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, 2012

o 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 o 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 o 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 o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 o

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	o	Accelerated filer	o
Non-accelerated filer	x	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of March 28, 2013, there were 280,400 shares of the registrant’s common stock, par value $.01 per share, outstanding.

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TABLE OF CONTENTS

	Page
PART I
Items 1and 2. Description of Business and Properties		4
Item 1A. Risk Factors		18
Item 1B. Unresolved Staff Comments		28
Item 3. Legal Proceedings		28
Item 4. Mine Safety Disclosures		28
PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6. Selected Financial Data		30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A. Quantitative and Qualitative Disclosure About Market Risk		47
Item 8. Financial Statements and Supplementary Data		50
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		73
Item 9A. Controls and Procedures		73
Item 9B. Other Information		73
PART III
Item 10. Directors, Executive Officers and Corporate Governance		74
Item 11. Executive Compensation		76
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		87
Item 13. Certain Relationships and Related Transactions, and Director Independence		88
Item 14. Principal Accounting Fees and Services		89
PART IV
Item 15. Exhibits and Financial Statement Schedules		91

2

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 level of indebtedness;

• covenant restrictions under our debt agreements;

• 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;

• exploration, 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;

• 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.

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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, 2012, we owned interests in 1,436 gross (845.2 net) wells and had average daily net production in December 2012 of approximately 7,054 Boe/d and approximately 7,308 Boe/d for the year ended December 31, 2012. The wells that we operate provided approximately 78% of our average daily production for 2012. As of December 31, 2012, our estimated net proved reserves, as prepared by our independent reserve engineering firm, W.D. Von Gonten & Co., were 33.6 MMBoe, consisting of 106.8 Bcf of natural gas, 10.9 MMBbl of oil, and 4.9 MMBbl of NGL. As of December 31, 2012, approximately 53% of our net proved reserves were natural gas and approximately 47% were oil and NGL, and approximately 59% of our reserves were proved developed. Our estimated reserve to production ratio as of December 31, 2012 was 12.6 years. During 2012, we drilled 16 gross (9.2 net) wells, consisting of eight gross (3.5 net) exploratory wells and eight gross (5.7 net) developments wells with an average success rate of 75%.

For the year ended December 31, 2012, we spent approximately $32.5 million in capital expenditures to support our business plan. Of this amount we spent approximately $16.0 million to drill or complete 16 gross (9.2 net) wells, of which 12 were successful, adding approximately 575 net Boe/d to our 2012 average daily production. Of these 16 gross wells, ten were completed in 2012, four were dry holes and two are going to be completed in early 2013.We also recompleted or worked over approximately 102 gross (78.9 net) wells during 2012 at a capital cost of approximately $12.0 million and approximately $1.6 million, net of insurance proceeds of approximately $1.7 million, was spent to plug and abandon wells. The remaining capital expenditures of approximately $2.9 million were related primarily to seismic, facilities, vehicles and other items associated with our operations. Our workover efforts added approximately 634 Boe/d to our average daily production for 2012. Our 2013 capital budget contemplates spending approximately $21.7 million in connection with the drilling and completion of 24 gross (13.7 net) wells. Two of these 24 completions are carried over from 2012 to be done in early 2013. Of the 24 wells, 12 will be operated and 12 will be non-operated. Of the operated wells, ten are planned in our Texas Gulf Coast area and two are planned for our Southeast area. Of the 12 non-operated wells, eight are planned in our South Texas area with three in our Midcontinent area and one in our Southeast area.

The following table provides information with respect to our estimated net proved reserves as of December 31, 2012, as prepared by W.D. Von Gonten & Co., and our average daily production for 2012.

											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		2012 Average Daily Production (Boe/d) ( c)		% of 2012 Average Daily Production
Texas Gulf Coast		9.8		29.2		207.9		218.6		72.1		476.0		294.9		2,374.1		32.5
Southeast		7.6		22.6		163.3		168.5		45.5		422.0		226.5		2,097.2		28.7
South Texas		9.0		26.8		80.1		107.1		83.6		408.0		245.0		2,050.4		28.0
Midcontinent		7.2		21.4		37.1		44.3		63.8		130.0		78.8		786.4		10.8
Total		33.6		100.0		488.4		538.5		66.8		1,436.0		845.2		7,308.1		100.0

(a)	Our “SEC Pricing” net proved reserves as of December 31, 2012, 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 preceding twelve months ended on such date. These average prices were $94.71 per Bbl for oil and $2.76 per MMBtu for natural gas for December 31, 2012. 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, 2012 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, 2012, the assumed oil prices were $91.97 per Bbl in 2012, $93.22 per Bbl in 2013, $92.16 per Bbl in 2014, $89.93 per Bbl in 2015 and $88.04 per Bbl in 2016 and $86.68  per Bbl held constant thereafter and the assumed natural gas prices were $3.33 per MMBtu in 2012, $3.55 per MMBtu in 2013, $3.99 per MMBtu in 2014, $4.20 per MMBtu in 2015 and $4.41 per MMBtu in 2016 and $4.65 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.

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Business Strategy

The key elements of our business strategy are to:

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

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 and which have a strong proved developed producing component. We intend to focus on properties that are weighted towards oil or NGL, provide greater geographic diversity, and contribute towards extending our current reserve to production ratio of 12.6 years.

Continue our lower risk development drilling program

We intend to continue our lower risk development drilling program which is 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 129 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 14 development wells during 2013.

Grow our proved reserves and production

In 2012, we drilled eight gross (5.7 net) development wells, with a success rate of 100%, adding approximately 436 Boe/d to our average daily production for 2012. During 2012, our production replacement strategy and various drilling activities enabled us to maintain a relatively flat daily production profile of approximately 7,308 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 future goal of maintaining 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 expenses. We also intend to rationalize high cost and low profit assets. 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, 2012, we had hedging contracts in place for 968,704 Boe from January 1, 2013 through the end of 2013 and 767,200 Boe during 2014. Based on the forecasted production set forth in our January 1, 2013 reserve report, we have hedged approximately 50% of our expected 2013 and 2014 proved developed producing production as of December 31, 2012. 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 exploration, exploitation and development efforts

As of December 31, 2012, we had 64,426 gross (51,550 net) acres of undeveloped leasehold acreage and have identified 129 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 2013 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 54.2% of our properties, based on producing wells at December 31, 2012, 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.

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 2011, we 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.

5

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

Since 2007, we have spent approximately $27.4 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 intend to re-process some of this 3-D data in 2013 in order to enhance our ability to see subsurface structures and stratigraphy. 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 8 operational and technical professionals, including geophysicists and geologists, as well as 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 levels of expertise within our project teams, we believe we possess a competitive advantage in our acquisition, exploration, 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, exploration, 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, 2012. 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 licensed 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 former Corporate Engineering Manager, Vignesh Proddaturi, who is a licensed petroleum engineer in the State of Texas with over seven years’ experience in oil and natural gas reserve estimation, was also responsible for preparing our internal reserve reports. Mr. Proddaturi left the Company in December 2012, at which time we contracted the services of Glenn Sliva as a corporate engineering consultant. Mr. Sliva is a professional engineer licensed in the State of Texas with over thirty-one years of experience in oil and gas reserve estimation and he has assumed the responsibilities for preparing our internal reserve reports. 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.

The following table sets forth certain information about our estimated net proved reserves calculated using SEC pricing as of December 31, 2012.

	Oil (MBbls)		Natural Gas (MMcf)		NGL (MBbls)		Total MMBoe
Proved Developed		5,135		38,324		1,653		13.2
Proved Developed Non-Producing		1,757		28,212		260		6.7
Proved Undeveloped		3,971		40,222		2,966		13.7
Total Proved		10,863		106,758		4,879		33.6

As of December 31, 2012, our proved undeveloped reserve locations totaled 13.7 MMBoe, a 6% decrease from our proved undeveloped reserve locations at December 31, 2011. During 2012, we spent approximately $18.2 million converting eight of our proved undeveloped reserve locations at December 31, 2011 to prove developed at December 31, 2012. The majority of the decrease in our proved undeveloped reserves was the result of our business decisions to concentrate on oil focused locations and delay development of our gas focused locations due to low gas prices. This delay caused us to reclassify to probable some of our gas focused locations. We expect all of our proved undeveloped reserve locations at December 31, 2012 to be developed over the next five years. Estimated future costs related to the development of these locations are expected to total approximately $188.4 million.

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The estimated cash flows from our proved reserves at December 31, 2012 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)		379,170		190,805		324,509		894,484
Discounted pre-tax future net cash flows (PV-10)(1)		235,119		96,722		156,619		488,460

(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, 2012 using “SEC Pricing.”

Estimated pre-tax future net cash flows	$	894,484
10% annual discount		(406,024	)
Discounted pre-tax future net cash flows (PV-10)	$	488,460
Future income taxes discounted at 10%		(31,712	)
Standardized measure of discounted future net cash flows	$	456,748

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 area are the Magnet Withers and Lions fields. Since January 1, 2008, we have drilled 49 gross (37.6 net) wells on our Texas Gulf Coast properties and we have completed 41 of those wells. As of December 31, 2012, we had interests in 476 gross (294.9 net) wells in this area, with an average net working interest of 62.0% and average daily net production in December 2012 of approximately 2,374.1 Boe/d. We operate approximately 58.4% of our properties in the Texas Gulf Coast based on producing wells at December 31, 2012. In 2012, we drilled five development wells in our Texas Gulf Coast area, as well as performed 27 production enhancing workovers. We currently anticipate drilling ten development wells in this area in 2013, all of which will be in the Magnet Withers field.

At December 31, 2012, net proved reserves attributable to the Magnet Withers field were approximately 2.6 Bcf of natural gas and 3.6 MMBbl of oil and NGL. Our properties within the Magnet Withers field account for 11% of our total net proved reserves. During 2012, our average daily net production from the Magnet Withers field averaged 779 Boe/d, including approximately 0.3 MMcf/d of natural gas and approximately 722 Bbl/d of oil and NGL, down from 873 Boe/d during 2011.

Magnet Withers is a regional  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 normal 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 remaining oil in off-structure accumulations which have been targeted by recent drilling.

At December 31, 2012, 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 2012, our daily net production from the Lions field averaged 355 Boe/d, including approximately 2.1 MMcf of natural gas, down from 538 Boe/d during 2011.

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.

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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 19 gross (12.2 net) wells on our Southeast properties and have completed 13 of those wells. As of December 31, 2012, we had interests in 422 gross (226.5 net) wells in this area, with an average working interest of 53.5% and average net daily production in December 2012 of approximately 2,097.2 Boe/d. We operate approximately 42.6% of our properties in our Southeast area based on producing wells at December 31, 2012. In 2012, we drilled one development well, one exploratory well and participated in another exploratory well.  We also performed eight production enhancing workovers. The Robertson 21-7 #2 development well, operated by Roundtree and Associates, started production in 2013.

At December 31, 2012, net proved reserves attributable to the Gueydan Dome were approximately 0.3 Bcf of natural gas with 0.4 MMBbl of oil and NGL. The Gueydan Dome accounts for 1.3% of our total net proved reserves. During 2012, our average daily net production from the Gueydan Dome averaged 248 Boe/d, including approximately 0.1 MMcf/d of natural gas and approximately 240 Bbl/d of oil, down from 270 Boe/d during 2011.

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. We currently anticipate drilling two development wells in the Gueydan Dome field in 2013.

At December 31, 2012, 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 2012, our average daily net production from West Lake Verret averaged 525 Boe/d, including approximately 0.5 MMcf/d of natural gas and approximately 443 Bbl/d of oil, up from 332 Boe/d during 2011. 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, 2012 West Lake Verret net exit production rate was 450 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 normal pressured section above 11,500 feet. 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 our Southeast area, Mississippi and Texas, our Southeast area includes a non-operating interest in nine offshore fields in the Outer Continental Shelf off the coast of our Southeast area 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 33 gross (19.9 net) wells on our South Texas properties and have completed 23 of those wells. As of December 31, 2012, we had interests in 408 gross (245.0 net) producing wells in this area, with an average working interest of 60.0% and average daily net production in December 2012 of approximately 2,050.4 Boe/d. We operate approximately 55.0% of our properties in the South Texas area based on producing wells at December 31, 2012. In 2012, we participated in two non-operated development wells and three non-operated exploratory wells in the South Texas area and performed eight production enhancing workovers. One of these, the Gran Torino A #1H exploratory well in the Eagle Ford formation, operated by Abraxas Petroleum Corporation, was drilled in February 2013 and will start production in March 2013. We anticipate drilling six additional non-operated development wells in this area in 2013.

At December 31, 2012, net proved reserves attributable to the Nabors field were approximately 7.4 Bcf of natural gas with 0.4 MMBbl of oil and NGL. Nabors accounts for 4.4% of our total net proved reserves. During 2012, our average daily net production from Nabors averaged 481 Boe/d, including approximately 2.2 MMcf/d of natural gas, 115 Bbl/d of oil and NGL, down from 601 Boe/d during 2011.

Nabors is a high side closure with several inter-field faults breaking up the productive reservoirs. The reservoir is overpressured and comes 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, 2012, net proved reserves attributable to La Reforma were approximately 11.0 Bcf of natural gas with 0.9 MMBbl of oil and NGL. La Reforma accounts for 8.2% of our total net proved reserves. During 2012, our average daily production from the La Reforma field averaged 457 Boe/d, including approximately 2.2 MMcf/d of natural gas, 150 Bbl/d of oil and NGL, up from 284 Boe/d during 2011.

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

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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 7.4 MMBoe as of December 31, 2012 and an average working interest of 60.6% and average daily net production in December 2012 of approximately 786 Boe/d including 2.2 MMcf of natural gas, 39 Bbl of oil and 377 Bbl of NGL. We operate approximately 72.7% of our properties in the Midcontinent area based on producing wells at December 31, 2012. We are the operator of the Boonesville Bend Conglomerate properties, which account for approximately 47% of the properties, based on producing wells at December 31, 2012. EOG Resources, Inc. and Devon Energy operate the deeper Barnett Shale properties. We have an average working interest of 23.9% with a corresponding average net revenue interest of 17.5% in the Barnett Shale and an average working interest of 73.6% with a corresponding net revenue interest of 52.1% in the Boonesville Bend Conglomerate properties. In 2012, we participated in two Devon horizontal wells drilled and completed in the Barnett Shale. A third Devon well, the Hartsell #1H, was drilled in December 2012 and was completed and initiated production in 2013. Two additional non-operated Barnett Shale horizontal wells will be drilled in 2013.

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 decade 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 a report of the U.S. Geological Survey numbers in January 2013, an estimated 26.7 trillion cubic feet of undiscovered natural gas, 98.5 MMBbl of undiscovered oil and 1.1 BBbl of undiscovered NGL 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. The majority of the new leases were procured with six year primary terms in an area known as Harper Trend. Also during 2012, we drilled one new exploratory well with a horizontal completion. The primary target was the Cottage Grove formation. The well is producing 140 Bbl/d as of February 20, 2013.

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.

