Gulf Of Mexico, L.L.C., 49,230 square feet of executive and corporate office space located at 1301 McKinney in Houston, Texas. Rent expense related to this office space for the twelve months ended December 31, 2011 was approximately $1.8 million. The lease term extends to August 31, 2017.

Item 1A. Risk Factors

Our acquisition, exploitation and development projects require substantial capital expenditures. We may have difficulty financing our planned capital expenditures, which could adversely affect our business, financial condition and results of operation.

The oil and natural gas industry is capital intensive. We make, and intend to continue to make, substantial capital expenditures in our acquisition, exploitation and development projects. While we intend to finance our future capital expenditures through a variety of sources, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. Additionally, we expect that future acquisitions will require funding, at least in part, from the issuance of equity securities. We may not be able to secure additional debt financing or the additional equity financing required for acquisitions on reasonable terms or at all. Financing may not continue to be available to us under our existing or new financing arrangements. If additional capital resources are unavailable, we may be forced to curtail our drilling, development and other activities or sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operations.

 

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Oil and natural gas prices are volatile and we may not be able to meet our hedging goals. A substantial or extended decline in oil or natural gas prices could adversely affect our results of operations.

Our revenues, operating results and future rate of growth depend upon the prices we receive for our oil and natural gas production. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Although we will seek to enter into commodity price hedging contracts for additional volumes of our expected proved developed producing production, approximately 74% and 72% of our expected 2012 and 2013 proved developed producing production, respectively, has been hedged as of December 31, 2011, based on forecasted production set forth in our most recent reserve report. We cannot assure you that we will be able to meet our goal of increasing the level of our hedges for expected proved developed producing production by any certain date or at all or that our level of hedges in 2012 and 2013 will remain the same if actual production is different from expected production. To the extent we are not hedged, we will sell our oil and natural gas at current market prices, which exposes us to the risks associated with volatile commodity prices. In addition, the prices that we receive for our oil and natural gas production generally trade at a discount to the relevant benchmark prices such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials.

The markets and prices for oil and natural gas depend on numerous factors beyond our control. These factors include demand for oil and natural gas, which fluctuate with changes in market and economic conditions and other factors, including:

 

   

worldwide and domestic supplies of oil and natural gas;

 

   

actions taken by foreign oil and natural gas producing nations;

 

   

political conditions and events (including instability or armed conflict) in oil producing or natural gas producing regions;

 

   

the level of global and domestic oil and natural gas inventories;

 

   

the price and level of foreign imports including liquefied natural gas imports;

 

   

the level of consumer demand;

 

   

the price and availability of alternative fuels;

 

   

the availability of pipeline or other takeaway capacity;

 

   

weather conditions;

 

   

technological advances affecting energy consumption;

 

   

domestic and foreign governmental regulations and taxes; and

 

   

the overall worldwide and domestic economic environment.

Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:

 

   

adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

 

   

reduce the amount of oil and natural gas that we can produce economically;

 

   

cause us to delay or postpone some of our capital projects;

 

   

reduce our revenues, operating income and cash flow;

 

   

reduce the carrying value of our oil and natural gas properties; and

 

   

limit our access to sources of capital.

 

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Our level of indebtedness may adversely affect our cash available for operations.

As of December 31, 2011, we had approximately $381.9 million in outstanding indebtedness and had approximately $40.4 million of available borrowing capacity under our amended and restated first lien credit agreement (the “2011 Credit Facility”). Our level of indebtedness will have several important effects on our operations, including:

 

   

we will dedicate a portion of our cash flow from operations to the payment of interest on our indebtedness and to the payment of our other current obligations and will not have that portion of cash flow available for other purposes;

 

   

our debt agreements limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions;

 

   

our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired;

 

   

we may be more vulnerable to economic downturns and our ability to withstand sustained declines in oil and natural gas prices may be impaired;

 

   

since outstanding balances under our 2011 Credit Facility are subject to variable interest rates, we are vulnerable to increases in interest rates;

 

   

our flexibility in planning for or reacting to changes in market conditions may be limited; and

 

   

we may be placed at a competitive disadvantage compared to our competitors that have less indebtedness.

We have had losses in the past and there is no assurance of our profitability for the future.

We recorded a net loss for the years ended December 31, 2011, 2010 and 2009 of $23.6 million, $70.6 million and $8.6 million, respectively. We cannot assure you that our current level of operating results will continue or improve. Our activities could require additional equity or debt financing. Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of oil and natural gas, 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 and results of operations.

We cannot assure you that we will be able to improve our leverage position.

A significant element of our business strategy involves improving our ratio of debt to EBITDA and the aggregate value of our assets. However, we are also seeking to acquire, exploit and develop additional reserves which may require the incurrence of additional indebtedness. Although we will seek to improve our leverage position, our ability to reduce our level of indebtedness depends on a variety of factors, including future performance. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to improve our leverage position. Many of these factors are beyond our control.

Although our oil and natural gas reserve data is independently estimated, these estimates may still prove to be inaccurate.

Our proved reserve estimates are prepared each year by W.D. Von Gonten & Co., our independent consulting petroleum engineers. In conducting their evaluation, the engineers and geologists of W.D. Von Gonten & Co. evaluate our properties and independently develop proved reserve estimates. There are numerous uncertainties and risks that are inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and timing of development expenditures, and those estimates and projections are subject to many factors that are beyond our control. Factors and assumptions taken into account in our estimates and projections include:

 

   

expected reservoir characteristics based on geological, geophysical and engineering assessments;

 

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future production rates based on historical performance and expected future operating and investment activities;

 

   

future oil and natural gas prices and quality and location differentials; and

 

   

future development and operating costs.

Although we believe the independent reserve estimates of W.D. Von Gonten & Co. are reasonable based on the information available to them at the time they prepare their estimates, our actual results could vary materially from these estimated quantities of proved oil and natural gas reserves (in the aggregate and for a particular location), production, revenues, taxes and development and operating expenditures. In addition, these estimates of net proved reserves may be subject to downward or upward revision based upon production history, results of future exploitation and development, prevailing oil and natural gas prices, operating and development costs and other factors.

Finally, recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations. At December 31, 2011, approximately 39% of our estimated net proved reserves were classified as undeveloped. At December 31, 2011, we estimated that it would require additional capital expenditures of approximately $190.7 million to develop our proved undeveloped reserves. Our reserve estimates assume that we can and will make these expenditures and conduct these operations successfully, which may not occur, and as a result, we may not be able to recover or develop our proved undeveloped reserves.

Lower oil and natural gas prices may cause us to record ceiling limitation impairments, which would increase our stockholders’ deficit.

We use the full cost method of accounting for our oil and natural gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of oil and natural gas properties may not exceed a “ceiling limit” that is based upon the present value of estimated future net revenues from net proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties and other adjustments as required by Regulation S-X under the Securities Act. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation impairment.” The risk that we will experience a ceiling limitation impairment increases when oil and natural gas prices are depressed, if we have substantial downward revisions in estimated net proved reserves or if estimates of future development costs increase significantly. In 2009 we had a ceiling limitation impairment of approximately $39.6 million and in 2011 we had a ceiling limitation impairment of approximately $18.2 million. Although we did not have a ceiling limitation impairment in 2010, no assurance can be given that we will not experience a ceiling limitation impairment in future periods. For more information about our prior impairments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Critical Accounting Policies — Oil and Natural Gas Properties.”

The instrument governing our indebtedness contains significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.

The instruments governing our indebtedness contain customary restrictions on our activities, including covenants that restrict our and our subsidiaries’ ability to:

 

   

incur additional indebtedness;

 

   

pay dividends on, redeem or repurchase stock;

 

   

create liens;

 

   

make specified types of investments;

 

   

apply net proceeds from certain asset sales;

 

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engage in transactions with our affiliates;

 

   

engage in sale and leaseback transactions;

 

   

merge or consolidate;

 

   

restrict dividends or other payments from subsidiaries;

 

   

sell equity interests of subsidiaries; and

 

   

sell, assign, transfer, lease, convey or dispose of assets.

The indenture governing our 10.500% Senior Secured Second Lien Notes due 2016 (the “Notes”) contains certain incurrence-based covenants that limit our ability to incur indebtedness and engage in other transactions. One of these covenants incorporates the net present value of our net proved reserves calculated based on SEC rules. Our ability to increase our borrowings in 2012 will depend, in part, on prices for oil and natural gas and our drilling results at the time of redetermination. Our 2011 Credit Facility also requires us to meet a minimum current ratio, a minimum interest coverage ratio and leverage ratios relating to both total debt to EBITDA and total senior debt to EBITDA. We may not be able to maintain or comply with these ratios, and if we fail to be in compliance with these covenants, we will not be able to borrow funds under our 2011 Credit Facility, which would make it difficult for us to operate our business.

The restrictions in the instruments governing our indebtedness may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future indebtedness obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements or that we will be able to refinance our indebtedness on terms acceptable to us, or at all.

The breach of any of these covenants and restrictions could result in a default under the instruments governing our indebtedness. An event of default under our debt agreements would permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness, lenders having secured obligations could exercise their rights and remedies against the collateral securing the indebtedness. Because the indenture governing the Notes and the agreements governing our 2011 Credit Facility have customary cross-default provisions, if the indebtedness under either or any future facilities is accelerated, we may be unable to repay or refinance the amounts due.

We expect that it will be necessary to raise equity capital in order to finance most of our acquisitions. An inability to raise equity capital would limit our ability to acquire additional reserves.

As a result of our existing levels of indebtedness, we expect that it will be necessary to fund future acquisitions, at least in part, with the net proceeds of equity financings. Our ability to obtain equity financing will depend, among other things, on our level of success with our exploitation and development activities and general conditions in the capital markets at the time funding is sought. We may not be able to secure equity financing on reasonable terms or at all. If additional capital resources are unavailable, we may not be able to pursue acquisitions of additional reserves or otherwise execute our business strategy.

We may incur additional indebtedness, which could further exacerbate the risks associated with our substantial leverage.

We may incur substantial additional indebtedness in the future. The indenture governing the Notes and the agreements governing our 2011 Credit Facility contain restrictions on our ability to incur indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions will not prevent us from incurring obligations that do not constitute “Indebtedness” under the indenture and the 2011 Credit Facility, respectively. If we incur indebtedness above our current levels, the related risks that we now face could intensify and we may not be able to meet all our debt obligations. Failure to meet these obligations could result in a default under our debt agreements, which could adversely affect our business, financial condition and results of operations.

 

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Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and our ability to raise capital.

The current reserve to production ratio of our properties is 12.9 years. As a result, unless we conduct successful development and exploitation activities or acquire properties containing net proved reserves, our net proved reserves will decline as those reserves are produced. Producing oil and natural gas are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. In particular, approximately 50% of our total net proved reserves and approximately 64% of our total production were in our Texas Gulf Coast and Southeast areas. Reservoirs in our Texas Gulf Coast and Southeast areas are characterized by high initial production rates followed by steep declines in production, resulting in a reserve life for wells in this area that is shorter than the industry average. Our future oil and natural gas 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. If we are unsuccessful in acquiring or developing additional producing reserves, our production and revenues will decline as our current reserves are depleted. We cannot assure you that we will be able to develop, exploit, find or acquire additional reserves sufficient to replace our current and future production on an economic basis or at all.

Economic uncertainty could negatively impact the prices for oil and natural gas, limit access to the credit and equity markets, increase the cost of capital, and may have other negative consequences that we cannot predict.

Economic uncertainty in the United States, Europe and Asia could create financial challenges if conditions do not improve. Standard & Poor’s downgraded the U.S. credit rating to AA+ from its top rank of AAA and more recently has downgraded the credit ratings for several countries in Europe, which has increased the possibility of other credit-rating agency downgrades which could have a material adverse effect on the financial markets and economic conditions in the United States and throughout the world. Our internally generated cash flow and cash on hand historically have not been sufficient to fund all of our expenditures, and we have relied on, among other things, bank financings and private equity to provide us with additional capital. Our ability to access capital may be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations is less than anticipated and our access to capital is restricted, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult and less economic to consummate. Additionally, demand for oil and natural gas may deteriorate and result in lower prices for oil and natural gas, which could have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.

Our ability to meet our indebtedness obligations and other expenses will depend on our future performance, which will be subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our 2011 Credit Facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.

If we are unable to meet our debt service obligations, we may be required to seek a waiver or amendment from our debt holders, refinance such debt obligations or sell assets or additional equity. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to meet our debt obligations could result in a default under our debt agreements. An event of default under our debt agreements will permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness, lenders having secured obligations could proceed against the collateral securing the indebtedness. Because the indenture governing the Notes and the agreements governing our 2011 Credit Facility have customary cross-default provisions, if the indebtedness under the Notes or under our 2011 Credit Facility is accelerated, we may be unable to repay or finance the amounts due.

 

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We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We currently operate approximately 56.9% of our properties, based on producing wells at December 31, 2011. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

 

   

the timing and amount of capital expenditures;

 

   

the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

 

   

the operator’s expertise and financial resources;

 

   

approval of other participants in drilling wells;

 

   

selection of technology; and

 

   

the rate of production of the reserves.

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

In an attempt to reduce our sensitivity to energy price volatility and in particular to downward price movements, we enter into hedging arrangements with respect to a portion of our expected production, such as the use of derivative contracts that generally result in a range of minimum and maximum price limits or a fixed price over a specified time period. Even if we are successful in our strategy to increase our hedging activities, such activities may expose us to the risk of financial loss in certain circumstances. For example, if we do not produce our oil and natural gas reserves at rates equivalent to our derivative position, we would be required to satisfy our obligations under those derivative contracts on potentially unfavorable terms without the ability to offset that risk through sales of comparable quantities of our own production. Additionally, because the terms of our derivative contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation and marketing costs to delivery points, substantial differences between the prices we receive pursuant to our derivative contracts and our actual results could harm our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and natural gas prices. We also could be financially harmed if the counterparties to our derivative contracts prove unable or unwilling to perform their obligations under such contracts. Additionally, before our 2010 recapitalization (as described below under “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Overview”), some of our derivative contracts required us to deliver cash collateral or other assurances of performance to the counterparties if our payment obligations exceeded certain levels. No cash collateral requirements characterize our current liability hedging positions. Future collateral requirements are uncertain but will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and future rules and regulations promulgated by the Commodities Futures Trading Commission (“CFTC”), pursuant to the mandate of the United States Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act. See also “— Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.”

 

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

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, crews, equipment, supplies, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. If increasing levels of exploitation and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in our areas of operation, our results of operations could be materially and adversely affected.

We depend on our key management personnel and technical experts and the loss any of these individuals could adversely affect our business.

If we lose the services of our key management personnel or technical experts, or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could be adversely affected. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas exploitation and development projects. The loss of the services of one or more members of our senior management or technical teams could have a negative effect on our business, financial condition, results of operations and future growth.

Our properties are located in regions which make us vulnerable to risks associated with operating in one major contiguous geographic area, including the risk and related costs of damage or business interruptions from hurricanes.

Our properties are primarily located onshore and in state and federal waters along the Texas and Louisiana Gulf Coast region of the United States. As a result of this geographic concentration, we are disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations and other factors. This is particularly true of our inland water drilling and offshore operations, which are susceptible to hurricanes and other tropical weather disturbances. Such disturbances have in the past and will in the future have any or all of the following adverse effects on our business:

 

   

interruptions to our operations as we suspend production in advance of an approaching storm;

 

   

damage to our facilities and equipment, including damage that disrupts or delays our production;

 

   

disruption to the transportation systems we rely upon to deliver our products to our customers; and

 

   

damage to or disruption of our customers’ facilities that prevents us from taking delivery of our products.

For example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production for approximately 30 days. Although we maintain property and casualty insurance, we cannot predict whether we will continue to be able to obtain insurance for hurricane-related damages or, if obtainable and carried, whether this insurance will be adequate to cover our liabilities. In addition, we expect any insurance of this nature to be subject to substantial deductibles and to provide for premium adjustments based on claims. Any future hurricane-related costs and work interruptions could adversely affect our operations and financial condition.

 

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Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended.

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production in paying quantities is established during their primary terms or we obtain extensions of the leases. Our drilling plans for our undeveloped leasehold acreage are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Because of these uncertainties, we do not know if our undeveloped leasehold acreage will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. If our leases expire, we will lose our right to develop the related properties on this acreage. As of December 31, 2011, we had leases representing 3,207 net acres expiring in 2012, 1,912 net acres expiring in 2013, and 4,229 net acres expiring in 2014. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Availability under our 2011 Credit Facility is based on a borrowing base that is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to post additional assets as collateral or repay amounts outstanding under our 2011 Credit Facility.

Under the terms of our 2011 Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our net proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination during each six-month period between borrowing base determinations. In the past, the borrowing base under our credit agreements has been reduced as a result of, among other things, changes in pricing, production, monetization of unrealized hedging gains and our disposition of assets included in the then-current borrowing base. A reduction in our borrowing base below the amount outstanding under our 2011 Credit Facility will result in a borrowing base deficiency requiring us to cure such deficiency by posting additional assets as collateral or repaying a portion of the loan under the 2011 Credit Facility over a period no longer than five months. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our 2011 Credit Facility or sell assets. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to cure a borrowing base deficiency could result in a default under our 2011 Credit Facility, which could adversely affect our business, financial condition and results of operations.

Our exploitation, development and drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

We require significant amounts of undeveloped leasehold acreage to further our development efforts. Exploitation, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us in areas that we pursue will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. Wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results is dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

Although we aim to control and reduce our drilling and production costs to improve our overall return, the cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

 

   

unexpected drilling conditions;

 

   

low prices for oil and natural gas;

 

   

title problems;

 

   

pressure or irregularities in formations;

 

   

delays by project participants;

 

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equipment failures or accidents;

 

   

adverse weather conditions;

 

   

compliance with governmental requirements;

 

   

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

 

   

increases in the cost for equipment and services.

We may not drill all of our potential drilling locations and drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.

Our drilling locations are in various stages of evaluation, ranging from locations that are ready to be drilled to potential locations that will require substantial additional evaluation and interpretation. A decision to drill any specific well on our inventory of potential well locations may not be made for many years, if at all. If a decision is made to drill, we cannot conclusively predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover our drilling or completion costs or to be economically viable. Our use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil and natural gas will be present or, if present, whether oil and natural gas will be present in commercial quantities.

The analysis that we perform using data from other wells, more fully explored prospects and/or analogous producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling locations. As a result, we may not find commercially viable quantities of oil and natural gas and, therefore, we may not achieve a targeted rate of return or have a positive return on investment.

The marketability of our oil and natural gas production depends on services and facilities that we typically do not own or control. The failure or inaccessibility of any such services or facilities could affect market based prices or result in a curtailment of production and revenues.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of oil and natural gas gathering and transportation systems, pipelines and processing facilities. We generally deliver oil at our leases under short-term trucking contracts. Counterparties to our short-term contracts rely on access to regional transportation systems and pipelines. If transportation systems or pipeline capacity is constrained, we would be required to find alternative transportation modes, which would impact the market based price that we receive, or temporarily curtail production. We generally sell our natural gas production at the wellhead. The transportation of our natural gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. If any of the pipelines or other facilities that we use to transport our natural gas production become unavailable, we would be required to find a suitable alternative to transport and process the natural gas, which could increase our costs and reduce the revenues we might obtain from the sale of the natural gas. For example, in 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production for approximately 30 days.

We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as:

 

   

fires;

 

   

natural disasters;

 

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formations with abnormal pressures;

 

   

blowouts, mechanical failures and explosions; and

 

   

pipeline ruptures and spills.

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

We cannot predict all liabilities and costs related to expanding our geographic diversity. The incurrence of material unanticipated liabilities could have a material adverse effect on our business, financial condition and results of operation.

We intend to grow our reserve base primarily through asset acquisitions and the further exploitation and development of acquired and existing assets, with a focus on properties that are weighted towards oil or NGLs and provide greater geographic diversity. Historically we have operated properties only in the Gulf Coast region. We cannot assure you that we will be successful in expanding our operations into regions outside of our core areas. Operating in areas outside the Gulf Coast region may expose us to unanticipated liabilities and costs, some of which may be material. As a result, the anticipated benefits of moving into the region may not be fully realized, if at all, which could have a material adverse effect on our business, financial condition and results of operation.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

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 results 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 resources 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.

 

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We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.

We maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We may elect not to carry insurance if our management believes that the cost of insurance is excessive relative to the risks presented. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution and environmental risks.

The loss of a significant customer could in the short term have a material adverse impact on our financial results.

During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 16% and Shell Trading (US) Company accounting for 17%. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Enterprise Crude Oil LLC accounting for 11% and Shell Trading (US) Company accounting for 19%. During 2009, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 16%. Although we believe that the availability of other potential purchasers would limit the effects of the loss of one or more of these customers, such a loss could in the short term have a material adverse effect on our results of operations.

Our future operating results may fluctuate and significant declines in them may limit our ability to invest in projects.

Our future operating results may fluctuate significantly depending upon a number of factors, including:

 

   

industry conditions;

 

   

prices of oil and natural gas;

 

   

rates of drilling success;

 

   

availability of capital resources;

 

   

rates of production from completed wells; and

 

   

the timing and amount of capital expenditures.

This variability could cause our business, financial condition and results of operations to suffer. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our ability to invest and participate in economically attractive projects.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our 2011 Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase, although the amount borrowed would remain the same, and our net income and cash available for servicing our indebtedness would decrease. A significant increase in our interest expense could adversely affect our business, financial condition and results of operations.

We face significant competition and many of our competitors have resources in excess of our available resources.

We operate in the highly competitive areas of oil and natural gas exploitation, acquisition and production. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent oil and natural gas companies in a number of areas such as:

 

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seeking to acquire desirable producing properties or new leases for future exploitation;

 

   

seeking to hire professional personnel;

 

   

seeking to acquire the equipment and expertise necessary to operate and develop those properties; and

 

   

marketing our oil and natural gas production.

Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could harm our business.

We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal, state and local laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or what effect any changes and interpretations may have on our business or financial condition. Our business is subject to laws and regulations promulgated by federal, state and local authorities, including but not limited to, the United States Congress, the Federal Energy Regulatory Commission, the EPA, the BLM, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Texas Railroad Commission, the Texas Commission on Environmental Quality, the Oklahoma Corporation Commission, the Oklahoma Department of Environmental Quality, the Louisiana Department of Natural Resources, the Louisiana Department of Environmental Quality, the Mississippi Department of Environmental Quality and the Mississippi Oil & Gas Board, relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas or pollutants into the air, soil or water may give rise to significant liabilities to the government and third parties and may require us to incur substantial costs for remediation.

Our operations are subject to complex federal, state and local environmental laws and regulations, including the federal Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act (the “CAA”) and the Clean Water Act. Administration of the federal laws is often delegated to the states. Environmental laws and regulations are subject to change, and the implementation of new, or the modification of existing, laws or regulations could impose significant additional burdens. For example, hydraulic fracturing and associated processes, which are used in our operations to maximize oil and gas production, are undergoing increased public and regulatory scrutiny due to concerns relating to potential impact on environmental and geologic resources. These concerns are being evaluated by federal and state regulatory agencies and may result in new regulatory requirements. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if changes in requirements are imposed. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities. In addition, the EPA has recently announced its intention to develop discharge standards for wastewater produced by natural gas extraction from shale formations. Proposed rules are expected in 2014. At this time, we cannot predict the impact that these standards may have on our business.

Failure to comply with environmental, health and safety laws or regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining or limiting our current or future operations. Compliance with these laws and regulations also increases the cost of our operations and may prevent or delay the commencement or continuance of a given operation.

Under certain environmental laws that impose strict, joint and several liability, we may be required to perform remediation on our properties to address historical conditions. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health, or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.

 

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We do not know how the ongoing reorganization of the BOEMRE will impact potential future regulations or enforcement that may affect our business.