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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 2012, ten customers collectively accounted for 78% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 21% and Enterprise Crude Oil LLC accounting for 20%. During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 17% and Enterprise Crude Oil, LLC accounting for 16% and Plains Marketing, L.P. accounting for 6%. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 19%, Enterprise Crude Oil, LLC accounting for 11% and Plains Marketing LP accounting for 6%. 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.

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 commodity 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,
	2012		2011		2010
Sales volumes:
Oil volumes (MBbls)
Texas Gulf Coast		322		288		270
Southeast		456		407		488
South Texas		81		87		112
Midcontinent		14		13		2
Total oil		873		795		872
Natural gas volumes (MMcf)
Texas Gulf Coast		3,293		4,773		6,486
Southeast		1,800		2,287		2,799
South Texas		3,298		3,549		4,286
Midcontinent		812		732		86
Total natural gas		9,203		11,341		13,657
NGL volumes (MBbls)
Texas Gulf Coast		1		1		7
Southeast		4		8		7
South Texas		118		94		111
Midcontinent		137		132		14
Total NGL		260		235		139
Total Oil Equivalent (MBoe)		2,667		2,920		3,287

	Year Ended December 31,
	2012		2011		2010
Average oil prices based on sales volumes:
Oil price (per Bbl)	$	105.62	$	103.06	$	78.58
Oil price including derivative settlement gains (losses) (per Bbl)	$	104.88	$	94.96	$	78.64
Average natural gas prices based on sales volumes:
Natural gas price (per Mcf)	$	2.59	$	3.93	$	4.39
Natural gas price including derivative settlement gains (losses) (per Mcf)	$	5.04	$	6.02	$	7.27
Average NGL prices based on sales volumes:
NGL prices (per Bbl)	$	35.61	$	49.74	$	41.14
NGL prices including derivative settlement gains (losses) (per Bbl)	$	45.72	$	48.93	$	41.14
Average equivalent prices based on sales volumes:
Oil equivalent price (per Boe)	$	46.80	$	47.33	$	40.83
Oil equivalent price including derivative settlement gains (losses) (per Boe)	$	56.02	$	53.16	$	52.80
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)	$	51.04	$	53.02	$	47.81
Average production costs (per Boe) based on sales volumes:
Lease operating expenses (including costs for operating and maintenance and workover expense)	$	13.67	$	12.04	$	10.43
Taxes other than income	$	4.40	$	3.40	$	3.32

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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:

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploration:
Productive		4.0		1.5		2.0		2.0		4.0		2.1
Non-productive		4.0		2.0		2.0		1.0		2.0		1.5
Total		8.0		3.5		4.0		3.0		6.0		3.6
Development:
Productive		8.0		5.7		7.0		5.5		6.0		5.8
Non-productive		0.0		0.0		0.0		0.0		0.0		0.0
Total		8.0		5.7		7.0		5.5		6.0		5.8

Productive Wells

The following table shows the number of producing wells we owned by location at December 31, 2012:

	Oil				Natural Gas
	Gross		Net		Gross		Net
Texas Gulf Coast		85.0		62.5		237.0		119.3
Southeast		97.0		65.1		107.0		25.4
South Texas		46.0		32.8		243.0		130.0
Midcontinent		44.0		32.0		77.0		40.4
Total		272.0		192.4		664.0		315.1

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage by location as of December 31, 2012:

	Leasehold Acreage
	Developed				Undeveloped
	Gross		Net		Gross		Net
Texas Gulf Coast		57,492		51,789		16,864		10,443
Southeast		55,611		48,295		2,580		2,517
South Texas		56,358		50,781		5,872		2,555
Midcontinent		30,665		29,775		37,110		36,035
Total		200,126		180,640		62,426		51,550

Undeveloped Acreage Expirations

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

	Acres Expiring
Twelve Months Ending:	Gross		Net
December 31, 2013		4,963		3,207
December 31, 2014		3,990		3,897
December 31, 2015		10,487		4,229
December 31, 2016		9,045		9,045
December 31, 2017		24,799		24,612
December 31, 2018 and thereafter		9,142		6,560
Total		62,426		51,550

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We have lease acreage that is 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.

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 we will be affected by any action taken materially differently than 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. It therefore reflects a significant expansion of FERC’s enforcement authority. We do not anticipate that we will be affected any differently than other producers of natural gas.

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In 2007, FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our general and administrative expenses. We do not anticipate that we will be affected any differently than other producers of natural gas.

Sales and Transportation of Crude Oil. Our sales of crude oil, condensate and NGL are not currently regulated, and are subject only to applicable contract provisions negotiated by us and our 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 NGL is generally less restrictive than FERC’s regulation of natural gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate and NGL 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. The Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement regulate offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico shelf, and removal of facilities.

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 “USEPA”), lessees must obtain a permit from The Bureau of Ocean Energy Management, Regulation and Enforcement 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 is 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. In the event we conduct operations on federal, state or American Indian onshore oil and natural gas leases, such operations 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, tribal or state agencies.

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.

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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, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

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 USEPA. Such regulations can increase the cost of our activities. 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 gradually become stricter 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 USEPA 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.

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Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials which precipitate on production equipment or area soils during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework, although such wastes may qualify for the oil and gas hazardous waste exclusion.  Primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.

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 USEPA 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 USEPA under CERCLA or by any state under a similar state law.

Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, NGL, liquefied natural gas, or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may generate waste that may fall within CERCLA's definition of a “hazardous substance” in the course of our ordinary operations. We also currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substances” may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. At this time, we do not believe that we have any liability associated with any Superfund site, and we have not been notified of any claim, liability or damages under CERCLA.

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 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 carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

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 USEPA 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.

Moreover, our exploration and production activities may involve the use of hydraulic fracturing techniques to stimulate wells and maximize natural gas production. Citing concerns over the potential for hydraulic fracturing to impact drinking water, human health and the environment, and in response to a congressional directive, the USEPA has commissioned a study to identify potential risks associated with hydraulic fracturing. The USEPA published a progress report on this study in December 2012 and a final draft report will be delivered in 2014. Additionally, the Bureau of Land Management (“BLM”) proposed to regulate the use of hydraulic fracturing on federal and tribal lands, but following extensive public comment on the proposals, announced it would issue an improved proposal before finalizing new rules.  The revised proposal is expected to address disclosure of fluids used in the fracturing process, integrity of well construction, and the management and disposal of wastewater that flows back from the drilling process.  Some states now regulate utilization of hydraulic fracturing and others are in the process of developing, or are considering development of, such rules. Depending on the results of the USEPA 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.

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Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The USEPA has promulgated 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 hydraulically fractured natural gas wells by January 1, 2015.  Other new rules, many effective in 2012, impose stricter standards on emissions associated with gas production, storage and transport. 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.

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 USEPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject to these reporting requirements include on- and offshore petroleum and natural gas production and onshore natural gas processing and distribution facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year in aggregate emissions from all site sources. We are not subject to GHG reporting requirements. In addition, the USEPA 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 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 not precluded certain state 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 USEPA 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, 2012, we had 103 employees. We have a land department staff that includes four landmen, an exploration staff that includes three geologists and one geological technician and an operations staff that includes five 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, 2012 was approximately $1.8 million. The lease term extends to August 31, 2017.

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Item 1A. Risk Factors

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

As of December 31, 2012, we had approximately $360.3 million in outstanding indebtedness and had approximately $40.0 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.

The instruments 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;

• 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 2013 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.  For example, the maximum leverage ratio will reduce to 4.00 to 1.0 as of March 31, 2013 and all periods thereafter. We are currently exploring a range of alternatives to be in compliance with the financial covenant on such date. Alternatives being considered include using cash flow from operations or 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. Unless we are able to execute one or more of these alternatives, our maximum leverage ratio may not meet the reduced threshold in the covenants beginning on March 31, 2013. In that event, we would have to seek a waiver or amendment to these agreements and, if not granted, the lenders could declare a default and we will not be able to borrow additional funds under the facility.

 

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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. These conditions also create a deficiency in short term and long term liquidity and raise substantial doubt about our ability to continue as a going concern.

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. In particular, a borrowing base redetermination was conducted in October of 2012 and the borrowing base is being reduced from $165 million to $135 million on a staggered basis over a six month period. The redetermination was effective starting November 1, 2012 and the borrowing base amount has been reduced by $5 million per month since then and will end at $135 million in April 2013. This will limit or inhibit our access to additional borrowings. We currently have approximately $115.0 million outstanding under our 2011 Credit Facility.  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, raise equity or debt capital 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 acquisition, exploration, 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, exploration, 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. For example, a borrowing base redetermination was conducted in October of 2012 and the borrowing base is being reduced from $165 million to $135 million on a staggered basis over a six month period. The redetermination was effective starting November 1, 2012 and the borrowing base amount has been reduced by $5 million per month since then and will end at $135 million in April 2013.  This will limit or inhibit our availability for additional borrowings. 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.

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 51.6% and 50.9% of our expected 2013 and 2014 proved developed producing production, respectively, has been hedged as of December 31, 2012, 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 commodity hedges for expected proved developed producing production by any certain date or at all or that our level of commodity hedges in 2013 and 2014 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 premium for oil and at a discount for natural gas when compared 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.

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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.

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, 2012, 2011 and 2010 of $33.4 million, $23.6 million and $70.6 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 exploration, 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, 2012, approximately 37% of our estimated net proved reserves were classified as undeveloped. At December 31, 2012, we estimated that it would require additional capital expenditures of approximately $188.4 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 2012 we had a ceiling limitation impairment of approximately $14.6 million, and in 2011 we had a ceiling limitation impairment of approximately $18.2 million. 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.”

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 exploration, 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.

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 proved reserve to production ratio of our properties is 12.6 years. As a result, unless we conduct successful development, exploration 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.

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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. We are currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio at March 31, 2013. Alternatives being considered include using cash flow from operations or 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. We are also considering seeking a waiver or amendment to the 2011 Credit Facility and the Notes with respect to the maximum leverage ratio. 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. These conditions also create a deficiency in short term and long term liquidity and raise substantial doubt about our ability to continue as a going concern.

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 54.2% of our properties, based on producing wells at December 31, 2012. 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 commodity 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 exploration, 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 exploration, 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.

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, 2012, we had leases representing 3,207 net acres expiring in 2013, 3,897 net acres expiring in 2014, and 4,229 net acres expiring in 2015. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our exploration, 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. Exploration, 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.

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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;

• 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 2011, our West Lake Verret field in our Southeast area was shut-in for approximately 75 days due to flooding of the Mississippi river, also in 2012; Hurricanes Isaac disrupted our Gulf Coast operations in several Southeast area fields forcing us to temporarily curtail production for approximately one week.

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;

• formations with abnormal pressures;

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• 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 exploration, exploitation and development of acquired and existing assets, with a focus on properties that are weighted towards oil or NGL 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.

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 2012, ten customers collectively accounted for 78% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 21% and Enterprise Crude Oil LLC accounting for 20%. During 2011, ten customers collectively accounted for 70% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 17% and Enterprise Crude Oil LLC accounting for 16%. During 2010, ten customers collectively accounted for 69% of our oil and natural gas revenues, with Shell Trading (US) Company accounting for 19%. 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;

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• 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 exploration, 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:

• 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.

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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.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or 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 October 2011, the Commodities Futures Trading Commission, or the CFTC, approved 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. These newly approved CFTC position limits rules were vacated by the United States District Court for the District of Columbia in September 2012, although the CFTC has stated that it will appeal the District Court's decision.

It is not possible at this time to predict with certainty the full effect of the Dodd-Frank Act and CFTC rules on us and the timing of such effects.  The Dodd-Frank Act may require us to comply with margin requirements and with certain clearing and trade-execution requirements if we do not satisfy certain specific exceptions.  The Dodd-Frank Act may also require the counterparties to our derivatives contracts to transfer or assign some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty.  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.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws applicable to oil and natural gas exploration and production companies. These changes include, but are not limited to:

· the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;

· the elimination of current deductions for intangible drilling and development costs;

· the elimination of the deduction for certain domestic production activities; and

· an extension of the amortization period for certain geological and geophysical expenditures.

Members of the U.S. Congress have considered similar changes to the existing federal income tax laws that affect oil and natural gas exploration and production companies.  It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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 USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject to these reporting requirements include on- and offshore petroleum and natural gas production and onshore natural gas processing and distribution facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year in aggregate emissions from all site sources.

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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.

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, 2012, we had federal net operating loss carryforwards (“NOLs”) of $100.0 million to offset future taxable income, which expire in various years beginning in 2029, which if fully utilized will result in a tax savings of $34.9 million. See Note 13- “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 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.

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.

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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 28, 2013, 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 for the years December 31, 2008 through 2012. The statement of operations data for each of the years ended December 31, 2010 through 2012 and the balance sheet data as of December 31, 2011 and 2012 set forth below are derived from our audited financial statements and the notes thereto included elsewhere in this document. 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.

	Years Ended December 31,
	2012			2011			2010			2009			2008
Operating data:
Revenues:
Oil and natural gas revenues	$	124,297		$	138,210		$	134,207		$	128,782		$	360,294
Gain on commodity derivatives		11,249			15,577			22,943			25,606			50,259
Total revenues	$	135,546		$	153,787		$	157,150		$	154,388		$	410,553
Costs and Expenses:
Operating costs	$	49,790		$	48,551		$	46,469		$	43,484		$	71,011
General and administrative(1)		14,311			16,483			17,469			18,849			19,499
Other		69,852			72,609			56,899			111,249			576,367
Total costs and expenses	$	133,953		$	137,643		$	120,837		$	173,582		$	666,877
Other expense:
Other expense	$	34,989		$	39,718		$	49,479		$	46,864		$	62,588
Total other expense		34,989			39,718			49,479			46,864			62,588
Loss before income tax		(33,396	)		(23,574	)		(13,166	)		(66,058	)		(318,912	)
Income tax expense (benefit)(2)		—			—			57,422			(57,422	)		—
Net loss	$	(33,396	)	$	(23,574	)	$	(70,588	)	$	(8,636	)	$	(318,912	)
Preferred dividends(3)		31,946			18,634			—			—			—
Net loss available to common stockholders	$	(65,342	)	$	(42,208	)	$	(70,588	)	$	(8,636	)	$	(318,912	)

	As of December 31,
	2012			2011			2010			2009			2008
	(In thousands)
Balance sheet data:
Cash and cash equivalents	$	2,188		$	9,356		$	17,734		$	10,531		$	—
Net property, plant and equipment		441,885			483,062			453,185			392,904			515,822
Total assets		480,760			553,777			522,198			526,060			622,588
Long-term debt including current portion		360,265			381,879			560,600			491,550			544,922
Mezzanine equity(3)		235,694			234,558			—			—			—
Stockholders’ deficit		(192,800	)		(159,404	)		(135,830	)		(67,032	)		(60,251	)
Total liabilities and stockholders’ deficit	$	480,760		$	553,777		$	522,198		$	526,060		$	622,588

(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, 2012, 2011, 2010, 2009 and 2008, such expenses were zero, zero, $1,788, $1,951 and $1,951, respectively. 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. 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.

Overview

We are an independent oil, NGL and natural gas company primarily engaged in the acquisition, exploration, exploitation, development and production of oil, natural gas and NGL 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 which 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.

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”).

For the year ended December 31, 2012, we spent approximately $32.5 million in capital expenditures to support our business plan. Of this amount we spent approximately $16.0 million to drill or complete 16 gross (9.2 net) wells (consisting of eight gross (3.5 net) exploratory wells and eight gross (5.7 net) developments wells, of which 12 were successful, adding approximately 575 net Boe/d to our 2012 average daily production.  Of these 16 gross wells, ten were completed in 2012,four were dry holes and two are going to be completed in early 2013).We also recompleted or worked over approximately 102 gross (78.9 net) wells during 2012 at a capital cost of approximately $12.0 million, approximately $1.6 million was spent to plug and abandon wells. The remaining capital expenditures of approximately $2.9 million was related primarily to seismic, facilities, vehicles and other items associated with operations.  Our workover efforts added approximately 634 Boe/d to our average daily production for 2012. Our 2013 capital budget contemplates spending approximately $21.7 million in connection with the drilling and completion of 24 gross (13.7 net) wells. Two of these 24 completions are carried over from 2012 to be done in early 2013. Of the 24 wells, 12 will be operated and 12 will be non-operated.  Of the operated wells, ten are planned in Gulf Coast and two are planned for our Southeast area. Of the 12 non-operated wells, eight are planned in our South Texas area with three in our Midcontinent area and one in our Southeast area. See “-Liquidity and Capital Resources” for more on our capital expenditures.

As of December 31, 2012, we owned interests in 1,436 gross (845.2 net) wells and had average daily net production in December 2012 of approximately 7,054 Boe/d and approximately 7,308 Boe/d for the year ended December 31, 2012. The wells that we operate provided approximately 78% of our average daily production for 2012. As of December 31, 2012, our estimated net proved reserves, as prepared by our independent reserve engineering firm, W.D. Von Gonten & Co., were 33.5 MMBoe, consisting of 106.8 Bcf of natural gas, 10.9 MMBbl of oil, and 4.9 MMBbl of NGL. As of December 31, 2012, approximately 53% of our net proved reserves were natural gas and approximately 47% were oil and NGL, and approximately 59% of our reserves were proved developed.  Our estimated reserve to production ratio as of December 31, 2012 was 12.6 years.

We replaced approximately 124% of our production and increased oil/liquids production from approximately 35% in 2011 to approximately 46% in 2012. We increased oil production by approximately 118% at Magnet Withers from approximately 550 Bbl/d in 2011 to approximately 1,200 Bbl/d in 2012 by performing workovers. We updated and completed 67 field studies adding approximately 5.4 MMboe of new reserves in all categories.

The outstanding balance was reduced on our 2011 Credit Facility from approximately $138 million at the end of 2011 to approximately $115 million at December 31, 2012 and we remained in compliance with all financial covenants under the 2011 Credit Facility. 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. See Note 2 to our consolidated financial statements, for further discussion of liquidity.

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Sources of Our Revenues

We derive our revenues from the sale of oil, NGL 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 obtain commodity derivatives for 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. We have also entered into basis swaps (Light Louisiana Sweet vs. West Texas Intermediate) and the volumes relative to these contracts are not counted towards the percent of PDP under commodity derivative contracts .The approved counterparties are limited to those financial institutions that participate in the 2011 Credit Facility. As of December 31, 2012, we had the following oil, NGL and natural gas commodity derivative positions:

% of PDP Hedged

Year	Crude Oil			Natural Gas			NGL
2013		50	%		52	%		56	%
2014		51	%		50	%		55	%

In order to achieve more predictable cash flows and to reduce our exposure to downward commodity price fluctuations, we utilize derivative instruments to manage risks of future sales prices on a portion of our oil, NGL and natural gas production. As of December 31, 2012, we had commodity derivative contracts in place for 968,704 Boe from January 1, 2013, through the end of 2013, and 767,200 Boe during 2014. Based on the expected production set forth in our January 1, 2013 reserve report, we have commodity derivatives of approximately 50% of our forecasted 2013 and 2014 PDP production as of December 31, 2012. In 2012, we realized commodity derivative gains of approximately $24.5 million, but we expect this to be significantly less in 2013. 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 commodity derivative 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 production 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, NGL 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, NGL and natural gas prices rise.

• Historically, taxing authorities have from time to time encouraged the oil, NGL and natural gas industry to explore for new oil, NGL 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, NGL 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 exploration, exploitation and development efforts, including a portion of our interest and certain internal expenses that are specific to exploration, 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, NGL 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.

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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 expenses directly related to exploration, exploitation and development efforts.

Interest. We have relied on a combination of debt financings to fund our short-term liquidity and a portion of our long-term financing needs. On December 31, 2012, we had approximately $115.0 million of LIBOR-based floating rate indebtedness and base 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.

The 2011 Credit Facility borrowing base redetermination was conducted in October of 2012 and will be reduced from $165 million to $135 million on a staggered basis over a six month period. The redetermination was effective starting November 1, 2012 and the borrowing base amount will reduce by $5.0 million per month for the following six months, ending at $135 million in April 2013. As of December 31, 2012 the borrowing base was $155 million. 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 (as described in “Liquidity and Capital Resources – Capital Resources”). On December 31, 2012, we had approximately $360.3 million outstanding of total indebtedness.

Income Taxes. We recorded no income tax benefit or expense for the year ended December 31, 2012. 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, 2012.

As of December 31, 2012, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2012. 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, 2013.

Oil, NGL and Natural Gas Reserves

Our estimated total net proved reserves of as of December 31, 2012 and 2011 were as follows:

	As of December 31,
	2012			% Change			2011
Estimated Net Proved Reserves:
Oil (MMBbls)		10.9			18	%		9.2
Natural gas (Bcf)		106.8			(22)	%		136.8
NGL (MMBbls)		4.9			(8)	%		5.3
Total oil equivalent (MMBoe)		33.6			(10)	%		37.3
Proved developed reserves as a percentage of net proved reserves		59	%		(2)	%		61	%

Our estimated total net proved reserves decreased 10% in the period ended December 31, 2012 as compared to the same period in 2011. This decrease in our estimated total net proved reserves was primarily the result of production and SEC price revisions.  This decrease was partially offset by reserves obtained through field studies performed in Texas and Louisiana focusing on oil reserves.

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, 2012 Compared to Year Ended December 31, 2011

Sales Volumes

	Year Ended December 31,
	2012		% Change			2011
Oil (MBbls)		873		10	%		795
Natural gas (MMcf)		9,203		(19)	%		11,341
NGL (MBbls)		260		11	%		235
Total (MBoe)		2,667		(9	)%		2,920
Average daily production volumes (MBoe/d)(a)		7.3		(9	)%		8.0

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

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For the years ended December 31, 2012, our net equivalent production volumes decreased by 9% to 2,667 MBoe (7.3 MBoe/d) from 2,920 MBoe (8.0 MBoe/d) in 2011. Our production volumes in 2012 as compared to 2011 decreased primarily due to natural decline in production in our core areas and the shutting in of producing properties in our Texas Gulf Coast area due to pipeline shut-in issues. Natural gas represented approximately 58% and 65% of our total production in the years ended December 31, 2012 and 2011, respectively.

Revenues. The following tables shows (1) our revenues from the sale of oil, natural gas and NGL and (2) the impact of changes in price and sales volumes on our oil, NGL and natural gas revenues during the years ended December 31, 2012 and 2011. 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,
	2012			%Change			2011
	(In thousands)
Oil revenues:
Oil revenues	$	91,248			11	%	$	81,924
Oil derivative settlements		(637	)		(90	) %		(6,436	)
Oil revenues including oil derivative settlements		90,611			20	%		75,488
Natural gas revenues:
Natural gas revenues		23,800			(47	) %		44,596
Natural gas derivative settlements		22,487			(1	) %		22,601
Natural gas revenues including derivative settlements		46,287			(31	) %		67,197
NGL revenue:
NGL revenues		9,249			(21	) %		11,689
NGL derivative settlements		2,625			(1,474	) %		(191	)
NGL revenues including derivative settlements		11,874			3	%		11,498
Oil, natural gas and NGL revenues:
Oil, natural gas and NGL revenues		124,297			(10	) %		138,210
Oil, natural gas and NGL derivative settlements		24,475			53	%		15,973
Oil, natural gas and NGL revenues including derivative settlement gains (losses)		148,772			(4	) %		154,183
Oil, natural gas and NGL derivative unrealized gains (losses)		(13,226	)		3,240	%		(396	)
Oil, natural gas and NGL revenues including derivative settlements and unrealized gains (losses)		135,546			(12	) %		153,787
Total revenues	$	135,546			(12	) %	$	153,787

	Change from Year Ended December 31, 2011 to Year Ended December 31, 2012
	(In thousands)
Change in revenues from the sale of oil :
Price variance impact	$	1,266
Sales volume variance impact		8,057
Total change		9,323
Change in revenues from the sale of natural gas:
Price variance impact	$	(12,391	)
Sales volume variance impact		(8,405	)
Total change		(20,796	)
Change in revenues from the sale of NGL:
Price variance impact	$	(3,652	)
Sales volume variance impact		1,212
Total change		(2,440	)
Change in revenues from the sale of oil, natural gas and NGL:
Price variance impact	$	(14,777	)
Volume variance impact		864
Change in cash settlement of derivative hedging contracts		8,502
Changes in unrealized losses due to derivative hedging contracts		(12,830	)
Total change	$	(18,241	)

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	Year Ended December 31,
	2012			% Change			2011
Oil price:
Oil price per Bbl	$	104.52			1	%	$	103.05
Oil derivative settlements per Bbl		(0.73	)		(91	)%		(8.10	)
Oil revenues including oil derivative settlements per Bbl	$	103.79			9	%	$	94.95
NGL price:
NGL revenues	$	35.57			(28	)%	$	49.74
NGL derivative settlements per Bbl		10.10			(1,347	)%		(0.81	)
NGL revenues including derivative settlements	$	45.67			(7	)%	$	48.93
Natural gas price:
Natural gas per Mcf	$	2.59			(34	)%	$	3.93
Natural gas derivative settlements per Mcf		2.44			23	%		1.99
Natural gas revenues including derivative settlements per Mcf	$	5.03			(15	)%	$	5.92
Oil, NGL and natural gas price per BOE:
Oil, NGL and natural gas revenues per BOE	$	46.61			(2	)%	$	47.33
-Oil, NGL and natural gas derivative settlements per BOE		9.18			68	%		5.47
Oil, NGL and natural gas revenues including derivative settlements per BOE	$	55.79			6	%	$	52.80
Oil, NGL and natural gas derivative unrealized gains per BOE		(4.96	)		3,443	%		(0.14	)
Oil, NGL and natural gas revenues including derivative settlements and unrealized gains per BOE	$	50.83			(3	)%	$	52.66
Total price per BOE	$	50.83			(3	)%	$	52.66

Our oil, NGL and natural gas revenues, including derivatives settlements and unrealized gains (losses), for the year ended December 31, 2012 decreased by approximately $18.2 million, or 12%, when compared to the same period in 2011. The pre-hedged revenue decreased by approximately $13.9 million. This decrease related to lower prices of natural gas and NGL of approximately $16.0 million and lower production of natural gas of approximately $8.4 million, which was partially offset by higher oil prices of approximately $1.3 million, and higher production of oil and NGL of approximately $9.2 million. The decrease in hedged gains was due primarily to higher losses on unrealized commodity derivatives of approximately $12.8 million which was partially offset by higher realized commodity derivatives gains of approximately $8.5 million.

Production costs. Production volumes in the year ended December 31, 2012 decreased by approximately 9% as compared to the same period in 2011 to 2.7 MMBoe from 2.9 MMBoe. Per unit production cost in 2012 increased by $2.05/Boe, or 12%, and total production costs in 2012 increased by approximately $1.2 million, or 3%, as compared to 2011. The increase in rate was primarily attributable to the natural decline in production in our core areas. Our per unit and total production costs for the years ended December 31, 2012 and 2011 are as set forth below.

	Unit-of-Production
	(Per Boe Based on Sales Volumes)
	Year Ended December 31,
	2012		% Change			2011
Production costs:
Gathering and transportation	$	0.60		20	%	$	0.50
Operating and maintenance		12.62		15	%		10.93
Workover expenses		1.05		(5	)%		1.11
Lease operating expense		14.27		14	%		12.54
Remediation expenses		—		(100	)%		0.68
Taxes other than income		4.40		29	%		3.40
Production costs	$	18.67		12	%	$	16.62

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	Production Costs
	Year Ended December 31,
		2012	% Change				2011
	(In thousands)
Production costs:
Gathering and transportation	$	1,610		9	%	$	1,472
Operating and maintenance		33,651		5	%		31,922
Workover expenses		2,797		(13	)%		3,230
Lease operating expense		38,058		4	%		36,624
Remediation expenses		—		(100	)%		1,988
Taxes other than income		11,732		18	%		9,939
Production costs	$	49,790		3	%	$	48,551

Gathering and transportation costs in 2012 were approximately $1.6 million, compared to approximately $1.5 million in 2011, an increase of approximately $0.1 million, or 9%. This increase was primarily due to the Newfield acquisition in September 2011, which increased our NGL production resulting in higher gathering and transportation costs. For more on the acquisition, see Note 3 to our consolidated financial statements included herein.

Operating and maintenance costs for the year ended December 31, 2012 were approximately $33.7 million, compared to approximately $32.0 million in the same period of 2011, an increase of approximately $1.7 million, or 5%. This increase in operating and maintenance costs was related to higher labor, gas lift and repair costs that was partially offset by lower direct legal cost.

Workover expenses for the year ended December 31, 2012 were approximately $2.8 million, compared to approximately $3.2 million for the same period in 2011, a decrease of approximately $0.4 million, or 13%. This decrease was due primarily to a decrease in the cost of our workovers in 2012 as compared to 2011.

There were no environmental remediation costs incurred for the year ended December 31, 2012. In 2011, environmental remediation expenses were approximately $2.0 million and were incurred as the result of our participation in a settlement involving environmental remediation in a field in which we have an ownership interest.

Taxes other than income for the year ended December 31, 2012 were approximately $11.7 million, compared to approximately $9.9 million in the same period of 2011, an increase of $1.8 million or 18%. This increase 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, exploitation and development 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, 2012 and 2011 were as follows:

	Year Ended December 31,
	2012			% Change			2011
	(In thousands, except per unit measurements which are based on sales volumes)
General and administrative expenses — gross		$	17,856		(15	)%		$	21,005
Capitalized general and administrative expenses			3,545		(22	)%			4,522
General and administrative expenses — net		$	14,311		(13	)%		$	16,483
General and administrative expenses — gross $ (per Boe)		$	6.70		(7	)%		$	7.19

Our gross general and administrative expenses for the year ended December 31, 2012 were approximately $17.9 million compared to approximately $21.0 million in the same period of 2011, a decrease of approximately $3.1 million, or 15%, primarily as a result of lower non-recurring consulting expenses in 2012. In 2011, there was a significant amount of expenses related to our 2011 Refinancing. After capitalization, our general and administrative expenses decreased by approximately $2.2 million, or 13%, to approximately $14.3 million. Per unit general and administrative expense decreased primarily due to the decrease in non-recurring consulting expenses, offset by a decrease in production volumes.