On May 19, 2010, the U.S. Department of the Interior announced that it would reorganize the Minerals Management Service by dividing its offshore oil and gas responsibilities among three separate agencies. Shortly thereafter, on June 18, 2010, the Minerals Management Service was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”). The BOEMRE currently regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf, and removal of facilities. On October 1, 2010, the first phase of reorganization took place when the revenue collection arm of the former Mineral Management Service became the Office of Natural Resources Revenue. On October 1, 2011, the U.S. Department of the Interior officially created the Bureau of Ocean Energy Management, which will have responsibility for leasing, resource evaluation and environmental studies, and the Bureau of Safety and Environmental Enforcement, which will have responsibility for field operations, including inspections, regulatory compliance, permitting and oil spill response. At this point, the BOEMRE ceased to exist. We have a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of Louisiana which are subject to jurisdiction of these agencies. We do not know how the ongoing reorganization will impact potential future regulations or enforcement that may affect our business.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act ( the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and natural gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. In November 2011, the CFTC published final rules that establish position limits for futures contracts on 28 physical commodities, including four energy commodities, and swaps, futures and options that are economically equivalent to those contracts. The rules provide an exemption for “bona fide hedging” transactions or positions, but this exemption is narrower than the exemption under existing CFTC position limit rules. The new limits generally will go into effect 60 days after the term “swap” is further defined pursuant to Section 721 of the Dodd-Frank Act. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be materially impacted by position limits and other regulatory requirements, the impact upon our businesses will depend on whether the derivative contracts we enter into are exempt from position limits as bona fide hedging transactions.

Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

The adoption of climate change legislation by Congress could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities and result in reduced demand for the oil and natural gas we produce.

According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases (“GHG”) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the definition of an “air pollutant”, and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The EPA has also promulgated rules requiring owners or operators of certain petroleum and natural gas systems that emit 25,000 metric tons or more of GHG per year from a facility to report such emissions and we are subject to this reporting requirement. In addition, the EPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently written and based on our current operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Further, apart from these developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

 

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Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products could become more desirable in a market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations. Any laws or regulations that may be adopted to restrict or reduce emissions of GHG could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to our operations and the refining, processing, and use of oil and natural gas.

Our ability to use net operating losses to offset future taxable income may be subject to certain limitations.

As of December 31, 2011, we had federal net operating loss carryforwards (“NOLs”) of $42.2 million to offset future taxable income, which expire in various years beginning in 2030, which if fully utilized will result in a tax savings of $14.8 million. See Note 12- “Income Taxes” to our audited consolidated financial statements elsewhere herein for more. As a result of the evaluation of the likelihood that the deferred tax asset will not be realized, we applied a valuation allowance for this deferred tax asset along with all other deferred tax assets that are a result of normal differences in GAAP treatment and applicable tax laws. This valuation will be assessed in the future based on relevant financial data and projections. In addition, under Section 382 of the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), a corporation that experiences a more-than 50 percent ownership change over a three-year testing period is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income.

We must increase our staff and will incur increased costs as a result of being a reporting company.

As a result of the completion of an exchange offer in November 2011, we became subject to the Exchange Act, and as a result are required to comply with the reporting obligations of a publicly traded company. We have, and must continue to, hire additional personnel or engage third party providers to meet our obligations with respect to internal controls and disclosure requirements. We also expect to engage additional accounting resources. In addition, we anticipate that our director and officer liability insurance premiums will increase. These additional obligations and responsibilities will require us to incur significant legal, accounting and other expenses that we did not incur as a non-reporting private company.

We have identified material weaknesses in our internal control over financial reporting.

We have identified material weaknesses in our internal control over financial reporting related to inconsistent or ineffective financial statement review and preparation and insufficient financial reporting resources. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected and corrected on a timely basis.

Although we intend to take appropriate steps to remediate these material weaknesses, we cannot assure you that we will be able to do so in a timely manner, that our initiatives will prove to be successful or that additional material weaknesses will not be identified in the future. Failure to identify material weaknesses in our internal controls in a timely manner, or the identification of material weaknesses in the future, will impair our ability to record, process, summarize and report financial information accurately, timely and in accordance with SEC rules. The failure could also negatively affect the trading liquidity of our notes, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties and adversely impact our business and financial condition.

 

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Item 1B. Unresolved Staff Comments

Not Applicable.

Item 3. Legal Proceedings

There are currently various suits and claims pending against us that have arisen in the ordinary course of our business, including contract disputes and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on our consolidated financial position, results of operations or cash flow. We record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Item 4. Mine Safety Disclosures

Not Applicable.

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

There is no established public trading market for our common stock.

Holders

As of March 29, 2012, Milagro Holdings, LLC, our parent company (“Holdings”), is the sole record holder of our common stock.

Dividends

Our 2011 Credit Facility and the indenture governing the Notes, as well as the terms of our Series A preferred stock, restrict dividend payments by us on our common stock. We presently do not plan to pay future cash dividends.

Securities Authorized for Issuance Under Equity Compensation Plans

We have no outstanding equity compensation plans under which our securities are authorized for issuance. Equity compensation plans are maintained by Holdings, our parent company.

Recent Sales of Unregistered Securities

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

 

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Item 6. Selected Financial Data

The following table presents our selected historical financial data as of and for the one month ended December 31, 2007 and for the years 2008 through 2011. The statement of operations data for each of the years ended December 31, 2009 through 2011 and the balance sheet data as of December 31, 2010 and 2011 set forth below are derived from our audited financial statements and the notes thereto included elsewhere in this document. The balance sheet data as of December 31, 2007, 2008 and 2009 and statement of operations data for the year ended December 31, 2008, set forth below are derived from our audited financial statements. The statement of operations data for the one month ended December 31, 2007 is derived from our unaudited financial records. You should read this selected financial data in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto included elsewhere in this document.

The table below does not include selected statements of operations and balance sheet data for our predecessor as for the eleven months ended November 30, 2007. A combination of factors results in our inability to provide the 2007 selected historical financial data noted above without unreasonable effort and expense. These factors are: 1) our predecessor was not accounted for as a separate entity, subsidiary, or division by the previous owner, and as a result, the selected financial data for the predecessor for the eleven months ended November 30, 2007 was not prepared and does not exist, and 2) we did not acquire the employees of the predecessor and as such the time and expense associated with preparing the applicable selected financial data for the predecessor would be unreasonable.

 

     Years Ended December 31,     One Month
Ended
December 31,
 
     2011     2010     2009     2008     2007  
     (In thousands)  

Operating data:

          

Revenues:

          

Oil and natural gas revenues

   $ 138,210      $ 134,207      $ 128,782      $ 360,294      $ 27,978   

Hedge gains/(loss)

     15,577        22,943        25,606        50,259        (18,231
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

   $ 153,787      $ 157,150      $ 154,388      $ 410,553      $ 9,747   

Costs and Expenses:

          

Operating costs

   $ 48,551      $ 46,469      $ 43,484      $ 71,011      $ 5,948   

General and administrative(1)

     16,483        17,469        18,849        19,499        3,549   

Other

     72,609        56,899        111,249        576,367        12,954   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

   $ 137,643      $ 120,837      $ 173,582      $ 666,877      $ 22,451   

Other (income) expense:

          

Other (income) expense

   $ 39,718      $ 49,479      $ 46,864      $ 62,588      $ 6,436   

Total other (income) expense

     39,718        49,479        46,864        62,588        6,436   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Loss before income tax

     (23,574     (13,166     (66,058     (318,912     (19,140

Income tax expense (benefit)(2)

     —          57,422        (57,422     —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (23,574   $ (70,588   $ (8,636   $ (318,912   $ (19,140
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Preferred dividends(4)

     18,634        —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net loss available to common stockholders

   $ (42,208   $ (70,588   $ (8,636   $ (318,912   $ (19,140
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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     As of December 31,  
     2011     2010     2009     2008     2007  
     (In thousands)  

Balance sheet data:

          

Cash and cash equivalents

   $ 9,356      $ 17,734      $ 10,531      $ —        $ —     

Net property, plant and equipment

     483,062        453,185        392,904        515,822        895,426   

Total assets

     553,777        522,198        526,060        622,588        972,450   

Long-term debt including current portion

     381,879        560,600        491,550        544,922        590,750   

Mezzanine equity(4)

     234,558        —          —          —          —     

Stockholders’ (deficit) equity

     (159,404     (135,830     (67,032     (60,251     256,709   

Total liabilities and stockholders’ deficit

     553,777        522,198        526,060        622,588        972,450   

 

(1) Includes compensation expenses attributable to the issuance of Class C membership profits interests in our parent company, Holdings, to our officers and employees. For the years ended December 31, 2011, 2010, 2009 and 2008, such expenses were zero, $1,788, $1,951 and $1,951, respectively, and for the one month ended December 31, 2007, such expenses were $163. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” for more on the ownership of the Class C membership profits interests.
(2) Effective on August 1, 2009, we converted from a limited liability company to a corporation under Sub Chapter C of the Internal Revenue Code of 1986, as amended.
(3) On January 13, 2010, we entered into agreements to exchange a portion of our prior second lien debt and accrued interest for $205.5 million of our Series A preferred stock, consisting of 2,700,000 shares issued at $76.12 per share that were mandatorily redeemable in 2016. These shares were classified as a liability in the financial statements as they were mandatorily redeemable for cash.
(4) On May 11, 2011, we amended the terms of our Series A preferred stock. The amendment made the Series A preferred stock a perpetual instrument and removed the mandatory redemption. The amended Series A preferred stock is redeemable at the option of the holder in 2016, and, as a result of the amendment, the Series A preferred stock was reclassified from long-term debt to mezzanine equity.

 

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

You should read the following discussion and analysis of our financial condition and results of operations together with our consolidated financial statements and the related notes and other financial information included elsewhere in this report. Some of the information contained in this discussion and analysis or set forth elsewhere in this report, including information with respect to our plans and strategy for our business and related financing, include forward-looking statements that involve risks and uncertainties. You should review the section entitled “Risk Factors” included elsewhere herein for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

Overview

We are an independent oil and gas company primarily engaged in the acquisition, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. We have acquired proved producing reserves that we believe have upside potential, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent area.

In 2010, in order to improve our liquidity and capital structure and to resolve the events resulting in forbearances under our prior first lien credit agreement and prior second lien credit agreement, we effected a recapitalization through, among other things, (i) the discharge of approximately $194.7 million of prior second lien indebtedness through the issuance of Series A preferred stock, (ii) the conversion of approximately $56.2 million of prior second lien indebtedness into indebtedness under our prior second lien PIK credit agreement, and (iii) the conversion of the remaining $30.0 million of prior second lien indebtedness to indebtedness under our existing second lien term loan agreement. In addition, as part of the recapitalization, we received $60.0 million in new capital though the funding of $25.0 million in term loans and $35.0 million delayed draw loan under our existing second lien term loan agreement.

In connection with the 2010 recapitalization, and in response to changes in the business environment, we modified our business strategy by moving away from a primary focus on exploration to a more balanced approach of acquisition, exploitation, development and lower risk exploration. Our 2011 capital budget contemplated spending approximately $32.6 million in connection with the drilling of 12 additional wells, including three development wells in the Texas Gulf Coast, three development wells in the Southeast area, one development well in the South Texas area and five wells in the Midcontinent area, and spending approximately $5.0 million in connection with the workover and recompletion of existing wells. Our 2011 capital budget also included approximately $36.0 million for acquisitions. See “-Liquidity and Capital Resources” for more on our capital expenditures.

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250.0 million of the 2011 Notes. We used the proceeds of this offering, together with borrowings under our 2011 Credit Facility, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”).

We intend to fund our future capital expenditures through a variety of means, including cash flow from operations, borrowings under our 2011 Credit Facility, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.