Depletion of oil, NGL and natural gas properties.

	Year Ended December 31,
	2012		% Change			2011
	(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil, NGL and natural gas properties	$	50,505		0	%	$	50,476
Depletion of oil, NGL and natural gas properties (per Boe)	$	18.94		10	%	$	17.28

Our depletion expense for the years ended December 31, 2012 and December 31, 2011 was approximately $50.5 million.  Depletion expense decreased as a result of decreased production volumes, which resulted in lower depletion expense by approximately $4.8 million. This was offset by an increase in our depletion rate resulting in an increase in depletion expense of approximately $4.8 million.

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Impairment of oil, NGL and natural gas properties. For the year ended December 31, 2012, we reported an impairment of approximately $14.6 million to our oil, NGL and natural gas properties. The impairment occurred and was recorded at March 31, 2012 and September 30, 2012.  As of March 31, 2012, based on the average oil and natural gas prices in effect on the first day of each month during the first three months of 2012 and last nine month of 2011 ($3.53 per MMBtu for Henry Hub gas and $94.65 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized coast of our oil and natural gas properties exceeded the ceiling limit and we recorded an impairment of approximately $11.6 million to our oil and natural gas properties. As of September 30, 2012, based on the average oil, NGL and natural gas prices effect on the first day of each month during the first nine months of 2012 and the last three months of 2011 ($2.82 per MMBtu for Henry Hub and $91.48 per Bbl for west Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil, NGL and natural gas properties exceeded the ceiling limit and we recorded an impairment of approximately $3.0 million to our oil, NGL and natural gas properties. As of the three months ended June 30, 2012, there was no impairment needed and there was no impairment as of December 31, 2012, therefore the total impairment for the year ended December 31, 2012 was $14.6 million. An impairment of approximately $18.2 million was recorded for the year ended December 31, 2011.

Net interest expense. Our interest expense for the year ended December 31, 2012 and December 31, 2011 was approximately $35.9 million and $41.1 million, respectively. Total interest expense for the year ended December 31, 2012 benefited from our 2011 Refinancing that converted the Series A preferred stock from a debt instrument to mezzanine equity by approximately $9.8 million, offset by approximately $4.6 million related to the increase in interest expense due to a higher coupon on our Notes issued in May 2011.

Income taxes. For the years ended December 31, 2012 and 2011, current tax expense and deferred tax expense was approximately zero for both periods. 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, NGL 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, 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 our Southeast area 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, NGL 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	$	81,925			20	%	$	68,491
Oil derivative settlements		(6,437	)		—			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		67,197			(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		15,973			(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	$	(2,362	)

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	Year Ended December 31,
	2011			% Change			2010
Oil price:
Oil price per Bbl	$	103.05			31	%	$	78.54
Oil derivative settlements per Bbl		(8.10	)		(13,600	)%		0.06
Oil revenues including oil derivative settlements per Bbl	$	94.95			21	%	$	78.60
NGL price:
NGL revenues	$	49.74			21	%	$	41.13
NGL derivative settlements per Bbl		(0.81	)		100	%		—
NGL revenues including derivative settlements	$	48.93			19	%	$	41.13
Natural gas price:
Natural gas per Mcf	$	3.93			(10	)%	$	4.39
Natural gas derivative settlements per Mcf		1.99			(31	)%		2.88
Natural gas revenues including derivative settlements per Mcf	$	5.92			(19	)%	$	7.27
Oil, NGL and natural gas price per BOE:
Oil, NGL and natural gas revenues per BOE	$	47.33			16	%	$	40.83
-Oil, NGL and natural gas derivative settlements per BOE		5.47			(54	)%		11.97
Oil, NGL and natural gas revenues including derivative settlements per BOE	$	52.80			0	%	$	52.80
Oil, NGL and natural gas derivative unrealized gains per BOE		(0.14	)		(97	)%		(4.99	)
Oil, NGL and natural gas revenues including derivative settlements and unrealized gains per BOE	$	52.66			10	%	$	47.81
Total price per BOE	$	52.66			10	%	$	47.81

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

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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.

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 expenses 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, NGL 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, NGL and natural gas properties	$	50,476		(3	)%	$	51,779
Depletion of oil, NGL 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, NGL and natural gas properties. For the year ended December 31, 2011, based on the average oil, NGL 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, NGL and natural gas properties exceeded the ceiling limit and we recorded a $18.2 million impairment to our oil, NGL and natural gas properties. We did not record any impairment for the year ended December 31, 2010.

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Income taxes. For the years ended December 31, 2011 and 2010, current tax expense was zero for both periods 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.

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 the 2011 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.

Liquidity and Capital Resources

Historically, we have financed our acquisition, exploration, 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 exploration, 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, NGL and natural gas reserves.

The Company currently has indebtedness outstanding under the 2011 Credit Facility, which contains customary financial and other covenants.   The maximum leverage ratio, as defined, of debt balances as compared to EBITDA is required to be not greater than 4.25 to 1.0, which was 4.13 as of December 31, 2012. The maximum leverage ratio will reduce to 4.0 to 1.0 as of March 31, 2013 and all periods thereafter.

The Company is currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio at March 31, 2013. Alternatives being considered include using cash flow from operations or 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.  The Company is also considering seeking a waiver or amendment to the 2011 Credit Facility and the Notes with respect to the maximum leverage ratio.

Because the Company cannot provide assurances as to its ability to remain in compliance with its financial covenants at March 31, 2013, the Company received a going concern modification in the audit report from its independent registered public accounting firm for the year ended December 31, 2012. The 2011 Credit Facility provides that a going concern modification from an independent registered public accounting firm is a covenant breach. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of this covenant breach, the Company has classified approximately $115.0 million of borrowings under the Credit Facility and approximately $245.5 million of the Notes as current liabilities.  At December 31, 2012, this results in current liabilities exceeding current assets by approximately $371.5 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent the Company from borrowing additional funds under the 2011 Credit Facility.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about the Company’s ability to continue as a going concern.  The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

Sources and Uses of Cash

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

	Year Ended December 31,
	2012			% Change			2011			% Change			2010
	(In thousands)
Net loss	$	(33,396	)		(42	)%	$	(23,574	)		(67	)%	$	(70,588	)
Non-cash items		87,874			(4	)%		84,635			(46	)%		157,652
Changes in working capital and other items		(1,744	)		(35	)%		(2,673	)		(132	)%		8,253
Cash flows provided by operating activities	$	52,734			(10	)%	$	58,388			(39	)%	$	95,317
Cash flows used in investing activities	$	(36,843	)		(64	)%	$	(101,395	)		0	%	$	(101,071	)
Cash flows (used in) provided by financing activities		(23,059	)		(167	)%		34,629			167	%		12,957
Net (decrease) increase in cash and cash equivalents	$	(7,168	)		(14	)%	$	(8,378	)		(216	)%	$	7,203

Working capital

At December 31, 2012, we had a working capital deficit of approximately $371.5 million. Our working capital deficit at December 31, 2011 and 2010 was approximately $3.3 million and $238.5 million, respectively. The 2012 deficiency was primarily due to the reclassification of the 2011 Credit Facility of approximately $115.0 million and the Notes of approximately $245.3 million to current.  See Note 2 to our consolidated financial statements, for further discussion of this deficiency and alternatives to resolve it. The 2011 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 2010 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 2012 were approximately $52.7 million, as compared to approximately $58.4 million in 2011, a decrease of approximately $5.7 million, or 10%. The decrease in net cash provided by operating activities from 2011 to 2012 was primarily due to approximately $5.5 million of lower revenues and higher operating costs of approximately $1.5 million, which decreased operating cash flow activities by approximately $7.0 million. This decrease was partially offset by working capital changes of approximately $1.6 million in 2012 compared to 2011.

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.

Analysis of cash flows used in investing activities

Cash flows used in investing activities in 2012 was approximately $36.8 million, compared to approximately $101.4 million in 2011, a $64.6 million decrease. The decrease is related to there being no acquisitions in 2012 compared to approximately $29.6 million in 2011 and a reduced drilling program in 2012 compared to 2011 of approximately $35.2 million.

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

Analysis of cash flows used in and provided by financing activities

Cash flows cash used in financing activities in 2012 was approximately $23.1 million as compared to approximately $34.6 million provided by financing activities in 2011, a change of approximately $57.7 million, or 167%. This change was primarily the result of paying down the 2011 Credit Facility in 2012 and the borrowings received in 2011 in connection with our 2011 Refinancing.

Cash flows 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.

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, NGL and natural gas wells, installing new production infrastructure and maintaining, repairing and enhancing existing oil, NGL 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, NGL 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, 2012, we spent approximately $32.5 million in capital expenditures to support our business plan. Of this amount, we spent approximately $16.0 million to drill or complete 16 gross (9.2 net) wells, of which 12 were successful, adding approximately 575 net Boe/d to our 2012 average daily production. We also recompleted or worked over approximately 102 gross (78.9 net) wells during 2012 at a capital cost of approximately $12.0 million and approximately $1.6 million was spent to plug and abandon wells. The remaining capital expenditures of approximately $2.9 million related primarily to seismic, facilities, vehicles and other items associated with operations.

For 2013, our capital program is approximately $33.4 million, which we believe is sufficient to maintain current operations. Our 2013 capital budget contemplates spending approximately $21.7 million in connection with the drilling of 24 additional wells, which include 12 operated and 12 non-operated. We also plan to spend approximately $6.7 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $5.0 million for other capital associated with operations, including geological, geophysical, leasing, seismic and plugging and abandonment.

Capital resources

Cash. As of December 31, 2012 and 2011, we had $2.2 million and $9.4 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. A borrowing base redetermination was conducted in October of 2012 which resulted in a reduction from $165 million to $135 million on a staggered basis over a six month period. The redetermination was effective starting November 1, 2012 and the borrowing base amount will reduce by $5.0 million per month for the following six months, ending at $135 million in April 2013. As of December 31, 2012 the borrowing base was $155 million. 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 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, NGL 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. The next redetermination date is May 2013.

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 1.84 as of December 31, 2012), minimum interest coverage ratio, as defined, of not less than 2.50 to 1.0 (which was 2.73 as of December 31, 2012), maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.25 to 1.0 (which was 4.13 as of December 31, 2012) and maximum secured leverage ratio, as defined, of secured debt balances as compared to EBITDA of not greater than 2.00 to 1.0 (which was 1.33 as of December 31, 2012). The maximum leverage ratio will reduce to 4.0 to 1.0 as of March 31, 2013 and all periods thereafter. Alternatives being considered include using cash flow from operations or 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.  The Company is also considering seeking a waiver or amendment to the 2011 Credit Facility and the Notes with respect to the maximum leverage ratio.

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Because the Company cannot provide assurances as to its ability to remain in compliance with its financial covenants at March 31, 2013, the Company received a going concern modification in the audit report from its independent registered public accounting firm for the year ended December 31, 2012. The 2011 Credit Facility provides that a going concern modification from an independent registered public accounting firm is a covenant breach. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of this covenant breach, the Company has classified approximately $115.0 million of borrowings under the Credit Facility and approximately $245.5 million of the Notes as current liabilities.  At December 31, 2012, this results in current liabilities exceeding current assets by approximately $371.5 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent the Company from borrowing additional funds under the 2011 Credit Facility.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about the Company’s ability to continue as a going concern.  The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty

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%and 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 $4.7 million at December 31, 2012.

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% 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

During 2012, natural gas prices have been highly volatile and have fallen to levels as low as $1.95/Mcf.  In this environment, we did not include operated natural gas drilling opportunities in our 2013 capital budget and continue to believe this is the prudent course of action. While natural gas prices have recovered somewhat from the lows experienced in the quarter ended June 30, 2012, we continue to focus all of our exploration and development efforts on developing additional oil weighted opportunities in our existing portfolio. This would include both workover/recompletions of existing wells and new prospects. Since approximately 59% of our current daily production is natural gas, and is subject to typical Gulf Coast annual declines of 20%, we believe there is a high likelihood of reduced annual production from our existing portfolio, as compared to our prior year performance.

We expect to fund our acquisition, exploration, 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, 2012, we had approximately $40.0 million of available borrowing capacity under our 2011 Credit Facility. See Note 2 to our consolidated financial statements, for further discussion on liquidity.

For the year ended December 31, 2012, we realized approximately $24.5 million in gains under our hedging agreements. Based on the NYMEX strip pricing for oil, NGL and natural gas as of December 31, 2012, we expect to realize approximately $0.5 million of hedging revenues during 2013.

For 2013, our capital program is approximately $33.4 million, which we believe is sufficient to maintain current operations. Our 2013 capital budget contemplates spending approximately $21.7 million in connection with the drilling of 24 additional wells, which include 12 operated and 12 non-operated and an expected average production of approximately 2.8 MMcfe/d. We also plan to spend approximately $6.7 million in connection with the workover and recompletion of existing wells. We have also budgeted approximately $5.0 million for other capital associated with operations, including geological, geophysical, leasing, seismic and plugging and abandonment.

The table below sets forth our 2013 capital budget.

	2013 Budget
Drilling	$	21.7
Acquisitions		—
Workovers and recompletions		6.7
Geological, geophysical, leasing and seismic		1.5
Plugging and abandonment		1.5
Facilities, vehicles and other		2.0
Total operations capital budget	$	33.4

The final determination with respect to our actual capital expenditures during 2013 will depend on a number of factors, including:

• our liquidity and the availability of financing;

• 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, NGL and natural gas companies;

43

• production from our existing producing wells;

• the results of our current exploration, exploitation and development drilling efforts;

• economic and industry conditions at the time of drilling; 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, 2012 and the effect those obligations are expected to have on our future cash flow and liquidity.

Contractual Obligations
	As of December 31, 2012
	Payments Due by Year
	Total		2013		2014		2015-2016		2017 and Thereafter
	(In thousands)
Debt:
2011 Credit Facility(1)	$	115,000	$	—	$	115,000	$	—	$	—
Notes(1),(2)		250,000		—		—		250,000		—
Total	$	365,000	$	—	$	115,000	$	250,000	$	—
Other Commitments:
Services(3)	$	1,868	$	1,168	$	700	$	—	$	—
Operating Leases(4)		8,769		1,879		1,879		3,758		1,253
Total	$	10,637	$	3,047	$	2,579	$	3,758	$	1,253
Interest:
2011 Credit Facility	$	9,900	$	5,400	$	4,500	$		$	—
Notes		87,779		26,250		26,250		35,279
Total	$	97,679	$	31,650	$	30,750	$	35,279	$
Total Commitments	$	473,316	$	34,697	$	148,329	$	289,037	$	1,253

(1)	Classified as current in financial statements due to the inability to comply with the 2011 Credit Facility maximum leverage ratio as of March 31, 2013. See Note 2 to our consolidated financial statements, for further discussion.
(2)	Includes $4.7 million of original issue discount that will become due upon maturity.
(3)	Consists of fees payable to an investment bank for advisory services related to acquisitions and a management consulting company.
(4)	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, NGL 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, NGL 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, NGL 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 8. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

44

Oil, NGL and natural gas Properties

Full Cost Accounting — We utilize the full cost method to account for our investment in oil, NGL 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, NGL 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, NGL and natural gas properties when incurred. Accordingly, we capitalize the cost to acquire, explore for and develop oil, NGL 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 $3.8 million, $4.5 million and $3.8 million of direct internal costs capitalized for the years ended December 31, 2012, 2011 and 2010, respectively.

Depreciation, Depletion, and Amortization — The cost of oil, NGL 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, NGL and natural gas reserves as estimated by independent engineering consultants. Our depletion rates for the years ended December 31, 2012, 2011 and 2010 were $18.94, $17.28 and $15.75 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, NGL 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 $14.6 million was recorded for the year ended December 31, 2012, an impairment of approximately $18.2 million was recorded for the year ended December 31, 2011 and no impairment was recorded for the year ended December 31, 2010. Given the nature of the ceiling test, and the low natural gas prices experienced during 2012 and into 2013, it is reasonably possible that we could have material impairments in the future.

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, NGL and natural gas revenues are recorded for the amount of oil, NGL 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, NGL 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, 2012 and 2011, we had recorded a liability of approximately $592,000 and $597,000, respectively.

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.

45

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.

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.

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.

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 13 — “Income Taxes” in our consolidated financial statements 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, NGL 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, NGL and natural gas properties.

Recently Issued Accounting Pronouncements

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”). 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 adopted this ASU effective January 1, 2012, and it has not had an impact on the Company’s consolidated financial statements other than requiring additional disclosures.

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 January 1, 2013, and interim periods within those annual periods. Retrospective application is required. The Company will adopt this standard effective January 1, 2013, and it is not expected to have an impact on the Company’s consolidated financial statements other than requiring additional disclosures.

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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, 2012, a 1% increase in interest rates would increase interest expense by approximately $1.2 million per year, based on our approximately $115.0 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, NGL and natural gas industry, and as such, we are directly affected by the economy of the industry. During 2012, ten customers collectively accounted for 78% of our oil, NGL and natural gas revenues and during 2011, ten customers collectively accounted for 70% of our oil, NGL and natural gas revenues. This concentration increases our credit risk. We seek to mitigate our credit risk by, among other things, monitoring customer creditworthiness.

Counterparty Risk

We have exposure to financial institutions in the form of derivative transactions in connection with our commodity 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 exploration, 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, NGL 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 2012 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 or vice versa. 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 2012 was $2.59 per Mcf, which was approximately 34% lower than the price of $3.93 per Mcf that we received during 2011. Natural gas prices in 2012 were dependent upon many factors including the balance between North American supply and demand.

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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 2012 and includes the type of derivative contract, the volume, the weighted average reference price for those volumes, and the associated gain/(loss) upon settlement. Oil contracts settle against NYMEX West Texas Intermediate prices, gas contracts settle against NYMEX Henry Hub prices and NGL contracts settle against Mont Belvieu OPIS prices.

	As of December 31, 2012
Oil collars
Volumes (Bbls)		1,104,910
Average floor price (per Bbl)	$	87.16
Average ceiling price (per Bbl)	$	96.85
Gain/(loss) upon settlement	$	749,135
Oil swaps
Volumes (Bbls)		255,181
Average swap price (per Bbl)	$	96.34
Gain/(loss) upon settlement	$	1,598,828
LLS-WTI Basis swaps
Volumes (Bbls)		336,800
Average swap price (per Bbl)	$	9.62
Gain/(loss) upon settlement	$	(2,984,796	)
Total oil gain/(loss) upon settlement	$	(636,833	)
Natural gas collars and three way costless collars
Volumes (Mcf)		7,305,840
Average floor price (per Mcf)	$	4.88
Average ceiling price (per Mcf)	$	5.13
Gain/(loss) upon settlement	$	11,483,716
Natural gas swaps
Volumes (Mcf)		8,651,649
Average swap price (per Mcf)	$	4.59
Gain/(loss) upon settlement	$	11,003,723
Total natural gas gain/(loss) upon settlement	$	22,487,439
NGL swaps
Volumes (Mcf)		419,501
Average swap price (per Mcf)	$	48.29
Gain/(loss) upon settlement	$	2,624,838
Total NGL gain/(loss) upon settlement	$	2,624,838
Total gain/(loss)	$	24,475,444

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The following derivatives contracts were in place as of December 31, 2012

Natural Gas	Type	MMbtu /Mo. or Avg. MMbtu / Mo.		Price / MMbtu
Jan-13 to Dec-13	Collar		90,000	$	3.50 – 5.75
Jan-14 to Dec-14	Swap		75,000	$	3.82
Jan-13 to Dec-14	Swap		100,000	$	3.79
Jan-13 to Dec-13	Swap		90,000	$	4.22
Jan-14 to Dec-14	swap		40,000	$	4.52

Crude Oil	Type	Bbl / Mo. or Avg. Bbl / Mo.		Price / Bbl
Jan-13 to Dec-13	Collar		8,000	$	92.00 -102.95
Jan-13 to Dec-13	Collar		11,000	$	80.00 -98.00
Jan-13 to Dec-13	Swap		4,559	$	83.00
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		19,000	$	80.00 -96.75

NGL	Type		Bbl / Mo. or Avg. Bbl / Mo.		Price / Bbl
Jan-13 to Dec-13		Swap		8,500	$	38.90
Jan-14 to Dec-14		Swap		7,100	$	38.24

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		52
CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2012 AND 2011, AND FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010:
Balance sheets		53
Statements of operations		55
Statements of changes in stockholders’ deficit		56
Statements of cash flows		57
Notes to consolidated financial statements		58
SUPPLEMENTAL DISCLOSURE ABOUT OIL & GAS PRODUCING ACTIVITIES		71

50

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, 2012 and 2011, and the related consolidated statements of operations, changes in stockholders' deficit, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company is not in compliance with certain covenants of its 2011 Credit Facility, and all of the Company’s indebtedness is classified within current liabilities as of December 31, 2012. The Company’s violation of its debt covenants, combined with its financing needs and negative working capital position, raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also discussed in Note 2 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 /s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 28, 2013

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MILAGRO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2012 AND 2011

	2012			2011
	(Amounts in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,188		$	9,356
Accounts receivable:
Oil, NGL and natural gas sales		19,728			22,288
Joint interest billings and other — net of allowance for doubtful accounts of $719 and $831 at December 31, 2012 and 2011, respectively		977			1,124
Derivative assets — current		873			11,405
Prepaid expenses and other		4,030			3,041
Total current assets		27,796			47,214
PROPERTY, PLANT AND EQUIPMENT:
Oil, NGL and natural gas properties — full cost method:
Proved properties		1,303,922			1,279,276
Unproved properties		14,971			14,914
Less accumulated depreciation, depletion and amortization		(877,754	)		(812,364	)
Net oil, NGL and natural gas properties		441,139			481,826
Other property and equipment — net of accumulated depreciation of $6,879 and $6,114 at December 31, 2012 and 2011, respectively		746			1,236
Net property, plant and equipment		441,885			483,062
DERIVATIVE ASSETS		68			6,875
OTHER ASSETS:
Deferred financing fees, net		5,850			7,856
Advance to affiliate		2,442			2,391
Other		2,719			6,379
Total other assets		11,011			16,626
TOTAL	$	480,760		$	553,777

See notes to consolidated financial statements.

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MILAGRO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2012 AND 2011

		2012			2011
		(Amounts in thousands)
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable	$	4,458		$	4,875
Accrued liabilities		27,374			33,185
Accrued interest payable		4,558			4,074
Derivative liabilities		799			5,186
Asset retirement obligation		1,882			3,199
Current debt		360,265			—
Total current liabilities		399,336			50,519
NONCURRENT LIABILITIES:
Long-term debt		—			381,879
Asset retirement obligation		35,626			41,441
Derivative liabilities		1,127			853
Other		1,777			3,931
Total noncurrent liabilities		38,530			428,104
Total liabilities		437,866			478,623
MEZZANINE EQUITY
Redeemable series A preferred stock (Note 11)		235,694			234,558
COMMITMENTS AND CONTINGENCIES (Note 14)
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, 2012 and 2011, respectively)		3			3
Additional paid-in-capital		(66,813	)		(66,813	)
Accumulated (deficit)		(125,990	)		(92,594	)
Total stockholders’ deficit		(192,800	)		(159,404	)
TOTAL	$	480,760		$	553,777

See notes to consolidated financial statements.

53

MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

	2012			2011			2010
	(Amounts in thousands)
REVENUES:
Oil, NGL and natural gas revenues	$	124,297		$	138,210		$	134,207
Gain on commodity derivatives		11,249			15,577			22,943
Total revenues		135,546			153,787			157,150
COSTS AND EXPENSES:
Gathering and transportation		1,610			1,472			1,282
Lease operating		36,448			35,152			34,283
Environmental remediation		—			1,988			—
Taxes other than income		11,732			9,939			10,904
Depreciation, depletion, and amortization		51,515			51,240			54,272
Full cost ceiling impairment		14,641			18,164			—
General and administrative		14,311			16,483			17,469
Accretion		3,696			3,205			2,627
Total costs and expenses		133,953			137,643			120,837
OTHER (INCOME) EXPENSE:
Net (gain) loss on interest rate derivatives		—			(1,854	)		2,127
Other income		(926	)		(555	)		(669	)
Interest and related expenses, net of amounts capitalized		35,915			41,100			48,021
Loss on extinguishment of debt		—			1,027			—
Total other expense		34,989			39,718			49,479
LOSS BEFORE INCOME TAX		(33,396	)		(23,574	)		(13,166	)
INCOME TAX EXPENSE		—			—			57,422
NET LOSS		(33,396	)		(23,574	)		(70,588	)
Preferred dividends		31,946			18,634			—
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$	(65,342	)	$	(42,208	)	$	(70,588	)

See notes to consolidated financial statements.

54

MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

	Common Stock
	Shares		Par Value		Additional Paid in Capital			Accumulated Deficit			Total Stockholder’s Deficit
BALANCE — December 31, 2009		280,400		3		(68,603	)		(1,568	)		(67,032	)
Net loss									(70,588	)		(70,588	)
Stock based compensation						1,788			—			1,788
Contributions						2			—			2
BALANCE — December 31, 2010		280,400		3					(69,020	)		(135,830	)
Net loss						(66,813	)		(23,574	)		(23,574	)
BALANCE — December 31, 2011		280,400		3		(66,813	)		(92,594	)		(159,404	)
Net loss						—			(33,396	)		(33,396	)
BALANCE — December 31, 2012		280,400	$	3	$	(66,813	)	$	(125,990	)	$	(192,800	)

See notes to consolidated financial statements.

55

MILAGRO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

	2012			2011			2010
	(Amounts in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(33,396	)	$	(23,574	)	$	(70,588	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		51,515			51,240			54,272
Full cost ceiling impairment		14,641			18,164			—
Amortization of deferred financing costs		2,006			1,924			1,752
Accretion of asset retirement obligation		3,696			3,205			2,627
Deferred income taxes		—			—			56,811
PIK note interest		—			9,801			29,003
Recapitalization of debt loss		1,137			1,136			1,135
Unrealized loss on commodity derivatives		13,226			396			16,412
Unrealized gain on interest rate derivatives		—			(3,510	)		(6,148	)
OID interest		1,386			924			—
Bad debt expense		267			328			—
Stock-based compensation expense		—			—			1,788
Loss on debt extinguishment		—			1,027			—
Changes in assets and liabilities — net of acquisitions:
Accounts receivable and accrued revenue		2,441			(2,730	)		(170	)
Prepaid expenses and other		(1,175	)		(308	)		(490	)
Accounts payable, accrued liabilities and other		(3,010	)		365			8,913
Net cash from operating activities		52,734			58,388			95,317
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil, NGL and natural gas properties		(37	)		(29,556	)		(66,194	)
Additions of oil, NGL and natural gas properties		(36,666	)		(72,085	)		(34,539	)
Additions of other property		(275	)		(196	)		(573	)
Proceeds from sale of oil, NGL and natural gas properties		135			442			235
Net cash from investing activities		(36,843	)		(101,395	)		(101,071	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		72,250			420,455			60,000
Payments of borrowings		(95,250	)		(376,479	)		(47,048	)
Deferred financing costs paid		—			(9,193	)		—
Other		(59	)		(154	)		3
Capital contributions		—			—			2
Net cash from financing activities		(23,059	)		34,629			12,957
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS		(7,168	)		(8,378	)		7,203
CASH AND CASH EQUIVALENTS — Beginning of year		9,356			17,734			10,531
CASH AND CASH EQUIVALENTS — End of year	$	2,188		$	9,356		$	17,734
INCOME TAX PAID — Net of refunds	$	—		$	—		$	—
INTEREST PAID — Net of interest capitalized of $1,038, $1,199, and $2,391 in 2012, 2011, and 2010, respectively	$	30,443		$	24,736		$	11,358
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Acquisition:
Acquisitions of other assets and liabilities — net	$	—		$	1,370		$	(750	)
Recapitalization:
Issuance of series A preferred stock	$	—		$	—		$	198,712
Interest paid in kind — series A preferred stock	$	—		$	9,801		$	23,783
Forgiveness of forbearance fee	$	—		$	—		$	4,000
Settlement of second lien debt	$	—		$	—		$	(194,712	)
Interest paid in kind — second lien	$	—		$	—		$	5,220
Interest and fees converted to debt	$	—		$	—		$	21,960
Accrued capital and seismic costs included in proved properties	$	2,659		$	3,696		$	5,604
Asset retirement obligations incurred	$	717		$	2,142		$	3,359

See notes to consolidated financial statements.

56

MILAGRO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

1. ORGANIZATION

Milagro Oil & Gas, Inc. (the “Company” or “Milagro”) is an independent oil, NGL and natural gas exploration and production company. The Company was organized as a Delaware limited liability company on November 30, 2007. The Company owns 100% of Milagro Exploration, LLC, Milagro Resources, LLC, Milagro Producing, LLC and Milagro Mid-Continent, LLC and is a subsidiary of Milagro Holdings, LLC (“Parent”). Each of these subsidiaries is included in the consolidated financial statements. All intercompany accounts and transactions are eliminated in consolidation.

Milagro’s historic geographic focus has been along the onshore Gulf Coast area, primarily in Texas, Louisiana and Mississippi. The Company operates a significant portfolio of oil, natural gas liquids (“NGL”) and natural gas producing properties and mineral interests in this region and has expanded its footprint through the acquisition and development of additional producing or prospective properties in North Texas and Western Oklahoma.

2. LIQUIDITY AND GOING CONCERN

The Company currently has indebtedness outstanding under the 2011 Credit Facility, which contains customary financial and other covenants.   The maximum leverage ratio, as defined, of debt balances as compared to EBITDA is required to be not greater than 4.25 to 1.0, which was 4.13 as of December 31, 2012. The maximum leverage ratio will reduce to 4.0 to 1.0 as of March 31, 2013 and all periods thereafter.

The Company is currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio at March 31, 2013. Alternatives being considered include using cash flow from operations or 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.  The Company is also considering seeking a waiver or amendment to the 2011 Credit Facility and the Notes with respect to the maximum leverage ratio.