Sources of Our Revenues

We derive our revenues from the sale of oil and natural gas that are produced from our properties. Our revenues are a function of the production volumes we sell and the prevailing market prices at the time of sale. Under the terms and conditions of our 2011 Credit Facility, we are required to hedge at least 50%, but no more than 90%, of our monthly forecasted proved developed producing (“PDP”) production by product. We are permitted to use zero-cost collars and out-right swaps with approved counterparties to meet this requirement. The approved counterparties are limited to those financial institutions that participate in the 2011 Credit Facility. As of December 31, 2011, we had the following hedged positions:

% of PDP Hedged

 

Year

   Crude Oil   Natural Gas   NGLs

2012

   72.6%   73.5%   83.3%

2013

   77.1%   67.9%   83.8%

2014

   67.5%   63.7%   51.5%

 

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In order to achieve more predictable cash flows and to reduce our exposure to downward commodity price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. As of December 31, 2011, we had hedging contracts in place for 1,784,607 Boe from January 1, 2012, through the end of 2012, 1,315,949 Boe during 2013 and 943,337 Boe during 2014. Based on the expected production set forth in our January 1, 2012 reserve report, we have hedged approximately 71% of our forecasted 2012, 2013 and 2014 PDP production as of December 31, 2011. In 2011, we realized commodity hedging gains of approximately $16.0 million, but we expect this to be significantly less in 2012. The use of certain types of derivative instruments may prevent us from realizing the benefit of upward price movements for the portion of the production that is hedged. As of the date of this report, we have met the above stated hedging obligations.

Components of Our Cost Structure

Production Costs. Production costs represent the day-to-day costs we incur to bring hydrocarbons out of the ground and to the market, combined with the daily costs we incur to maintain our producing properties. These daily costs include lease operating expenses and taxes other than income.

 

   

Lease operating expenses are generally composed of several components, including the cost of: labor and supervision to operate our wells and related equipment; repairs and maintenance; fluid treatment and disposal; related materials, supplies, and fuel; and insurance applicable to our wells and related facilities and equipment. Lease operating expenses also include the cost for workover expense and gathering and transportation. Lease operating expenses are driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties.

 

   

Environmental remediation expenses are costs related to environmental remediation activity associated with our ongoing operations.

 

   

In the U.S., there are a variety of state and federal taxes levied on the production of oil and natural gas. These are commonly grouped together and referred to as taxes other than income. The majority of our production tax expense is based on a percent of gross value realized at the wellhead at the time the production is sold or removed from the lease. As a result, our production tax expense increases when oil and natural gas prices rise.

 

   

Historically, taxing authorities have from time to time encouraged the oil and natural gas industry to explore for new oil and natural gas reserves, or to develop high cost reserves, through reduced tax rates or tax credits. These incentives have been narrow in scope and short-lived. A number of our wells have qualified for reduced production taxes because they are high cost wells.

 

   

Taxes other than income include production taxes and ad valorem taxes, which are imposed by local taxing authorities such as school districts, cities, and counties or boroughs. The amount of tax we pay is based on a percent of value of the property assessed or determined by the taxing authority on an annual basis. When oil and natural gas prices rise, the value of our underlying property interests increase, which results in higher ad valorem taxes.

Depreciation, Depletion and Amortization. As a full cost company, we capitalize all direct costs associated with our exploitation and development efforts, including a portion of our interest and certain general and administrative costs that are specific to exploitation and development efforts, and we apportion these costs to each unit of production sold through depletion expense. Generally, if reserve quantities are revised up or down, our depletion rate per unit of production will change inversely. When the depreciable capital cost base increases or decreases, the depletion rate will move in the same direction. Our full-cost depletion expense is driven by many factors, including certain costs spent in the exploration for and development of oil and natural gas reserves, production levels, and estimates of proved reserve quantities and future developmental costs.

Asset Retirement Accretion Expense. Asset retirement accretion expense represents the systematic, monthly accretion of future abandonment costs of tangible assets such as wells, service assets, flowlines and other facilities.

General and Administrative Expense. General and administrative expense includes payroll and benefits for our corporate staff, costs of maintaining our headquarters, managing our production and development operations and legal compliance. We capitalize general and administrative costs directly related to exploitation and development efforts.

Interest. We have relied on a series of debt financings to fund our short-term liquidity and a portion of our long-term financing needs. On December 31, 2011, we had approximately $138.0 million of LIBOR-based floating rate indebtedness outstanding under our 2011 Credit Facility. In addition, our Series A preferred stock carries a non-cash cumulative coupon of 12% per annum.

 

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As part of the 2011 Refinancing, we issued $250 million of the Notes and entered into the 2011 Credit Facility which provides for a current borrowing base of $180 million, as of December 31, 2011. Interest on the 2011 Credit Facility is calculated based on floating rates of LIBOR and Base Rate with a sliding margin that reflects usage under the facility. The higher the usage under the 2011 Credit Facility, the higher the interest margin over the floating rate index. We expect to continue to utilize indebtedness to grow and, as a result, expect to continue to pay interest throughout the term of the Notes.

Income Taxes. We recorded no income tax benefit or expense for the year ended December 31, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2011 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred tax assets as of December 31, 2011.

As of December 31, 2011, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2011. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2012.

Oil and Natural Gas Reserves

Our estimated total net proved reserves of oil and natural gas as of December 31, 2011 and 2010 were as follows:

 

     As of December 31,  
     2011     % Chg     2010  

Estimated Net Proved Reserves:

      

Oil (MMBbls)

     9.2        (7 )%      9.9   

Natural gas (Bcf)

     136.8        2     134.7   

NGLs (MMBbls)

     5.3        23     4.3   
  

 

 

     

 

 

 

Total oil equivalent (MMBoe)

     37.3        2     36.7   

Proved developed reserves as a percentage of net proved reserves

     61     (9 )%      67

Our estimated total net proved reserves increased 2% in the period ended December 31, 2011 as compared to the same period in 2010. This increase in our estimated net proved reserves was primarily the result of additional reserves obtained through an acquisition of interests in our Lions and La Reforma fields and field studies performed in the Midcontinent region.

Results of Operations

The following discussion is 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 related notes thereto contained elsewhere herein. Comparative results of operations for the periods indicated are discussed below.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Sales Volumes

 

     Year Ended December 31,  
     2011      % Change     2010  

Oil (MBbls)

     795         (9 )%      872   

Natural gas (MMcf)

     11,341         (17 )%      13,657   

NGLs (MBbls)

     235         69     139   
  

 

 

      

 

 

 

Total (MBoe)

     2,920         (11 )%      3,287   

Average daily production volumes (MBoe/d)(a)

     8.0         (11 )%      9.0   

 

(a) Average daily production volumes calculated based on 365-day year

For the years ended December 31, 2011 and 2010, our net equivalent production volumes decreased by 11% to 2,920 MBoe (8.0 MBoe/d) from 3,287 MBoe (9.0 MBoe/d) in 2010. Our production volumes in 2011 as compared to 2010 decreased primarily due to natural decline in production and the shutting in of producing properties in Louisiana due to flooding from the Mississippi River. Natural gas represented approximately 65% and 69% of our total production in the years ended December 31, 2011 and 2010, respectively.

 

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Revenues. The following tables shows (1) our revenues from the sale of oil; natural gas and NGLs and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the year ended December 31, 2011 and 2010. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.

 

     Year Ended December 31,  
     2011     %Change     2010  
     (In thousands)  

Oil revenues:

      

Oil revenues

   $ 81,924        20   $ 68,491   

Oil derivative settlements

     (6,436     —          53   
  

 

 

     

 

 

 

Oil revenues including oil derivative settlements

     75,488        10     68,544   

Natural gas revenues:

      

Natural gas revenues

     44,596        (26 )%      59,999   

Natural gas derivative settlements

     22,601        (42 )%      39,302   
  

 

 

     

 

 

 

Natural gas revenues including derivative settlements

     67,198        (32 )%      99,301   

NGLs revenue:

      

NGLs revenues

     11,689        104     5,717   

NGLs derivative settlements

     (191     100     —     
  

 

 

     

 

 

 

NGLs revenues including derivative settlements

     11,498        101     5,717   

Oil, natural gas and NGLs revenues:

      

Oil, natural gas and NGLs revenues

     138,210        3     134,207   

Oil, natural gas and NGLs derivative settlements

     15,974        (59 )%      39,355   
  

 

 

     

 

 

 

Oil, natural gas and NGLs revenues including derivative settlement gains (losses)

     154,183        (11 )%      173,562   

Oil, natural gas and NGLs derivative unrealized gains (losses)

     (396     (98 )%      (16,412
  

 

 

     

 

 

 

Oil, natural gas and NGLs revenues including derivative settlements and unrealized gains (losses)

     153,787        (2 )%      157,150   
  

 

 

     

 

 

 

Total revenues

   $ 153,787        (2 )%    $ 157,150   
  

 

 

     

 

 

 

 

     Change from Year
Ended  December 31, 2010
to Year

Ended December 31, 2011
 
     (In thousands)  

Change in revenues from the sale of oil :

  

Price variance impact

   $ 19,461   

Sales volume variance impact

     (6,027
  

 

 

 

Total change

     13,434   

Change in revenues from the sale of natural gas:

  

Price variance impact

   $ (5,226

Sales volume variance impact

     (10,177
  

 

 

 

Total change

     (15,403

Change in revenues from the sale of NGLs:

  

Price variance impact

   $ 2,009   

Sales volume variance impact

     3,964   
  

 

 

 

Total change

     5,973   

Change in revenues from the sale of oil, natural gas and NGLs:

  

Price variance impact

   $ 16,244   

Volume variance impact

     (12,241

Change in cash settlement of derivative hedging contracts

     (22,381

Changes in unrealized losses due to derivative hedging contracts

     16,016   
  

 

 

 

Total change

   $ (3,362
  

 

 

 

 

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Our oil, natural gas and NGLs revenues, including derivatives settlements and unrealized gains (losses), for the year ended December 31, 2011 decreased by approximately $3.4 million, or 2%, when compared to the same period in 2010. The pre-hedged revenue increased by approximately $4.0 million. This increase related to higher prices of oil and NGLs of approximately $21.4 million, which was partially offset by lower natural gas prices of approximately $5.2 million and lower production, which decreased revenue by approximately $12.2 million. The decrease in hedged gains was due primarily to lower gains on realized commodity derivatives of approximately $22.3 million and lower unrealized commodity derivatives losses of approximately $15.0 million.

Production costs. Production volumes in the year ended December 31, 2011 decreased by approximately 11% as compared to the same period in 2010 from 3.3 MMBoe to 2.9 MMBoe. Per unit production cost in 2011 increased by $2.48/Boe, or 18%, and total production costs in 2011 increased by approximately $2.0 million, or 4%, as compared to 2010. The increase was attributable to the natural decline in production. Our per unit and total production costs for the years ended December 31, 2011 and 2010 are as set forth below.

 

     Unit-of-Production
(Per Boe Based on Sales Volumes)
Year Ended December 31,
 
     2011      % Change     2010  

Production costs:

       

Gathering and transportation

   $ 0.50         28   $ 0.39   

Operating and maintenance

     10.93         16     9.39   

Workover expenses

     1.11         7     1.04   
  

 

 

      

 

 

 

Lease operating expenses

     12.54         16     10.82   

Remediation expenses

     0.68         —          —     

Taxes other than income

     3.40         2     3.32   
  

 

 

      

 

 

 

Production costs

   $ 16.62         18   $ 14.14   
  

 

 

      

 

 

 

 

     Production Costs
Year Ended December 31,
 
     2011      % Change     2010  
     (In thousands)  

Production costs:

     

Gathering and transportation

   $ 1,472         15   $ 1,282   

Operating and maintenance

     31,922         3     30,865   

Workover expenses

     3,230         (6 )%      3,418   
  

 

 

      

 

 

 

Lease operating expenses

     36,624         3     35,565   

Remediation expenses

     1,988         —          —     

Taxes other than income

     9,939         (9 )%      10,904   
  

 

 

      

 

 

 

Production costs

   $ 48,551         4   $ 46,469   
  

 

 

      

 

 

 

Gathering and transportation costs in 2011 were approximately $1.5 million, compared to approximately $1.3 million in 2010, an increase of approximately $0.2 million, or 15%. This increase was primarily due to the increase in our NGLs production.