Because the Company cannot provide assurances as to its ability to remain in compliance with its financial covenants at March 31, 2013, the Company received a going concern modification in the audit report from its independent registered public accounting firm for the year ended December 31, 2012. The 2011 Credit Facility provides that a going concern modification from an independent registered public accounting firm is a covenant breach. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of this covenant breach, the Company has classified approximately $115.0 million of borrowings under the Credit Facility and approximately $245.5 million of the Notes as current liabilities.  At December 31, 2012, this results in current liabilities exceeding current assets by approximately $371.5 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent the Company from borrowing additional funds under the 2011 Credit Facility.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about the Company’s ability to continue as a going concern.  The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

3. ACQUISITIONS

Management considers the most significant fair value estimates associated with acquisitions to be proved oil, NGL and natural gas properties. The fair value of proved properties was estimated utilizing the value of underlying oil, NGL and natural gas reserves as of the transaction date. The acquisitions are accounted for using the acquisition method of accounting

NEWFIELD — On September 29, 2011, the Company completed the acquisition of certain Texas Gulf Coast and South Texas assets from Newfield Exploration Company, for a purchase price of $28.0 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction include producing wells in Goliad and Hidalgo Counties, Texas. The estimated fair values of the assets acquired and liabilities assumed were oil, NGL and natural gas properties of $26.8 million, asset retirement obligations of $1.9 million and other liabilities of $164,000. The acquisition was funded with cash on hand and proceeds from borrowings.

RAM — On December 8, 2010, the Company completed the acquisition of certain North Texas assets from RWG Energy, Inc., a wholly-owned subsidiary of RAM Energy Resources, Inc., for a purchase price of $43.75 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction include producing wells in Jack and Wise Counties, Texas. The estimated fair values of the assets acquired and liabilities assumed were oil, NGL and natural gas properties of $44.5 million, other assets of $91,000, and asset retirement obligations of $766,000 and other liabilities of $2.4 million. The acquisition was funded with cash on hand and proceeds from borrowings. In 2011, the Company completed the remediation activities contemplated at the time of acquisition, which resulted in a $1.5 million reduction of other liabilities and oil, NGL and natural gas properties.

Venoco — On May 14, 2010, the Company completed the acquisition of certain Gulf Coast assets of TexCal Energy South Texas, L.P., a subsidiary of Venoco, Inc., for a purchase price of $24.0 million, subject to normal and customary purchase price adjustments. The assets acquired in the transaction included producing wells in various counties along the Texas Gulf Coast. The estimated fair values of the assets acquired and liabilities assumed were oil, NGL and natural gas properties of $22.4 million, other assets of $34,000, and asset retirement obligations of $1.8 million and other liabilities of $0.5 million. The acquisition was funded with proceeds from borrowings.

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The following table reflects pro forma oil, NGL and natural gas revenues and net loss for the year ended December 31, 2010 as if these acquisitions had taken place on January 1, 2010.  These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

	2010
	(Unaudited)
Oil, natural gas and NGL revenues	$	144,864
(Net loss)/income		(62,461	)

Actual oil, natural gas and NGL revenues and net income before taxes recorded in 2010 from the acquisitions were approximately $6.3 million and $3.6 million, respectively.

4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates — The preparation of the Company’s consolidated financial statements in conformity with U.S. GAAP requires the Company’s 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, NGL 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, NGL 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, NGL 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 8. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

Oil, NGL and natural gas Properties:

Full Cost Accounting — The Company utilizes the full cost method to account for its investment in oil, NGL 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, NGL 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, NGL and natural gas properties when incurred. Accordingly, we capitalize the cost to acquire, explore for and develop oil, NGL 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 $3.8 million, $4.5 million and $3.8 million of direct internal costs capitalized for the years ended December 31, 2012, 2011 and 2010, respectively.

Depreciation, Depletion, and Amortization — The cost of oil, NGL 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, NGL and natural gas reserves as estimated by independent engineering consultants. The Company’s depletion rates for the years ended December 31, 2012, 2011 and 2010 were $18.94, $17.28 and $15.75 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, NGL 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 $14.6 million was recorded for the year ended December 31, 2012, an impairment of approximately $18.1 million was recorded for the year ended December 31, 2011 and no impairment was recorded for the year ended December 31, 2010. Given the nature of the ceiling test, and the low natural gas prices experienced during 2012 and into 2013, it is reasonably possible that we could have material impairments in the future.

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.

The Company assesses all items classified as unproved property on a quarterly basis for possible impairment or reduction in value. The Company assesses 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.

Sales of Properties — Dispositions of oil, NGL and natural gas properties held in the full cost pool are recorded as adjustments to net capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

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Other Property, Plant and Equipment — Other operating property and equipment are stated at cost. The provision for depreciation is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold or otherwise disposed of and the related accumulated depreciation or amortization is removed from the accounts, and any gains or losses are reflected in current operations.

Revenue Recognition and Natural Gas Imbalances — Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer. The Company uses the sales method of accounting for revenue. Under this method, oil, NGL and natural gas revenues are recorded for the amount of oil, NGL and natural gas production sold to purchasers. Natural gas imbalances are created when the sales amount is not equal to the Company’s entitled share of production. The Company’s entitled share is calculated as gross production from the property multiplied by the Company’s net revenue interest in the property. No provision is made for an imbalance unless the oil, NGL 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, 2012 and 2011, the Company had recorded a liability of approximately $592,000 and $597,000, respectively.

Accounts Receivable —Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGL or from reimbursable expenses billed to the other participants in oil, natural gas and NGL wells for which the Company serves as operator. Oil, natural gas and NGL sales are generally unsecured.

As is common industry practice, collateral or other security is generally not required as a condition of sale; rather, the Company relies on credit approval, balance limitation, and monitoring procedures to control the credit approval on accounts receivable. The Company also grants credit to joint owners of oil, NGL and natural gas properties, which the Company operates through its subsidiaries. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from all customers for collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. As of December 31, 2012 and December 31, 2011, the Company had allowances of approximately $0.7 million and $0.8 million, respectively. There were no significant write-offs of receivables for the years ended December 31, 2012 or the year ended December 31, 2011 and no significant bad debt expense recorded for the same periods.

Prepaid Expenses — The Company will occasionally prepay certain costs that may include insurance, maintenance agreements or rent. These costs are then amortized or expensed in the period the work or service is performed. As of December 31, 2012 and December 31, 2011, the Company had prepaid expenses of approximately $2.9 million and $1.9 million, respectively, primarily related to insurance.

Other — The Company is required to make advances to operators for costs incurred on a day-to-day basis to develop and operate ventures in which the Company has an ownership interest. These advances totaled approximately $0.8 million and $0.2 million for December 31, 2012 and December 31, 2011, respectively. Such costs are capitalized to the full cost pool at the time the operator develops the properties. Other assets included a prepaid escrow of approximately $0.2 million and $0.7 million as of both December 31, 2012 and 2011, respectively.

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.

The Company routinely assesses the realizability of its 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.

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 is utilized.

The Company’s policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in its 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.

The 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 Parent, and has not been recognized in the Company’s financial statements. There are no income tax sharing agreements between Parent and the Company

See Note 13 — “Income Taxes” for further information.

Cash and Cash Equivalents — The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents are maintained with major financial institutions and such deposits may exceed the amount of federally backed insurance provided. While the Company regularly monitors the financial stability of such institutions, cash and cash equivalents ultimately remain at risk subject to the financial viability of such institutions.

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Derivative Financial Instruments — The Company utilizes 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, NGL 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.

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

Deferred Financing Fees — The Company capitalizes 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.

Asset Retirement Obligation — The Company records a liability for the estimated fair value of its asset retirement obligations, primarily comprised of its 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, NGL and natural gas properties.

Stock-Based Compensation — The Company estimates the fair value of stock-based compensation provided to employees. When and if issued, the Company estimates the fair value of stock-based compensation at the grant date, and recognizes compensation expense over the period that the employees provide the required service. No new grants of stock-based compensation were provided by the Company in any period presented and stock-based compensation recognized during 2010 represents amortization of previous grants over the initial vesting period.

Recently Issued Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update (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 adopted this ASU effective January 1, 2012, and it has not had an impact on the Company’s consolidated financial statements other than requiring additional disclosures.

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 January 1, 2013, and interim periods within those annual periods. Retrospective application is required. The Company will adopt this standard effective January 1, 2013, and it is not expected to have an impact on the Company’s consolidated financial statements other than requiring additional disclosures.

5. CONCENTRATION OF CREDIT RISK

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of temporary cash investments, trade accounts receivable and derivative financial instruments.

The Company’s receivables relate to customers in the oil, NGL and natural gas industry, and as such, the Company is directly affected by the health of the industry. The credit risk associated with the receivables is mitigated by monitoring customer creditworthiness.

For the years ended December 31, 2012, 2011 and 2010, the Company’s most significant customers by total revenues of oil, NGL and natural gas  were as follows:

	2012			2011			2010
Shell Trading (US) Company		21	%		17	%		19	%
Enterprise Crude Oil, LLC		20			16			11
Conoco		9			9			—
Plains Marketing, L.P.		9			7			6
Smaller customers		41			51			64

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6. ASSET RETIREMENT OBLIGATION

In general, the amount of an asset retirement obligation (“ARO”) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using a credit-adjusted risk-free rate.

Activity related to the ARO liability for the years ended December 31, 2012, 2011 and 2010 is as follows (in thousands):

Liability for asset retirement obligation — December 31, 2010	$	40,271
Liabilities settled and divested		(2,137	)
Liabilities incurred		2,142
Revisions to cash flow estimates		1,159
Accretion expense		3,205
Liability for asset retirement obligation — December 31, 2011	$	44,640
Liabilities settled and divested		(3,342	)
Liabilities incurred		717
Revisions to cash flow estimates		(8,203	)
Accretion expense		3,696
Liability for asset retirement obligation — December 31, 2012	$	37,508

The liability comprises a current balance of approximately $1.9 million and $3.2 million and a noncurrent balance of approximately $35.6 million and $41.4 million as of December 31, 2012 and 2011, respectively.

Revisions to asset retirement obligations reflect changes in abandonment cost estimates, and reserve lives based on current information and considering the Company’s current plans.

7. DERIVATIVE FINANCIAL INSTRUMENTS

The Company produces and sells oil, NGL and natural gas. As a result, its operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. The Company periodically seeks to reduce its exposure to price volatility for a portion of its production by entering into swaps, options and other commodity derivative financial instruments. A combination of options, structured as a zero-cost collar, is the Company’s preferred derivative instrument because there are no up-front costs and the instrument sets a floor price for a portion of the Company’s hydrocarbon production. Such derivatives provide assurance that the Company receives NYMEX prices no lower than the price floor and no higher than the price ceiling. Our commodity derivatives 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. For the year ended December 31, 2012, the Company had commodity derivatives in place for 2.0 MMBoe, or approximately 77% of production, in the form of oil, NGL and natural gas collars and swaps. Oil contracts settle against NYMEX West Texas Intermediate (WTI) prices, gas contracts settle against NYMEX Henry Hub prices and NGL contracts settle against Mont Belvieu OPIS prices.

As of December 31, 2012, the Company has approximately 1.0 MMBOE of production hedged for 2013 which is approximately 33% of projected production.

Periodically the Company evaluates the unrealized commodity derivatives to determine if it would be beneficial to liquidate any contracts early. During 2012, the Company liquidated multiple commodity contracts early realizing approximately $15.1 million in realized derivative revenues.  

During 2012, the Company entered into basis swaps which allow the Company to manage risks against fluctuations in the price difference between Louisiana Light Sweet (“LLS”) Crude and WTI prices. All LLS related derivative contracts expired in December 2012. These volumes are disclosed as oil commodity derivative volumes. As of December 31, 2012, the Company was producing approximately 1,800 barrels per day of LLS crude and receives a premium price over the WTI price. The basis swap volumes are not included in the percent of production volumes under commodity derivative contracts as described above.

The Company has also entered into swaption derivative contracts which give the counterparty the right, for a period of time, to execute a natural gas price swap contract in exchange for a premium paid to the Company. Should the counterparty elect not to execute the swap contract by the due date, the option to do so will terminate and there is no further financial exposure to either party. The contingent volumes associated with these contracts are not included in the calculation for percent of production volumes under commodity derivative contracts.

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All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value of all derivative financial instruments in the consolidated balance sheets as of December 31, 2012 and 2011 (in thousands):

		Fair Value
Description	Location in Balance Sheet	2012		2011
Asset derivatives:
Natural gas collars and swaps — current portion	Derivative assets	$	836	$	11,405
Noncurrent portion	Derivative assets		68		5,897
Oil collars and swaps — current portion	Derivative assets		37		—
Noncurrent portion	Derivative assets		—		978
		$	941	$	18,280
Liability derivatives:
Oil collars and swaps — current portion	Derivative liabilities	$	590	$	4,677
Noncurrent portion	Derivative liabilities		550		—
Gas collars and swaps — current portion	Derivative liabilities		179		—
Noncurrent portion	Derivative liabilities		470		—
NGL collars and swaps — current portion	Derivative liabilities		30		509
Noncurrent portion	Derivative liabilities		107		853
		$	1,926	$	6,039

The following table summarizes the locations and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations:

Description	Location in Statements of Operations	2012			2011			2010
Commodity contracts:
Realized gain on commodity contracts	Gain on commodity derivatives	$	24,475		$	15,973		$	39,355
Unrealized loss on commodity contracts	Gain on commodity derivatives		(13,226	)		(396	)		(16,412	)
Total net gain on commodity contracts			11,249			15,577			22,943
Interest rate swaps:
Realized loss on interest rate swaps	Net loss on interest rate derivatives		—			(1,656	)		(8,275	)
Unrealized gain (loss) on interest rate swaps	Net loss on interest rate derivatives		—			3,510			6,148
Total net gain (loss) on interest rate swaps			—			1,854			(2,127	)
Total net gain on derivative contracts		$	11,249		$	17,431		$	20,816

At December 31, 2012, the Company had the following natural gas collar positions:

	Collars
			Floors		Ceilings
Period	Volume in MMbtu’s		Price		Price
January 2013 — December 2013		1,080,000	$	3.50	$	5.75

At December 31, 2012, the Company had the following natural gas swap positions:

	Swaps
Period	Volume in MMbtu’s		Price Range			Weighted- Average Price
January 2013 — December 2013		2,280,000	$3.65	-	4.22	$	3.92
January 2014 — December 2014		2,580,000	$3.82	-	4.52	$	4.00

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At December 31, 2012, the Company had the following unexecuted natural gas swaption positions:

	Swaptions
Period	Volume in MMbtu’s		Price Range			Weighted- Average Price
January 2014 — December 2014		2,280,000	$4.22	-	4.66	$	4.45
January 2015 — December 2015		1,380,000	$4.52	-	4.99	$	4.83

At December 31, 2012, the Company had the following crude oil collar positions:

	Collars
			Floors			Weighted-		Ceilings			Weighted-
	Volume in		Price Range/			Average		Price Range/			Average
Period	Bbl’s		Price			Price		Price			Price
January 2013 — December 2013		228,000	$80.00	-	92.00	$	85.05	$98.00	-	102.95	$	100.08
January 2014 — December 2014		228,000		$80.00		$	80.00		$96.75		$	96.75

At December 31, 2012, the Company had the following crude oil swap positions:

	Swaps
Period	Volume in Bbl’s		Price Range			Weighted- Average Price
January 2013 — December 2013		78,703	$83.00	-	91.50	$	85.52
January 2014 — December 2014		24,000	$91.00	-	91.50	$	91.25

At December 31, 2012, the Company had the following NGL swap positions:

	Swaps
Period	Volume in BBl’s		Price
January 2013—December 2013		102,000	$	38.90
January 2014—December 2014		85,200	$	38.24

As of December 31, 2012, the Company had no active interest rate collar positions.

8. FAIR VALUES OF FINANCIAL INSTRUMENTS

The table below presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and December 31, 2011, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

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In general, fair values determined by Level 1 inputs utilize quoted prices (unadjusted) in active markets the Company has the ability to access for identical assets or liabilities. Fair values determined by Level 2 inputs utilize inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar assets and liabilities in active markets and inputs other than quoted prices observable for the asset or liability, such as interest rates and yield curves observable at commonly quoted intervals. Level 3 inputs are unobservable inputs for the asset or liability and include situations where there is little, if any, market activity for the asset or liability. In instances in which the inputs used to measure fair value may fall into different levels of the fair value hierarchy, the level in the fair value hierarchy within which the fair value measurement in its entirety has been determined is based on the lowest level input significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Disclosures concerning financial assets and liabilities measured at fair value are as follows:

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Quoted Once in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Reclassification (a)			Total Balance
December 31, 2012:
Current Assets
Commodity derivatives — natural gas	$	—	$	853	$	—	$	(17	)	$	836
Commodity derivatives — oil		—		614		—		(577	)		37
Commodity derivatives — NGL		—		—		—		—			—
Non-Current Assets
Commodity derivatives — natural gas	$	—	$	68	$	—	$	—		$	68
Commodity derivatives — oil		—		—		—		—			—
Commodity derivatives — NGL		—		—		—		—			—
Current Liabilities
Commodity derivatives — natural gas	$	—	$	196	$	—	$	(17	)	$	179
Commodity derivatives — oil		—		1,167		—		(577	)		590
Commodity derivatives — NGL		—		30		—		—			30
Non-Current Liabilities
Commodity derivatives — natural gas	$	—	$	470	$	—	$	—		$	470
Commodity derivatives — oil		—		550		—		—			550
Commodity derivatives — NGL		—		107		—		—			107
December 31, 2011:
Current Assets
Commodity derivatives — natural gas	$	—	$	11,635	$	—	$	(230	)	$	11,405
Commodity derivatives — oil		—		1,750		—		(1,750	)		—
Commodity derivatives — NGL		—		1,555		—		(1,555	)		—
Non-Current Assets
Commodity derivatives — natural gas	$	—	$	6,920	$	—	$	(1,023	)	$	5,897
Commodity derivatives — oil		—		7,967		—		(6,989	)		978
Commodity derivatives — NGL		—		1,773		—		(1,773	)		—
Current Liabilities
Commodity derivatives — natural gas	$	—	$	230	$	—	$	(230	)	$	—
Commodity derivatives — oil		—		6,427		—		(1,750	)		4,677
Commodity derivatives — NGL		—		2,064		—		(1,555	)		509
Non-Current Liabilities
Commodity derivatives — natural gas	$	—	$	1,023	$	—	$	(1,023	)	$	—
Commodity derivatives — oil		—		6,989		—		(6,989	)		—
Commodity derivatives — NGL		—		2,626		—		(1,773	)		853

(a) Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation due to netting of certain contracts with right of offset.

To obtain fair values, observable market prices are used if available. In some instances, observable market prices are not readily available for certain financial instruments and fair value is determined using present value or other techniques appropriate for a particular financial instrument using observable inputs (such as forward commodity price and interest rate curves). These techniques involve some degree of judgment and as a result are not necessarily indicative of the amounts the Company would realize in a current market exchange. The use of different assumptions or estimation techniques may have a material effect on the estimated fair value amounts.

Derivative Financial Instruments — The majority of the inputs used to value the Company’s derivatives fall within Level 2 of the fair value hierarchy; however, the credit valuation adjustments associated with these derivatives utilize Level 3 inputs, such as estimates of current credit spreads to evaluate the likelihood of nonperformance. As of December 31, 2012 and December 31, 2011, the impact of the credit valuation adjustments on the overall valuation of the Company derivative positions is not significant. As a result, derivative valuations in their entirety are classified in Level 2 of the fair value hierarchy. The fair value is estimated using the discounted cash flow model (based on weighted average component of each counterparty’s default swap).

Debt Instruments — The 2011 Credit Facility (as defined in Note 9) accrues interest on a variable-rate basis. The fair value of the 2011 Credit Facility is characterized as a Level 3 measurement in the fair value hierarchy. The Notes (as defined in Note 8) accrue interest on a fixed rate basis. The fair value of the Notes is characterized as a Level 2 measurement in the fair value hierarchy, as the trading volume is limited. As of December 31, 2012, the fair value of the 2011 Credit Facility was estimated using the discounted cash flow model under the income approach (based on comparable market rate credit spreads observable from market data) to approximate carrying value. As of the same date, the fair value of the Notes was estimated using the market approach (based upon our December 2012 weighted average market price) to be approximately $185 million. As of December 31, 2011, the Company estimated the 2011 Credit Facility fair value to be approximately $132.8 million. As of the same date, the fair value of the Notes was estimated to be approximately $200.8 million.

Cash and Cash Equivalents, Trade Receivables, and Payables — The fair value approximates carrying value given the short-term nature of these investments.

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9. DEBT

The Company’s debt as of December 31, 2012 and 2011 was comprised of the following amounts (in thousands):

	December 31, 2012			December 31, 2011
First lien Indebtedness — current	$	115,000		$	—
First lien Indebtedness — non-current		—			138,000
Notes — current		250,000			—
Notes — non-current		—			250,000
Unamortized discount — current		(4,735	)		—
Unamortized discount — non-current		—			(6,121	)
Total debt	$	360,265		$	381,879

Scheduled maturities by fiscal year are as follows (amounts in thousands):

Years Ending December 31
2013	$	—
2014 (1)		115,000
2015		—
2016 (1)		250,000
2017		—
	$	365,000

(1) Classified as current in financial statements due to the inability to comply with the 2011 Credit Facility maximum leverage ratio as of March 31, 2013. See Note 2 for further discussion.

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250 million of the Notes. We used the proceeds of this offering, together with borrowings under First Lien Agreement, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”). The weighted average interest rate at December 31, 2012 was 8.36% as compared to the weighted average interest rate at December 31, 2011 of 8.13%.

First Lien Credit — During 2011, the Company entered into a $300 million Amended and Restated First Lien Credit Agreement (“2011 Credit Facility”) that matures in November 2014. The 2011 Credit Facility includes a $10.0 million sub facility for standby letters of credit, of which approximately $1.3 million has been issued as of December 31, 2012, and a discretionary swing line subfacility of $5.0 million with semi-annual re-determinations. A borrowing base redetermination was conducted in October of 2012 which resulted in a reduction from $165 million to $135 million on a staggered basis over a six month period. The redetermination was effective starting November 1, 2012 and the borrowing base amount will reduce by $5.0 million per month for the following six months, ending at $135 million in April 2013. As of December 31, 2012 the borrowing base was $155 million. Amounts outstanding under the 2011 Credit Facility bear interest at specified margins over LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the Alternate Base Rate (ABR) of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. As of December 31, 2012, the LIBOR based interest rates ranged from 3.76% to 3.87% and the ABR interest rate was 5.75%. Borrowings under the 2011 Credit Facility are secured by all of the Company’s oil, NGL 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.

The Company currently has indebtedness outstanding under the 2011 Credit Facility, which contains customary financial and other covenants.   The maximum leverage ratio, as defined, of debt balances as compared to EBITDA is required to be not greater than 4.25 to 1.0, which was 4.13 as of December 31, 2012. The maximum leverage ratio will reduce to 4.0 to 1.0 as of March 31, 2013 and all periods thereafter.

The Company is currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio at March 31, 2013. Alternatives being considered include using cash flow from operations or 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.  The Company is also considering seeking a waiver or amendment to the 2011 Credit Facility and the Notes with respect to the maximum leverage ratio.

Because the Company cannot provide assurances as to its ability to remain in compliance with its financial covenants at March 31, 2013, the Company received a going concern modification in the audit report from its independent registered public accounting firm for the year ended December 31, 2012. The 2011 Credit Facility provides that a going concern modification from an independent registered public accounting firm is a covenant breach. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of this covenant breach, the Company has classified approximately $115.0 million of borrowings under the Credit Facility and approximately $245.5 million of the Notes as current liabilities.  At December 31, 2012, this results in current liabilities exceeding current assets by approximately $371.5 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent the Company from borrowing additional funds under the 2011 Credit Facility.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about the Company’s ability to continue as a going concern.  The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

Capitalization of Debt Costs — The Company capitalizes 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. As of December 31, 2012 and December 31, 2011, the Company had deferred financing fees of $5.9 million and $7.9 million, respectively.

The Company capitalizes a portion of its interest expense incurred during the period related to assets that have been excluded from the amortization pool. For the years ended December 31, 2012, 2011 and 2010, the Company capitalized interest of $1.0 million, $1.2 million and $2.4 million, respectively.

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Senior Secured Second Lien Notes — As part of the 2011 Refinancing, the Company issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7 million (the “Notes”). The Notes carry a stated 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 of the Company. The outstanding balance of the Notes is presented net of unamortized discount at December 31, 2012.

The Notes contain an optional redemption provision allowing the Company 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 the Company 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 the Company’s ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay any 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.

10. GUARANTOR AND NON-GUARANTOR

The Company is not required to disclose condensed consolidating financial information as the parent company has no independent assets or operations and owns 100% of each of the Borrowers, Milagro Resources, LLC and Milagro Mid-Continent, LLC. The subsidiary guarantees are full and unconditional guarantees of the Company’s outstanding debt on a joint and several basis. There are no non-guarantor subsidiaries. These subsidiaries are included in the consolidated financial statements.

11. MEZZANINE EQUITY

The Company’s Series A Preferred Stock (the “Series A”) is a perpetual instrument and provides the holders with an option to redeem the preferred shares and requires two-thirds (2/3) of the holders to request redemption, 180 days after the maturity of certain qualified debt which matures in 2016, with the redemption date being not more than 90 days after receiving the redemption request. Therefore, the Series A is classified as mezzanine equity. The Series A consists of 2,700,000 shares issued at $76.12 per share.

The holders of the Series A shall be entitled to receive dividends on a cumulative basis. Dividends shall accrue, whether declared or not, semi-annually at a 12% rate. Accrued dividends shall be paid in kind when, and if declared by the Company’s board of directors and shall be made by issuing an amount of additional shares of Series A, based on the original issue price. As of December 31, 2012 the dividends in arrears were approximately $50.6 million.

The fair value of the Series A is characterized as Level 3 measurements in the fair value hierarchy. The fair value is estimated using the discounted future cash flow method under the income approach. Future cash flows were estimated based on future accrued dividends and repayment of the Series A at par value. The discount rate is based on analysis of market yields and company specific risks. The estimated fair value of the Series A at December 31, 2012 and at December 31, 2011 was approximately $218 million and $183 million, respectively.

12. COMMON STOCK

The Company is authorized to issue up to 1,000,000 shares of Common Stock, par value $0.01 per share. As of December 31, 2012 and 2011, 280,400 shares of Common Stock were issued and outstanding and held by Parent. Holders of Common Stock are entitled to, in the event of liquidation, to share ratably in the distribution of assets remaining after payment of liabilities. Holders of Common Stock have no cumulative rights. Holders of Common Stock have no preemptive or other rights to subscribe for shares. Holders of Common Stock are entitled to such dividends as may be declared by the board of directors of the Company out of funds legally available therefore. The Company has never paid cash dividends on the Common Stock and does not anticipate paying any cash dividends in the foreseeable future.

13. INCOME TAXES

The income tax expense in the Company’s consolidated statements of operations consisted of the following:

	2012		2011		2010
Current Income Tax Expense
Federal	$	—	$	—	$	—
State	$	—	$	—	$	—
Deferred Income Tax Expense
Federal	$	—	$	—	$	54,854
State	$	—		—		2,568
	$	—	$	—	$	57,422

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The differences between income taxes computed using the statutory federal income tax rate and that shown in the statement of operations are summarized as follows:

	For Years Ended December 31,
	2012			2011			2010
Income Items	Estimated Tax (Benefit)/ Expense			Estimated Tax (Benefit)/ Expense			Estimated Tax (Benefit)/ Expense
Income tax expense (benefit) at federal statutory rate	$	(11,688	)	$	(8,248	)	$	(4,608	)
Adjustments:
Effect of flow-through entity		—			—			—
Accrued Dividend on Series A Preferred Shares		—			3,430			8,324
State Income tax net of fed tax		(148	)		(95	)		1,807
Income Taxes Related to Prior Periods		6			3			(6,090	)
Adjustment to Deferred Asset at Conversion		—			—			—
Non-Deductible/Non-Taxable Items		14			16			(276	)
Establish deferred tax asset at conversion		—			—			—
Valuation Allowance		11,816			4,894			58,265
Total Tax Expense	$	—		$	—		$	57,422

Significant components of the Company’s deferred tax assets as of December 31, 2012 and 2011 are as follows:

	2012						2011
	FED			State			FED			State
Current Deferred Tax Assets
Accrued Interest Payable	$	217		$	4		$	217		$	4
Accrued Liabilities & Other		3,405			67			4,252			84
Less: Valuation Allowance		(3,596	)		(70	)		(4,258	)		(84	)
Total Current Deferred Tax Asset	$	26		$	1		$	211		$	4
Non-Current Deferred Tax Assets
Oil & Gas Properties Basis Differences	$	33,897		$	669		$	25,920		$	512
Deferred Financing Costs		4,186			83			3,511			69
Abandonment Liability		12,469			246			14,504			286
Derivative Financial Instruments		371			7			—			—
Net Operating Loss Carryforward		34,995			691			33,746			666
Other		19			—
Less: Valuation Allowance		(85,937	)		(1,696	)		(73,606	)		(1,449	)
Total Non-Current Deferred Tax Asset	$	—		$	—		$	4,075		$	84
Current Deferred Tax Liability
Derivative Financial Instruments		(26	)		(1	)		(2,178	)		(46	)
Total Current Deferred Tax Liability	$	(26	)	$	(1	)	$	(2,178	)	$	(46	)
Non-Current Deferred Tax Liability
Derivative Financial Instruments		—			—			(2,108	)		(42	)
Total Non-Current Deferred Tax Liability	$	—		$	—		$	(2,108	)	$	(42	)

As of December 31, 2012, we had no unrecognized tax benefits. 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, 2013.

As a result of the conversion to a corporation on August 1, 2009, which pursuant to Sec. 351 of the Internal Revenue Code, was 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, from 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.