Operating and maintenance expenses for the year ended December 31, 2011 were approximately $32.0 million, compared to approximately $30.9 million in the same period of 2010, an increase of approximately $1.0 million, or 3%. This increase in operating and maintenance expenses was related to properties acquired in 2010 and 2011 and higher repair costs that was partially offset by lower direct labor and natural gas lift expenses.

Workover expenses for the year ended December 31, 2011 were approximately $3.2 million, compared to approximately $3.4 million for the same period in 2010, a decrease of approximately $0.2 million, or 6%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2011 as compared to 2010.

 

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Environmental remediation expenses for the year ended December 31, 2011 were approximately $2.0 million and were incurred in 2011 as the result of our participation in a settlement involving environmental remediation in a field in which we have an ownership interest. There were no remediation costs incurred in the 2010 period.

Taxes other than income for the year ended December 31, 2011 were approximately $9.9 million, compared to approximately $10.9 million in the same period of 2010, a decrease of $1.0 million or 9%. This decrease in taxes was due to lower actual ad valorem taxes incurred in 2011.

General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized costs include the cost of technical employees who work directly on our exploration activities, a portion of our associated technical organization expenses such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative expenses (gross, capitalized and net) and our per unit general and administrative expenses for the years ended December 31, 2011 and 2010 were as follows:

 

     Year Ended December 31,  
     2011      % Change     2010  
    

(In thousands, except per unit measurements

which are based on sales volumes)

 

General and administrative expenses — gross

   $ 21,005         (1 )%    $ 21,309   

Capitalized general and administrative expenses

     4,522         18     3,840   
  

 

 

      

 

 

 

General and administrative expenses — net

   $ 16,483         (6 )%    $ 17,469   
  

 

 

      

 

 

 

General and administrative expenses — gross $ per Boe

   $ 7.19         11   $ 6.48   

Our gross general and administrative expenses for the year ended December 31, 2011 were approximately $21.0 million compared to approximately $21.3 million in the same period of 2010, a decrease of approximately $0.3 million, or 1%, primarily as a result of there being no stock based compensation expense in 2011. After capitalization, our general and administrative costs decreased by approximately $1.0 million, or 6%, to approximately $16.5 million. Per unit general and administrative expense increased due to a decrease in production volumes, offset by a decrease in compensation expense and an increase in capitalized costs.

Depletion of oil and natural gas properties.

 

     Year Ended December 31,  
     2011      % Change     2010  
    

(In thousands, except per unit measurements

which are based on sales volumes)

 

Depletion of oil and natural gas properties

   $ 50,476         (3 )%    $ 51,779   

Depletion of oil and natural gas properties (per Boe)

   $ 17.28         10   $ 15.75   

Our depletion expense for the year ended December 31, 2011 was approximately $50.5 million compared to approximately $51.8 million in the same period of 2010, a decrease of approximately $1.3 million, or 3%. This decrease in depletion expense was largely the result of decreased production volumes, which resulted in lower depletion expense by approximately $5.8 million. This was partially offset by an increase in our depletion rate resulting in an increase in depletion expense of approximately $4.5 million.

Impairment of oil and natural gas properties. For the year ended December 31, 2011, based on the average oil and natural gas prices in effect on the first day of each month during 2011 ($4.12 per MMBtu for Henry Hub gas and $96.19 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded a $18.2 million impairment to our oil and natural gas properties. We did not record any impairment for the year ended December 31, 2010.

Net interest expense. Our interest expense for the year ended December 31, 2011 and December 31, 2010 was approximately $41.1 million and $48.0 million, respectively. Total interest expense for the year ended December 31, 2011 benefited from our Refinancing that converted the Series A preferred from a debt instrument to mezzanine equity, offset by the increase in interest expense due to the assumption of a higher coupon on our $250 million Notes issued in May 2011.

 

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Income taxes. For the years ended December 31, 2011 and 2010, current tax expense (benefit) was zero and deferred tax expense was approximately zero and $57.4 million, respectively. In 2010, we provided a full valuation allowance with respect to our deferred tax assets given our history of operating losses, and the expectation that future profitability will be impacted significantly by volatility in commodity prices for oil and natural gas. Our future profitability is heavily correlated to the volume of our proved reserves, and the price at which these reserves will be sold. The expected volatility in commodity prices creates significant uncertainty with respect to whether future profitability will be sufficient to realize deferred tax assets.

The federal statutory rate of 35% is different from our effective tax rate primarily as a result of the full valuation allowance against deferred income tax assets.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Oil and Natural Gas Reserves

Our estimated total net proved reserves of oil and natural gas as of December 31, 2010 and 2009 were as follows:

 

     As of December 31,  
     2010     % Chg     2009  

Estimated Net Proved Reserves:

      

Oil (MMBbls)

     9.9        5     9.4   

Natural gas (Bcf)

     134.7        11     121.9   

NGLs (MMBbls)

     4.3        258     1.2   
  

 

 

     

 

 

 

Total oil equivalent (MMBoe)

     36.7        19     30.9   

Proved developed reserves as a percentage of net proved reserves

     67     (12 )%      76

Our estimated total net proved reserves increased 19% in the period ended December 31, 2010 as compared to the same period in 2009. This increase in our estimated net proved reserves was primarily the result of additional reserves obtained through an acquisition completed in December 2010.

Sales volumes

 

     Year Ended December 31,  
     2010      % Change     2009  

Oil (MBbls)

     872         (7 )%      938   

Natural gas (MMcf)

     13,657         (26 )%      18,512   

NGLs (MBbls)

     139         (21 )%      175   
  

 

 

      

 

 

 

Total (MBoe)

     3,287         (22 )%      4,198   

Average daily production volumes (MBoe/d)(a)

     9.0         (22 )%      11.5   

 

(a) Average daily production volumes calculated based on 365-day year

Our net equivalent production volumes for 2010 decreased by 22% to 3,287 MBoe (9.0 MBoe/d) from 4,198 MBoe (11.5 MBoe/d) in 2009. Our production volumes for 2010 decreased primarily due to reduced production-enhancing capital expenditure activity in 2009 and in the first half of 2010 and the natural production decline of our properties. Natural gas represented 69% of our total production in 2010.

Revenues

The following tables shows (1) our revenues from the sale of oil; natural gas and NGLs and (2) the impact of changes in price and sales volumes on our oil and natural gas revenues during the years ended December 31, 2010 and 2009. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.

 

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     Year Ended December 31,  
     2010     % Change     2009  
     (In thousands, except per unit
measurements)
 

Oil revenues:

      

Oil revenues

   $ 68,491        28   $ 53,656   

Oil derivative settlement gains (losses)

     53        (98 )%      3,466   
  

 

 

     

 

 

 

Oil revenues including oil derivative settlements

   $ 68,544        20   $ 57,122   

Natural gas revenues:

      

Natural gas revenues

   $ 59,999        (15 )%    $ 70,233   

Natural gas derivative settlement gains (losses)

     39,302        (3 )%      40,661   
  

 

 

     

 

 

 

Natural gas revenues including derivative settlements

   $ 99,301        (10 )%    $ 110,894   

NGLs revenues:

      

NGLs revenues

   $ 5,717        17   $ 4,893   

NGLs derivative settlement gains (losses)

     —          0     —     
  

 

 

     

 

 

 

NGLs revenues including derivative settlements

   $ 5,717        17   $ 4,893   

Oil, natural gas and NGLs revenues:

      

Oil, natural gas and NGLs revenues

   $ 134,207        4   $ 128,782   

Oil, natural gas and NGLs derivative settlement gains (losses)

     39,355        (11 )%      44,127   
  

 

 

     

 

 

 

Oil, natural gas and NGLs revenues including derivative settlement gains (losses)

   $ 173,562        0   $ 172,909   

Oil, natural gas and NGLs derivative unrealized gains (losses)

     (16,412     (11 )%      (18,521
  

 

 

     

 

 

 

Oil, natural gas and NGLs revenues including derivative settlements and unrealized gains (losses)

   $ 157,150        2   $ 154,388   
  

 

 

   

 

 

   

 

 

 

Total revenues

   $ 157,150        2   $ 154,388   
  

 

 

     

 

 

 

 

     Change from Year
Ended  December 31, 2009
to Year

Ended December 31, 2010
 

Change in revenues from the sale of oil

  

Price variance impact

   $ 18,625   

Sales volume variance impact

     (3,790
  

 

 

 

Total change

   $ 14,835   
  

 

 

 

Change in revenues from the sale of natural gas

  

Price variance impact

   $ 8,185   

Sales volume variance impact

     (18,419
  

 

 

 

Total change

   $ (10,234
  

 

 

 

Change in revenues from the sale of NGLs

  

Price variance impact

   $ 1,827   

Sales volume variance impact

     (1,003
  

 

 

 

Total change

   $ 824   
  

 

 

 

Change in revenues from the sale of oil, natural gas and NGLs

  

Price variance impact

   $ 28,636   

Volume variance impact

     (23,212

Cash settlement of derivative hedging contracts

     (4,772

Unrealized gains (losses) due to derivative hedging contracts

     2,109   
  

 

 

 

Total change

   $ 2,761   
  

 

 

 

Our oil, natural gas and NGLs revenues, including derivatives settlements and unrealized gains for 2010 increased approximately $2.7 million, or 2%, as compared to 2009. This increase in revenues was primarily due to a 33% increase in pre-hedge per Boe sales prices, which resulted in a $28.6 million increase in revenues, and a $2.1 million increase in unrealized gains on derivative hedge contracts from December 31, 2009 to December 31, 2010. This increase in revenues was offset by a 22% decrease in oil and natural gas volumes due to a natural decline in production, resulting in a $23.2 million decrease in revenues, and a $4.8 million decrease in derivative hedging gains on contracts settled.

Production costs. Although production volumes in 2010 decreased approximately 22% as compared to 2009 from 4.2 MMBoe to 3.3 MMBoe in 2010, per unit production cost in 2010 increased by $3.78/Boe, or 36%, and total production costs in 2010 increased by approximately $3.0 million, or 7%, as compared to 2009. Our per unit and total production costs for the years ended December 31, 2010 and 2009 are as set forth below.

 

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     Unit-of-Production
(Per Boe  Based on Sales Volumes)
Year Ended December 31,
 
     2010      % Change     2009  

Production costs:

       

Gathering and transportation

   $ 0.39         (15 )%    $ 0.46   

Operating and maintenance

     9.39         38     6.80   

Workover expenses

     1.04         9     0.95   
  

 

 

      

 

 

 

Lease operating expenses

   $ 10.82         32   $ 8.21   

Taxes other than income

     3.32         54     2.15   
  

 

 

      

 

 

 

Production costs

   $ 14.14         36   $ 10.36   
  

 

 

      

 

 

 

 

     Year Ended December 31,  
     2010      % Change     2009  
     (In thousands)  

Production costs:

       

Gathering and transportation

   $ 1,282         (33 )%    $ 1,925   

Operating and maintenance

   $ 30,865         8   $ 28,546   

Workover expenses

     3,418         (14 )%      3,996   
  

 

 

      

 

 

 

Lease operating expenses

   $ 35,565         3   $ 34,467   

Taxes other than income

     10,904         21     9,017   
  

 

 

      

 

 

 

Production costs

   $ 46,469         7   $ 43,484   
  

 

 

      

 

 

 

Our gathering and transportation costs in 2010 were approximately $1.3 million, compared to approximately $1.9 million in 2009, a decrease of approximately $0.6 million, or 33%. This decrease was primarily due to a reduction in our natural gas production.

Operating and maintenance expenses in 2010 were approximately $30.9 million, compared to approximately $28.5 million in 2009, an increase of $2.4 million, or 8%. This increase in operating and maintenance expenses was due primarily to an increase in well service costs and treating and processing costs.

Workover expenses in 2010 were approximately $3.4 million, compared to approximately $4.0 million in 2009, a decrease of approximately $0.6 million, or 14%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2010 as compared to 2009.

Taxes other than income in 2010 were approximately $10.9 million, compared to approximately $9.0 million in 2009, an increase of approximately $1.9 million or 21%. This increase in taxes other than income was due to utilized tight sands credits in 2009 that were unavailable to us in 2010 because the inventory of properties which became eligible for the credits declined.

General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized costs include the cost of technical employees who work directly on our prospect generation and exploration activities, a portion of our associated technical organization expenses such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative expenses (gross, capitalized and net) and our per unit general and administrative expenses for the years ended December 31, 2010 and 2009 are as follows:

 

     Year Ended December 31,  
     2010      % Change     2009  
     (In thousands, except per unit measurements which are based on sales
volumes)
 

General and administrative expenses — gross

   $ 21,309         (13 )%    $ 24,485   

Capitalized general and administrative expenses

     3,840         (32 )%      5,636   
  

 

 

      

 

 

 

General and administrative expenses — net

   $ 17,469         (7 )%    $ 18,849   

General and administrative expenses — gross $ per Boe

   $ 6.48         11   $ 5.83   

 

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Our gross general and administrative expenses in 2010 were approximately $21.3 million compared to approximately $24.5 million in 2009, a decrease of approximately $3.2 million, or 13%. After capitalization, our general and administrative expenses decreased by approximately $1.4 million, or 7%, to approximately $17.5 million. This decrease in our gross general and administrative expenses and our general and administrative expenses after capitalization was largely attributable to certain fees and expenses we paid in 2009 in connection with a recapitalization.

Depletion of oil and natural gas properties.

 

     Year Ended December 31,  
     2010      % Change     2009  
     (In thousands, except per unit measurements which are based on sales
volumes)
 

Depletion of oil and natural gas properties

   $ 51,779         (23 )%    $ 66,888   

Depletion of oil and natural gas properties (per Boe)

   $ 15.75         (1 )%    $ 15.93   

Our depletion expense for 2010 was approximately $51.8 million compared to approximately $66.9 million in 2009, a decrease of approximately $15.1 million, or 23%. The decrease in depletion expense was primarily attributable to a decrease in production volumes in 2010 resulting in an approximately $14.5 million decrease in depletion expense and a decrease in our depletion rate of approximately $0.6 million. The lower depletion rate was due to our 2009 ceiling limitation impairments.

Impairment of oil and natural gas properties. For the year ended December 31, 2009, based on the average oil and natural gas prices in effect on the first day of each month during 2009 ($3.87 per MMBtu for Henry Hub gas and $61.18 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded a $39.6 million impairment to our oil and natural gas properties. We did not record any impairment for the year ended December 31, 2010.

Net interest expense. In 2010, our net interest expense increased by approximately $7.4 million, or 18%, from approximately $40.6 million in 2009 to $48.0 million in 2010. This increase in interest expense was the result of higher interest rates payable on loans under our existing second lien indebtedness as compared to the rates payable under our prior second lien credit agreement and the additional interest expense attributable to the dividends on our Series A preferred stock.

Income taxes. For the years ended December 31, 2010 and 2009, current tax expense (benefit) was zero and deferred tax expense (benefit) was approximately $57.4 million and ($57.4) million, respectively. In 2010, we provided a full valuation allowance with respect to our deferred tax assets given our history of operating losses, and the expectation that future profitability will be impacted significantly by volatility in commodity prices for oil and natural gas. Our future profitability is heavily correlated to the volume of our proved reserves, and the price at which these reserves will be sold. The expected volatility in commodity prices creates significant uncertainty with respect to whether future profitability will be sufficient to realize deferred tax assets.

Effective August 1, 2009, we converted from a single member limited liability company to a corporation taxed under sub-chapter C of the Internal Revenue Code. As a result of the conversion, deferred tax assets and liabilities were recorded to reflect the future tax impacts associated with differences in tax basis as compared to net book value as of the date of conversion. Approximately $77.6 million of net deferred tax assets existed as of the conversion date, before consideration of any valuation allowance.

The federal statutory rate of 35% is different from our effective tax rate primarily because the dividends on our Series A preferred stock (recorded as interest expense) are not deductible for income tax purposes and as a result of the full valuation allowance against deferred income tax assets.

Liquidity and Capital Resources

Historically, we have financed our acquisition, exploitation and development activities, and repayment of our contractual obligations, through a variety of means, including cash flow from operations, borrowings under our credit agreements, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties. Our primary needs for cash are to fund our capital expenditure program and our working capital obligations and for the repayment of contractual obligations. In the future, we will also require cash to fund our capital expenditures for the exploitation and development of properties necessary to offset the inherent declines in production and proved reserves that are typical in an extractive industry like ours. We will also spend capital to hold acreage that would otherwise expire if not drilled. Future success in growing reserves and production will be highly dependent on our access to cost effective capital resources and our success in economically finding and producing additional oil and natural gas reserves.

 

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Sources and Uses of Cash

The table below summarizes our sources and uses of cash during the periods indicated.

 

     Year Ended December 31,  
     2011     %
Change
    2010     %
Change
    2009  
     (In thousands)  

Net loss

   $ (23,574     (67 )%    $ (70,588     717   $ (8,636

Non-cash items

     84,635        (46 )%      157,652        102     78,066   

Changes in working capital and other items

     (2,673     (132 )%      8,253        (65 )%      23,801   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows provided by operating activities

   $ 58,388        (39 )%    $ 95,317        2   $ 93,231   

Cash flows used in investing activities

   $ (101,395     0   $ (101,071     247   $ (29,113

Cash flows provided by (used in) financing activities

     34,629        167     12,957        124     (53,587
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

   $ (8,378     (216 )%    $ 7,203        (32 )%      10,531   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Working capital

At December 31, 2011, we had a working capital deficit of approximately $3.3 million. Our working capital deficit at December 31, 2010 and 2009 was approximately $238.5 million and approximately $11.0 million, respectively. The 2010 deficiency was primarily the result of reclassifying from long-term debt to current debt the approximately $244.6 million outstanding under our prior first lien credit agreement and our prior second lien term loan agreement. The 2009 deficiency was the result of accrued interest of approximately $20.1 million and derivative liabilities of approximately $10.3 million in 2009.

Analysis of cash flows provided by operating activities

Cash flows provided by operating activities in 2011 were approximately $58.4 million, as compared to approximately $95.3 million in 2010, a decrease of approximately $36.9 million, or 39%. The decrease in 2011 was the result of higher operating cost, oil and natural gas receivables and lower accounts payable.

Cash flows provided by operating activities in 2009 were approximately $93.2 million, as compared to approximately $95.3 in 2010, an increase of 2%. The increase in cash flows provided by operating activities from 2009 to 2010 was primarily due to higher oil and natural gas revenues in 2010.

Analysis of cash flows used in investing activities

Net cash used in investing activities in 2011 was approximately $101.4 million, compared to approximately $101.1 million in 2010, a $0.3 million increase.

 

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Our net cash used in investing activities in 2009 was approximately $29.1 million as compared to approximately $101.1 million in 2010, an increase of approximately $72.0 million, or 247%. This increase was primarily due to our acquisition in 2010 of properties from TexCal Energy South Texas, L.P. for $22.4 million and from RWG Energy, Inc. for $44.5 million.

Analysis of cash flows provided by and used in financing activities

Net cash provided by financing activities in 2011 was approximately $34.6 million as compared to approximately $13.0 million provided by financing activities in 2010, an increase of approximately $21.6 million, or 167%. This increase was primarily the result of borrowings in connection with our 2011 Refinancing.

Our net cash used in financing activities in 2009 was approximately $53.6 million as compared to cash provided by financing activities of approximately $13.0 million in 2010, a change of 124%. This increase was the result of $35.0 million of borrowings under our prior second lien term loan agreement to fund our 2010 acquisitions and $25.0 million of borrowings under our prior second lien term loan agreement in connection with our 2010 recapitalization. In 2009, we repaid approximately $53.4 million of outstanding borrowings under our prior first lien credit agreement.

Capital expenditures

The timing of most of our capital expenditures is discretionary because we operate the majority of our wells and we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital expenditure program also includes general and administrative expenses allowed to be capitalized under full cost accounting, costs related to plugging and abandoning unproductive or uneconomic wells and the cost of acquiring and maintaining our lease acreage position and our seismic resources, drilling and completing new oil and natural gas wells, installing new production infrastructure and maintaining, repairing and enhancing existing oil and natural gas wells.

The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We re-evaluate our annual budget periodically throughout the year. The primary factors that affect our budget include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our planned expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our periodic analysis results in a reprioritization of our drilling schedule to ensure that we are optimizing our capital expenditure plan.

For the year ended December 31, 2011, we spent approximately $92.6 million in capital expenditures to support our business plan. Of this amount we spent approximately $39.5 million to drill or complete eleven gross (8.5 net) wells, of which nine were successful, adding approximately 77 net Boe/d to our 2011 average daily production. We also recompleted or worked over approximately 74 gross (58.6 net) wells during 2011 at a capital cost of approximately $10.2 million, approximately $2.1 million was spent to plug and abandon wells, and spent approximately $11.9 million to acquire seismic data and additional leases primarily in Oklahoma to support the future development of our Atoka Shale properties. The remaining capital expenditures of approximately $28.9 million related primarily to acquisitions.

Capital resources

Cash. As of December 31, 2011 and 2010, we had $9.4 million and $17.7 million of cash and cash equivalents, respectively.

First Lien Credit. As part of the 2011 Refinancing, we entered into the $300 million 2011 Credit Facility that matures in November 2014. The borrowing base for the 2011 Credit Facility is currently $180.0 million with semi-annual redeterminations. The next redetermination date is May 2012. Amounts outstanding under the 2011 Credit Facility bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the 2011 Credit Facility are secured by all of our oil and natural gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 Credit Facility will mature, in November 2014.

 

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The 2011 Credit Facility contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused availability of the borrowing base under the 2011 Credit Facility to current liabilities) of not less than 1.0 to 1.0 (which was 1.85 as of December 31, 2011), minimum interest coverage ratio, as defined, of not less than 2.25 to 1.0 (which was 3.47 as of December 31, 2011), maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.5 to 1.0 (which was 3.98 as of December 31, 2011) and maximum secured leverage ratio, as defined, of secured debt balances as compared to EBITDA of not greater than 2.0 to 1.0 (which was 1.45 as of December 31, 2011). The interest coverage ratio, as defined, increases from 2.25 to 1.0 during 2011 and 2.5 to 1.0 thereafter. The leverage ratio, as defined, is 4.5 to 1.0 for 2011. The leverage ratio for the first quarter of 2012 was waived and then will reduce to 4.25 to 1.0 for the remainder of 2012 and 4.0 to 1.0 thereafter. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. At December 31, 2011, we were in compliance with the financial covenants governing the 2011 Credit Facility. Under the 2011 Credit Facility, the maximum amount of debt outstanding in 2011 was $149,500,000 on November 15, 2011 and the average daily balance of debt outstanding during 2011 was $114,502,128.

Series A Preferred Stock. As part of the 2010 recapitalization, we entered into agreements to exchange a portion of prior second lien indebtedness for $205.5 million of Series A preferred stock, consisting of 2,700,000 shares issued at $76.12 per share redeemable in 2016 at the option of the holder subsequent to the maturity of certain qualified debt, including the 2011 Credit Facility and the Notes. The preferred shareholders receive a 12% dividend each year paid in-kind. There were no dividends declared or paid during 2010 or 2011. The Series A stock was classified as a liability in the financial statements prior to May 11, 2011, as they were mandatorily redeemable for cash.

Upon completion of the 2011 Refinancing, including the amendment of the terms of our Series A preferred stock as described in Note 10 to the consolidated financial statements included herein, we reclassified the Series A preferred stock as mezzanine equity for financial reporting purposes because there is no longer a mandatory redemption provision and the Series A preferred stock is redeemable at the option of the holder

Capitalization of Debt Costs. We capitalize certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method.

Senior Secured Second Lien Notes. As part of the 2011 Refinancing, we issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7.0 million. The Notes carry a face interest rate of 10.500%; interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 Credit Facility, and effectively rank junior to any existing and future first lien secured indebtedness, which includes the 2011 Credit Facility. The balance is presented net of unamortized discount of $6.1 million at December 31, 2011.

The Notes contain an optional redemption provision allowing us to retire up to 35% of the principal outstanding with the proceeds of an equity offering, at 110.5% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.5%, 102.625% and 100.0% beginning on each of May 15, 2014, May 15, 2015 and November 15, 2015, respectively. If a change of control occurs, each noteholder may require us to repurchase all or a portion of its notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase. The indenture governing the Notes contains covenants that, among other things, limit our ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; transfer or sell assets; make investments; create certain liens; consolidate, merge or transfer all or substantially all of its assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

Outlook

We expect to fund our acquisition, exploitation and development activities from a variety of sources, including through cash flow from operations, borrowings under our 2011 Credit Facility, issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties. However, we expect that future significant acquisitions will require funding, at least in part, from the proceeds of the issuance of equity securities.

As of December 31, 2011, we had approximately $40.4 million of available borrowing capacity under our 2011 Credit Facility.

For the year ended December 31, 2011, we realized approximately $17.0 million in gains under our hedging agreements. Based on the NYMEX strip pricing for oil and natural gas as of December 31, 2011, we expect to realize approximately $7.5 million of hedging revenues during 2012.

 

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For 2012, our capital program is approximately $54.2 million, which we believe is sufficient to maintain current operations. Our 2012 capital budget contemplates spending approximately $14.2 million in connection with the drilling of eight additional wells and approximately $11.3 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $25.0 million for acquisitions.

The table below sets forth our 2012 capital budget.

 

     2012
Budget
 
  

Drilling

   $ 14.2   

Acquisitions

     25.0   

Workovers and recompletions

     11.3   

Geological, geophysical, leasing and seismic

     —     

Plugging and abandonment

     1.5   

Facilities, vehicles and other

     2.2   
  

 

 

 

Total operations capital budget

   $ 54.2   
  

 

 

 

The final determination with respect to our actual capital expenditures during 2012 will depend on a number of factors, including:

 

   

changes in commodity prices;

 

   

changes in service and materials costs, including from the sharing of costs through the formation of joint ventures with other oil and natural gas companies;

 

   

production from our existing producing wells;

 

   

the results of our current exploitation and development drilling efforts;

 

   

economic and industry conditions at the time of drilling;

 

   

our liquidity and the availability of financing; and

 

   

properties for sale at an attractive price and rate of return.

Off Balance Sheet Arrangements

We currently do not have off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the indebtedness of any other party.

Contractual Obligations

In the schedule below, we set forth our contractual obligations as of December 31, 2011 and the effect those obligations are expected to have on our future cash flow and liquidity.

 

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Contractual Obligations

 
     As of December 31, 2011  
     Payments Due by Year  
     Total      2012      2013      2014-2015      2016 and
Thereafter
 
     (In thousands)  

Debt:

              

2011 Credit Facility

   $ 138,000       $ —         $ —         $ 138,000       $ —     

Notes(1)

     250,000         —           —           —           250,000   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 388,000       $ —         $ —         $ 138,000       $ 250,000   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Other Commitments:

              

Services(2)

   $ 700       $ —         $ 700       $ —         $ —     

Operating Leases(3)

     10,696         1,798         1,884         3,826         3,188   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 11,396       $ 1,798       $ 2,584       $ 3,826       $ 3,188   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Interest:

              

2011 Credit Facility

   $ 17,801       $ 5,985       $ 6,322       $ 5,494       $ —     

Notes

     114,479         26,250         26,250         52,500         9,479   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 132,280       $ 32,235       $ 32,572       $ 57,994       $ 9,479   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Commitments

   $ 531,676       $ 34,033       $ 35,156       $ 199,820       $ 262,667   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes $6.1 million of original issue discount that will become due upon maturity.
(2) Consists of fees payable to an investment bank for advisory services related to acquisitions.
(3) Consists primarily of leases for office space and office equipment.

Critical Accounting Policies

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our consolidated financial statements in accordance with GAAP, as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions.

Use of Estimates

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties; (ii) calculation of amortization of oil and natural gas properties and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (a) estimated quantities and prices of oil and natural gas sold, but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations; and (d) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 7. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

 

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Oil and Natural Gas Properties

Full Cost Accounting — We utilize the full cost method to account for our investment in oil and natural gas properties. Under the full cost method, which is governed by Rule 4-10 of Regulation S-X of the SEC, all costs of acquisition, exploration, exploitation, and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible exploration and development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. There were approximately $4.5 million, $3.8 million and $5.6 million of direct internal costs capitalized for the years ended December 31, 2011, 2010 and 2009, respectively.

Depreciation, Depletion, and Amortization — The cost of oil and natural gas properties, the estimated future expenditures to develop proved reserves and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and natural gas reserves as estimated by independent engineering consultants. Our depletion rates for the years ended December 31, 2011, 2010 and 2009 were $17.28, $15.75 and $15.93 per Mboe, respectively.

Impairment — Full cost ceiling impairment is calculated whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. The full cost ceiling limitation is calculated using 12-month simple average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. Price and operating costs, which are based on current cost conditions, are held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations. An impairment of approximately $18.2 million was recorded for the year ended December 31, 2011, no impairment was recorded for the year ended December 31, 2010 and an impairment of approximately $39.6 million was recorded for the year ended December 31, 2009.

Unproved Property Costs — Costs directly associated with the acquisition and evaluation of unproved properties, including leasehold, acreage, and capitalized interest, are excluded from the full cost pool until it is determined whether or not proved reserves can be assigned to the individual prospects or whether impairment has occurred.

We assess all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Unproved property costs fall into two broad categories:

 

   

Leasehold costs for projects not yet evaluated and

 

   

Interest

 

   

Costs related to financing such activities.

Revenue Recognition and Natural Gas Imbalances

Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer.

We use the sales method of accounting for revenue. Under this method, oil and natural gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Natural gas imbalances are created when the sales amount is not equal to our entitled share of production. Our entitled share is calculated as gross production from the property multiplied by our net revenue interest in the property. No provision is made for an imbalance unless the oil and natural gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. As of December 31, 2011 and 2010, we had recorded a liability of approximately $597,000 and $725,000, respectively.

 

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Income Taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets also arise when operating losses or tax credits are available to offset future taxable income. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the realizability of our deferred tax assets. If it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset is reduced by a valuation allowance.

As a result of the conversion to a corporation on August 1, 2009, which pursuant to Sec. 351 of the Internal Revenue Code, a tax-free reorganization, we stepped into the “shoes” of our parent company as to the tax value of the net assets. Therefore, in effect, the income tax years of 2008, through the conversion date, through the current year, remain open and subject to examination by Federal tax authorities and/or the tax authorities in Texas, Oklahoma, Mississippi, and Louisiana which are our principal operating jurisdictions. These audits can result in adjustments of taxes due or adjustments of the net operating loss carry forwards that are available to offset future taxable income.

A more-likely-than-not recognition threshold (assuming taxing authorities have full knowledge of the facts and based solely on the technical merits) and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return.

Our policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in our Consolidated Statements of Operations. No interest expense or penalties related to unrecognized tax benefits associated with uncertain tax positions have been recognized in the provision for income taxes in any year presented.

The total amount of unrecognized tax benefit if recognized that would affect the effective tax rate was zero.

Our parent files a consolidated tax return in Texas for the Texas Margin Tax, and is the legally responsible party for such taxes. Therefore, any income tax associated with the Texas Margin Tax is the responsibility of our parent, and has not been recognized in our consolidated financial statements. There are no income tax sharing agreements between our parent and us.

See Note 12 — “Income Taxes” for further information.

Derivative Financial Instruments

We utilize derivative financial instruments, specifically, commodity swaps and collars and interest rate collars. Commodity swaps and collars are used to manage market price exposures associated with sales of oil and natural gas. Interest rate collars are used to manage interest rate risk arising from interest payments associated with floating rate debt. Such instruments are entered into for non-trading purposes.

Derivative contracts have not been designated nor do they qualify for hedge accounting. The valuation of these instruments is determined using valuation techniques, including discounted cash flow analysis on the expected cash flows of each derivative. This analysis reflects the contractual terms of the derivatives, including the period to maturity, and uses observable market-based inputs, including price volatility and commodity and interest rate forward curves as appropriate.

We incorporate credit valuation adjustments to appropriately reflect both our nonperformance risk and the respective counterparty’s nonperformance risk in the fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, any impacts of netting and any applicable credit enhancements, such as collateral postings, thresholds, and guarantees, are considered.

Asset Retirement Obligation

We record a liability for the estimated fair value of our asset retirement obligations, primarily comprised of our plugging and abandonment liabilities, in the period in which it is incurred. The liability is accreted each period through charges to accretion expense. The asset retirement cost is included in the full cost pool. If the liability is settled for an amount other than the recorded amount, the difference is recognized in oil and natural gas properties.

 

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Recently Issued Accounting Pronouncements

In December 31, 2008, the SEC issued “Modernization of Oil and Gas Reporting” (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of the final release is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by the release are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The final release is effective for financial statements with fiscal years ending on or after December 31, 2009. We adopted the provisions of the rule effective December 31, 2009.

In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, “Improving Disclosures About Fair Value Measurements” (“ASU 2010-06”), which amends the Fair Value Measurements and Disclosures Topic of the ASC (“ASC Topic 820”). Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy. This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements. ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques. ASU 2010-06 became effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which became effective for interim and annual reporting periods beginning after December 15, 2010. See Note 7 to the consolidated financial statements included herein. We adopted the applicable provisions of the rule effective January 1, 2010 and January 1, 2011, respectively.

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This ASU expands existing disclosure requirements for fair value measurements and provides additional information on how to measure fair value. The Company is required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.

On December 16, 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities, in conjunction with the IASB’s issuance of amendments to Disclosures—Offsetting Financial Assets and Financial Liabilities (Amendments to IFRS 7). While the FASB and IASB retained the existing offsetting models under U.S. GAAP and IFRS, the new standards require disclosures to allow investors to better compare financial statements prepared under U.S. GAAP with financial statements prepared under IFRS. The new standards are effective for annual periods beginning Jan. 1, 2013, and interim periods within those annual periods. Retrospective application is required. We are currently evaluating the potential impact of this adoption on its consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

Interest Rate Risk

We are exposed to changes in interest rates that affect the interest paid on borrowings under the 2011 Credit Facility. The Company currently is not party to any interest rate hedging arrangements that would mitigate the risk of increasing interest rates. The interest paid on the Notes is fixed at 10.500% per annum and is not subject to changes in floating interest rates. Based on our current capital structure at December 31, 2011, a 1% increase in interest rates would increase interest expense by approximately $1.4 million per year, based on our approximately $138.0 million of floating rate indebtedness outstanding under our existing 2011 Credit Facility that would be affected by such a movement in interest rates.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative instruments. We believe that we place our excess cash investments with strong financial institutions. Our receivables generally relate to customers in the oil and natural gas industry, and as such, we are directly affected by the economy of the industry. During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues and during 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues. This concentration increases our credit risk. We seek to mitigate our credit risk by, among other things, monitoring customer creditworthiness.

 

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Counterparty Risk

We have exposure to financial institutions in the form of derivative transactions in connection with our hedges. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. In addition, we also have exposure to financial institutions which are lenders under our credit facilities. If any lender under our existing first lien credit agreement, or under our 2011 Credit Facility, is unable to fund its commitment, our liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitment under the 2011 Credit Facility.

Commodity Price Risk

Changes in commodity prices significantly affect our capital resources, liquidity and operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of capital we have available to reinvest in our exploitation and development activities. Commodity prices are impacted by many factors that are outside of our control. Over the past few years, commodity prices have been highly volatile. We expect that commodity prices will continue to fluctuate significantly in the future. As a result, we cannot accurately predict future oil and natural gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.

The prices we receive for our oil production are based on global market conditions. Significant factors that impacted oil prices in 2011 included the pace at which the domestic and global economies recovered from the current recession, the ongoing tensions and uprisings in the Middle East and North Africa, and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations were able to manage oil supply through export quotas.

Natural gas prices are primarily driven by North American market forces. However, global LNG shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe to North America. Factors that can affect the price of natural gas include changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Over the past several years, natural gas prices have been volatile. Our average pre-hedged sales price for natural gas in 2011 was $3.93 per Mcf, which was approximately 10% lower than the price of $4.39 per Mcf that we received during 2010. Natural gas prices in 2011 were dependent upon many factors including the balance between North American supply and demand.

We have utilized swaps and costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure that we can execute at least a portion of our capital spending plans with internally generated funds. The following table details derivative contracts that settled during 2011 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain/(loss) upon settlement.

 

     As of December 31,
2011
 

Oil collars

  

Volumes (Bbls)

     590,852   

Average floor price (per Bbl)

   $ 72.45   

Average ceiling price (per Bbl)

   $ 85.39   
  

 

 

 

Gain/(loss) upon settlement

   $ (6,934,691)   

Oil swaps

  

Volumes (Bbls)

     86,749   

Average swap price (per Bbl)

   $ 100.49   

Gain/(loss) upon settlement

   $ 498,251   
  

 

 

 

Total oil gain/(loss) upon settlement

   $ (6,436,440)   
  

 

 

 

 

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Natural gas collars and three way costless collars

  

Volumes (Mcf)

     2,560,164   

Average floor price (per Mcf)

   $ 4.89   

Average ceiling price (per Mcf)

   $ 6.86   
  

 

 

 

Gain/(loss) upon settlement

   $ 3,099,417   

Natural gas swaps

  

Volumes (Mcf)

     2,263,091   

Average swap price (per Mcf)

   $ 8.19   

Gain/(loss) upon settlement

   $ 19,501,993   
  

 

 

 

Total natural gas gain/(loss) upon settlement

   $ 22,601,409   
  

 

 

 

NGL swaps

  

Volumes (Mcf)

     75,000   

Average swap price (per Mcf)

   $ 56.79   

Gain/(loss) upon settlement

   $ (191,374)   
  

 

 

 

Total NGL gain/(loss) upon settlement

   $ (191,374
  

 

 

 

Total gain/(loss)

   $ 15,973,595   
  

 

 

 

The following derivatives contracts were in place as of December 31, 2011

 

Natural Gas

   Type      MMbtu /Mo. or Avg. MMbtu / Mo.      Price / MMbtu  

Jan-14 to Dec-14

     Swap         75,000       $ 4.99   

Jan-13 to Dec-13

     Swap         100,000       $ 4.66   

Jan-12 to Dec-12

     Collar         150,000       $ 6.50 - $8.10   

Jan-12 to Dec-12

     Swap         133,076       $ 5.00   

Jan-13 to Dec-14

     Swap         100,000       $ 5.20   

Jan -12 to Dec-12

     Collar         125,000       $ 3.45 - $3.81   

Jan-12 to Dec-12

     Swap         75,000       $ 5.15   

Jan-14 to Dec-14

     Collar         40,000       $ 5.10 - $6.20   

Jan-13 to Dec-13

     Collar         40,000       $ 5.00 - $5.85   

Jan-13 to Dec-13

     Collar         90,000       $ 4.75 - $5.75   

Jan-13 to Dec-13

     Collar         40,000       $ 4.70 - $5.75   

Jan-12 - Dec-12

     Collar         50,000       $ 4.25 - $5.35   

Jan-14 to Nov-14

     Collar         73,820       $ 4.50 - $6.15   

Crude Oil

   Type      Bbl / Mo. or Avg. Bbl / Mo.      Price / Bbl  

Jan-12 to Dec-12

     Collar         10,000       $ 80.00 - $93.24   

Jan-12 to Aug-12

     Collar         25,000       $ 80.00 - $91.60   

Sep-12 to Dec-12

     Collar         25,391       $ 80.00 - $86.00   

Jan-12 to Aug-12

     Swap         3,628       $ 101.60   

Jan-12 to Dec-12

     Collar         5,000       $ 90.00 - $96.50   

Jan-13 to Dec-13

     Collar         8,000       $ 92.00 - $102.95   

Jan-13 to Dec-13

     Collar         2,000       $ 93.00 - $102.00   

Jan-13 to Dec-14

     Collar         3,000       $ 91.00 - $98.00   

Jan-13 to Dec-14

     Collar         2,000       $ 90.00 - $97.00   

Jan-13 to Dec-14

     Collar         2,000       $ 91.00 - $97.00   

Jan-13 to Dec-14

     Collar         2,000       $ 92.00 - $98.00   

Jan-13 to Dec-14

     Collar         2,000       $ 92.00 - $100.00   

Jan-13 to Dec-14

     Collar         2,000       $ 93.00 - $101.00   

Jan-13 to Dec-14

     Swap         1,000       $ 91.00   

Jan-13 to Dec-14

     Swap         1,000       $ 91.50   

Jan-14 to Dec-14

     Collar         10,000       $ 93.00 - $100.25   

Jan-13 to Dec-13

     Collar         6,000       $ 90.00-$111.85   

 

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NGL

   Type      Bbl / Mo. or Avg. Bbl / Mo.      Price / Bbl  

Jan-13 to Dec-13

     Swap         5,137       $ 47.20   

Jan-12 to Dec-12

     Swap         4,148       $ 52.40   

Jan-12 to Dec-12

     Swap         5,000       $ 51.00   

Jan-13 to Dec-13

     Swap         3,300       $ 46.25   

Jan-12 to Dec-12

     Swap         6,000       $ 51.25   

Jan-13 to Dec-13

     Swap         4,000       $ 47.00   

Jan-14 to Dec-14

     Swap         6,500       $ 43.75   

 

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

 

      Page  

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     62   

CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER  31, 2011 AND 2010, AND FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009:

  

Balance sheets

     63   

Statements of operations

     64   

Statements of changes in stockholders’ (deficit)

     65   

Statements of cash flows

     66   

Notes to consolidated financial statements

     67   

SUPPLEMENTAL DISCLOSURE ABOUT OIL  & GAS PRODUCING ACTIVITIES

     81   

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Milagro Oil & Gas, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Milagro Oil & Gas, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Milagro Oil & Gas, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for oil and natural gas reserves and disclosures on December 31, 2009.

/s/ Deloitte & Touche LLP

Houston, Texas

March 29, 2012

 

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MILAGRO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010

 

     2011     2010  
     (Amounts in thousands)  

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 9,356      $ 17,734   

Accounts receivable:

    

Oil and natural gas sales

     22,288        18,480   

Joint interest billings and other — net of allowance for doubtful accounts of $831 and $615 at December 31, 2011 and 2010, respectively

     1,124        2,530   

Derivative assets — current

     11,405        18,834   

Prepaid expenses and other

     3,041        2,518   
  

 

 

   

 

 

 

Total current assets

     47,214        60,096   
  

 

 

   

 

 

 

PROPERTY, PLANT AND EQUIPMENT:

    

Oil and natural gas properties — full cost method:

    

Proved properties

     1,279,276        1,181,948   

Unproved properties

     14,914        13,156   

Less accumulated depreciation, depletion and amortization

     (812,364     (743,637
  

 

 

   

 

 

 

Net oil and natural gas properties

     481,826        451,467   

Other property and equipment — net of accumulated depreciation of $ 6,114 and $5,436 at December 31, 2011 and 2010, respectively

     1,236        1,718   
  

 

 

   

 

 

 

Net property, plant and equipment

     483,062        453,185   
  

 

 

   

 

 

 

DERIVATIVE ASSETS

     6,875        2,646   
  

 

 

   

 

 

 

OTHER ASSETS:

    

Deferred financing fees, net

     7,856        1,813   

Advance to affiliate

     2,391        2,248   

Other

     6,379        2,210   
  

 

 

   

 

 

 

Total other assets

     16,626        6,271   
  

 

 

   

 

 

 

TOTAL

   $ 553,777      $ 522,198   
  

 

 

   

 

 

 

LIABILITIES AND STOCKHOLDERS’ DEFICIT

    

CURRENT LIABILITIES:

    

Accounts payable

   $ 4,875      $ 4,680   

Accrued liabilities

     33,185        34,992   

Current portion of long-term debt

     —          244,580   

Accrued interest payable

     4,074        1,959   

Derivative liabilities

     5,186        9,427   

Asset retirement obligation — current

     3,199        2,921   
  

 

 

   

 

 

 

Total current liabilities

     50,519        298,559   
  

 

 

   

 

 

 

NONCURRENT LIABILITIES:

    

Long-term debt

     381,879        92,390   

Series A preferred stock (Note 8)

     —          223,630   

Asset retirement obligation — noncurrent

     41,441        37,350   

Derivative liabilities — noncurrent

     853        2,926   

Other

     3,931        3,173   
  

 

 

   

 

 

 

Total noncurrent liabilities

     428,104        359,469   
  

 

 

   

 

 

 

Total liabilities

     478,623        658,028   

MEZZANINE EQUITY

    

Redeemable series A preferred stock (Note 10)

     234,558        —     
  

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 13)

    

STOCKHOLDERS’ DEFICIT

    

Common shares (par value, $0.01 per share; shares authorized:

    

1,000,000; shares issued and outstanding: 280,400 as of December 31, 2011 and 2010, respectively)

     3        3   

Additional paid-in-capital

     (66,813     (66,813

Accumulated (deficit)

     (92,594     (69,020
  

 

 

   

 

 

 

Total stockholders’ deficit

     (159,404     (135,830
  

 

 

   

 

 

 

TOTAL

   $ 553,777      $ 522,198   
  

 

 

   

 

 

 

See notes to consolidated financial statements.

 

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MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009

 

     2011     2010     2009  
     (Amounts in thousands)  

REVENUES:

      

Oil and natural gas revenues

   $ 138,210      $ 134,207      $ 128,782   

Gain on commodity derivatives

     15,577        22,943        25,606   
  

 

 

   

 

 

   

 

 

 

Total revenues

     153,787        157,150        154,388   
  

 

 

   

 

 

   

 

 

 

COSTS AND EXPENSES:

      

Gathering and transportation

     1,472        1,282        1,925   

Lease operating

     35,152        34,283        32,542   

Environmental remediation

     1,988        —          —     

Taxes other than income

     9,939        10,904        9,017   

Depreciation, depletion, and amortization

     51,240        54,272        68,899   

Full cost ceiling impairment

     18,164        —          39,638   

General and administrative

     16,483        17,469        18,849   

Accretion

     3,205        2,627        2,712   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     137,643        120,837        173,582   
  

 

 

   

 

 

   

 

 

 

OTHER (INCOME) EXPENSE:

      

Net (gain) loss on interest rate derivatives

     (1,854     2,127        5,725   

Other (income) expense

     (555     (669     552   

Interest and related expenses, net of amounts capitalized

     41,100        48,021        40,587   

Loss on extinguishment of debt

     1,027        —          —     
  

 

 

   

 

 

   

 

 

 

Total other expense

     39,718        49,479        46,864   
  

 

 

   

 

 

   

 

 

 

LOSS BEFORE INCOME TAX

     (23,574     (13,166     (66,058

INCOME TAX EXPENSE (BENEFIT)

     —          57,422        (57,422
  

 

 

   

 

 

   

 

 

 

NET LOSS

     (23,574     (70,588     (8,636
  

 

 

   

 

 

   

 

 

 

Preferred dividends

     18,634        —          —     
  

 

 

   

 

 

   

 

 

 

NET LOSS AVAILABLE TO COMMON SHAREHOLDERS

   $ (42,208   $ (70,588   $ (8,636
  

 

 

   

 

 

   

 

 

 

See notes to consolidated financial statements.

 

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MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009

 

     Total
Members’
Equity*
    Common Stock      Additional
Paid in
Capital
    Accumulated
Earnings
(Deficit)
    Total
Stockholder’s
Equity
(Deficit)
 
     Shares      Par
Value
        
     (In thousands, except for share amounts)  

BALANCE — December 31, 2008

     (60,251     —           —           —          —          —     

Net loss January 1, 2009 through July 31, 2009

     (10,204            

Distributions

     (96            

Stock based compensation

     1,136               
  

 

 

             

 

 

 

Equity at July 31, 2009

     (69,415            

Entity conversion from LLC to C-Corp

     69,415              (69,415       (69,415