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In determining the carrying value of a deferred tax asset, accounting standards provide for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As the Company has incurred net operating losses in all years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, we have reduced the carrying value of our net deferred tax asset to zero. The valuation allowance has no impact on our NOL position for tax purposes, and if we generate taxable income in future periods, we will be able to use the NOL’s to offset taxes due at that time. The tax asset related to the NOLs of $34.9 million will begin to expire in 2029. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future tax periods.

14. COMMITMENTS AND CONTINGENCIES

Commitments — The Company leases corporate office space in Houston, Texas. Rental expense was approximately $1.8 million, $1.8 million and $2.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

In 2012, a Consulting Agreement was entered into with Sequitur Energy Management II, LLC, for management services at a fixed fee of $1.75 million to be performed in 2012 and 2013. The fixed fee shall be paid in 12 monthly installments during the term of this agreement.

In 2009, the Company entered into a contract with an investment bank for advisory services to be provided in 2010 for guaranteed fees of $1.0 million, this contract has been extended to 2014.  The Company paid $0.3 million in fees out of the $1.0 million to the investment bank in connection with the 2011 Refinancing.

The following table summarizes the Company’s contractual obligations and commitments at December 31, 2012, by fiscal year (amounts in thousands):

	2013		2014		2015		2016		2017		Thereafter		Total
Office lease	$	1,879	$	1,879	$	1,879	$	1,879	$	1,253	$	—	$	8,769
Management consulting agreement	$	1,168	$	—	$	—	$	—	$	—	$	—	$	1,168
Other		—		700		—		—		—		—		700

Contingencies — There are currently various suits and claims pending against the Company that have arisen in the ordinary course of the Company’s business, including contract disputes, property damage claims 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 the Company’s consolidated financial position, results of operations or cash flow. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

15. EMPLOYEE BENEFIT PLANS

The Company operates a discretionary bonus plan and a 401(k) savings plan via a third-party service provider.

Upon hire, an individual is immediately eligible to participate in the 401(k) plan. The Company, under its sole discretion, may contribute an employer-matching contribution equal to a percentage not to exceed 6% of each eligible participant’s contributions. The Company contributed $625,000, $592,000 and $283,000, in the years ended December 31, 2012, 2011 and 2010, respectively.

16. RELATED PARTY TRANSACTIONS

As of December 31, 2012 and 2011, the Company had a receivable of $2.4 million, for monitoring fees on behalf of Parent to Parent’s members, ACON Milagro Investors, LLC, Milagro Investors, LLC and West Coast Milagro Partners, LLC, in 2008 and 2007, which are recognized as an advance to affiliates in the accompanying balance sheets.

17. SEGMENT INFORMATION

Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.

The Company measures financial performance as a single enterprise, allocating capital resources on a project by project basis across its entire asset base to maximize profitability. The Company utilizes a company-wide management team that administers all enterprise operations encompassing the exploration, development and production of natural gas and oil. Since the Company follows the full cost of method of accounting and all its oil, NGL and natural gas properties and operations are located in the United States, the Company has determined that it has one reporting unit. In as much as the Company is one enterprise, it does not maintain comprehensive financial statement information by area but does track basic operational data by area.

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MILAGRO OIL & GAS, INC.

SUPPLEMENTAL DISCLOSURES ABOUT OIL & GAS PRODUCING ACTIVITIES

1. Modernization of Oil and Natural Gas Reporting Requirements

The reserve estimates as of December 31, 2012, 2011 and 2010, presented herein were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the Financial Accounting Standards Board effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

The above-mentioned rules include updated definitions of proved oil and natural gas reserves, proved undeveloped oil and natural gas reserves, oil and natural gas producing activities, and other terms used in estimating proved oil and natural gas reserves. Proved oil and natural gas reserves as of December 31, 2012, 2011 and 2010 were calculated based on the prices for oil and natural gas during the twelve month period before the reporting date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. The authoritative guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and natural gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands as well as oil and natural gas extracted from shale.

2. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the years ended December 31:

	2012		2011		2010
	(In millions)
Property acquisition costs:
Proved	$	—	$	28.2	$	66.9
Unproved		1.7		10.8		3.3
Exploration		12.8		27.8		16.1
Development costs(1)		10.5		32.5		27.0
Total costs incurred	$	25.0	$	99.3	$	113.3

(1) Includes asset retirement obligations incurred and revisions of previous estimates of $7.5 million, $3.3 million and $10.1 million for 2012, 2011 and 2010, respectively.

3. Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below as of December 31:

	2012		2011
	(in thousands)
Capitalized costs:
Proved properties	$	1,303,922	$	1,279,276
Unproved properties		14,971		14,914
Less: accumulated depreciation, depletion, amortization and impairment		877,754		812,364
Net capitalized costs	$	441,139	$	481,826

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Unproved properties, which are not subject to amortization, are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the amortization calculation.

4. Proved Oil and Natural Gas Reserves

The Company’s proved oil and natural gas reserves were prepared by W.D Von Gonten & Co. (W.D. Von Gonten), independent third party petroleum consultants. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.

An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2012 and 2011 is as follows:

Milagro Oil & Gas, Inc.

Supplemental Oil and Gas Disclosures

	Year Ended December 31, 2012
	Gas (MMcf)		Oil (MBbls)		NGL (MBbls)		MBoe
Proved developed and undeveloped reserves:
Beginning of year		136,780		9,162		5,302		37,260
Revisions of previous estimates		(26,250)		14		(705)		(5,067)
Extensions, discoveries and other additions		5,431		2,561		542		4,008
Divestitures of reserves		—		—		—		—
Purchases of minerals in place		—		—		—		—
Production		(9,203)		(873)		(260)		(2,667)
End of year		106,758		10,863		4,879		33,535
Proved developed reserves:
Beginning of year		83,078		6,951		1,961		22,758
End of year		66,537		6,892		1,913		19,894
Proved undeveloped reserves:
Beginning of year		53,702		2,211		3.341		14,502
End of year		40,221		3,971		2,966		13,641

	Year Ended December 31, 2011
	Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		134,722			9,926			4,305			36,684
Revisions of previous estimates		(7,411	)		(381	)		33			(1,583	)
Extensions, discoveries and other additions		7,763			228			767			2,289
Divestitures of reserves		—			—			—			—
Purchases of minerals in place		13,047			184			432			2,790
Production		(11,341	)		(795	)		(235	)		(2,920	)
End of year		136,780			9,162			5,302			37,260
Proved developed reserves:
Beginning of year		90,401			7,300			2,057			24,424
End of year		83,078			6,951			1,961			22,758
Proved undeveloped reserves:
Beginning of year		44,321			2,626			2,248			12,260
End of year		53,702			2,211			3,341			14,502

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	Year Ended December 31, 2010
	Gas (MMcf)			Oil (MBbls)			NGL (MBbls)			MBoe
Proved developed and undeveloped reserves:
Beginning of year		121,922			9,403			1,218			30,942
Revisions of previous estimates		4,627			197			293			1,261
Extensions, discoveries and other additions		868			31			40			216
Divestitures of reserves		(5	)		(4	)		—			(5	)
Purchases of minerals in place		20,967			1,170			2,893			7,557
Production		(13,657	)		(871	)		(139	)		(3,287	)
End of year		134,722			9,926			4,305			36,684
Proved developed reserves:
Beginning of year		93,748			7,041			787			23,453
End of year		90,401			7,300			2,057			24,424
Proved undeveloped reserves:
Beginning of year		28,174			2,362			431			7,489
End of year		44,321			2,626			2,248			12,260

The tables above include changes in estimated quantities of oil and natural gas reserves shown in Bbl equivalents (“Boe”) at a rate of six Mcf per one Bbls.

For the year ended December 31, 2012, the Company did not add any MMBoe through acquisitions, with a negative revision of 5.067 MMBoe of previous estimated quantities primarily due to certain natural gas proved undeveloped locations being dropped from the Company’s plan due to the low natural gas prices. The oil and natural gas reference prices used in computing reserves as of December 31, 2012 were $94.71 per barrel and $2.76 per Mmbtu before price differentials.

For the year ended December 31, 2011, the Company added 2.79 MMBoe through acquisitions in its onshore Texas Gulf Coast and Midcontinent core areas, with a negative revision of 1.5 MMBoe of previous estimated quantities primarily due to certain natural gas proved undeveloped locations being dropped from the Company’s plan due to the low natural gas prices. The oil and natural gas reference prices used in computing reserves as of December 31, 2011 were $96.19 per barrel and $4.12 per Mmbtu before price differentials.

For the year ended December 31, 2010, the company added 7.6 MMBoe through acquisitions in its core areas onshore Texas Gulf Coast and the Midcontinent, with a positive revision of 1.3 MMBoe of previous estimated quantities primarily due to an increase in reference prices. The oil and natural gas reference prices used in computing reserves as of December 31, 2010 were $79.43 per barrel and $4.38 per Mmbtu before price differentials.

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5. Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2012, 2011 and 2010 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the Company. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2012, 2011 and 2010 is as follows:

	2012			2011			2010
	(In thousands)
Future cash inflows	$	1,619,754		$	1,631,188		$	1,505,295
Future production costs		(503,133	)		(487,925	)		(459,137	)
Future development costs		(222,137	)		(227,877	)		(195,440	)
Future income tax expenses		(76,364	)		(88,822	)		(80,150	)
Future net cash flows		818,120			826,563			770,568
10% discount for estimated timing of cash flows		(361,372	)		(364,107	)		(321,533	)
Standardized measure of discounted future net cash flows	$	456,748		$	462,456		$	449,035

The changes in standardized measure as of December 31, 2012, 2011 and 2010 are as follows:

Standardized measure of discounted future net cash flows, beginning of year	$	462,456		$	449,035		$	318,198
Changes in the year resulting from:
Sales, less production costs		(25,713	)		(91,647	)		(89,020	)
Revisions of previous quantity estimates		(68,152	)		(21,264	)		16,946
Extensions, discoveries and other additions		95,153			16,009			3,930
Net change in prices and production costs		(74,508	)		33,620			96,996
Changes in estimated future development costs		3,244			(11,969	)		(2,507	)
Previously estimated development costs incurred during the period		4,421			11,183			7,227
Purchases of minerals in place		—			32,108			72,121
Accretion of discount		50,120			49,293			31,886
Divestiture of Reserves		—			—			(68	)
Net change in income taxes		7,031			5,152			(43,234	)
Changes in timing differences and other		(2,696	)		(9,064	)		36,560
Standardized measure of discounted future net cash flows, end of year	$	456,748		$	462,456		$	449,035

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

Not Applicable

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, our management, including our Chief Executive Officer and Vice President of Finance and Chief Accounting Officer, completed an evaluation of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended, and determined that our disclosure controls and procedures were not effective as of December 31, 2012. . We have identified certain material weaknesses in our internal control over financial reporting related to inconsistent or ineffective financial statement review and preparation and insufficient financial reporting resources in our internal control over financial reporting primarily related to a lack of financial and personnel resources. To remediate these issues, our management has retained the services of additional third party accounting personnel as well as modified existing internal controls in a manner designed to ensure compliance.

Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting Firm

Management is responsible for establishing and maintaining adequate internal control over financial reporting, and for performing an assessment of the effectiveness of internal control over financial reporting as of December 31, 2012.  Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012 based upon criteria in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management believes that our internal control over financial reporting was ineffective as of December 31, 2012, due to insufficient financial reporting resources.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting as of the annual period covered by this report that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.    Other Information

Not Applicable

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PART III

Item 10.     Directors, Executive Officers and Corporate Governance

Officers and Directors

The following is a list of our executive officers and directors as of December 31, 2012. Our directors hold office until the expiration of their term or until their successors are duly elected and qualified.

Name	Age		Position
Gary J. Mabie		69	President and Chief Operating Officer
Robert D. LaRocque		57	Chief Financial Officer and Treasurer
Marshall L. Munsell		55	Senior Vice President of Business Development
Lloyd Armstrong		54	Vice President of Production Logistics
Jonathan Ginns		46	Director
Mo Bawa		35	Director
Thomas J. Hauser		31	Director
Adam Cohn		40	Director

Gary J. Mabie has served as our President and Chief Operating Officer since December 2012.  Prior to this, he served as our Chief Operating Officer since February 2010. Prior to joining us, Mr. Mabie worked as President for GM Oil & Gas Company, an industry provider of consulting services, Vice President of Operations at Comet Ridge Resources from 2006 to 2009, President of CDX West, a subsidiary of CDX Gas, LLC, from 2005 to 2006, President and Chief Operating Officer of SunCoast Energy Corporation from 2000 to 2005, General Manager and Senior Vice President of Onshore of Pennzoil/PennzEnergy from 1997 to 1999, and Vice President of Exploration and Production for Hunt Petroleum from 1990 to 1997. Mr. Mabie served in various management positions with Tenneco Oil, E&P with the last position being Operations Manager of the International Division. Mr. Mabie began his career as a petroleum engineer with Gulf Oil Corporation. He graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.

Robert D. LaRocque has served as our Chief Financial Officer and Treasurer since July 2012.  Prior to this he served as our Vice President of Finance and Treasurer since October 2010. Prior to joining us, Mr. LaRocque served as a Managing Director for Credit Lyonnais from 1997 to 2003, Vice President of Corporate Development for Aquila Energy from 1995 to 1997 and Director of International Finance at Tenneco Gas. Mr. LaRocque earned his undergraduate degree from Queen’s University and his MBA from Dalhousie University.

Marshall L. Munsell is one of our original founders and as our Senior Vice President of Business Development has been responsible for our Land and Business Development departments since our formation in 2005. Prior to joining us, Mr. Munsell worked for Mission Resources Corporation as Senior Vice President of Land and Land Administration from 2002 to 2005, and has served in various management and staff roles with DDD Energy, Presidio Oil Company and Sun Oil Company. Mr. Munsell is a Certified Professional Landman and earned his Bachelor’s degree in Petroleum Land Management from the University of Texas.

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Lloyd Armstrong has served as our Vice President of Production Logistics since January 2008. Prior to joining us, Mr. Armstrong served as Vice President of Operational Accounting for Goodrich Petroleum Corporation from August 2005 until December 2007, Vice President of Revenue Administration for Mission Resources Corporation from November 2002 to July 2005 and as Director of Operational Accounting for El Paso Production Company from 1999 to 2002. Mr. Armstrong has also served as Accounting Manager for El Paso Field Services and as Project Manager of a gas plant accounting system implementation for Andersen Consulting from 1997 to 1998. Mr. Armstrong began his career at Amerada Hess Corporation where he held several accounting positions from 1980 to 1997. Mr. Armstrong earned his BS in Accounting and Business Administration from Northeastern State University in Oklahoma.

Jonathan Ginns is a Founder and Managing Partner of ACON Investments and has served on our board of directors since 2007. Founded in 1996, ACON is an international private equity investment firm managing capital through varied investment funds and special purpose partnerships. Prior to founding ACON, he was a Senior Investment Officer at the GEF Funds Group. Previously, Mr. Ginns was a Management Consultant at Booz Allen &Hamilton. Mr. Ginns received an MBA from the Harvard Business School, and a BA from Brandeis University. He also serves on the Boards of Directors of Chroma Oil & Gas, Northern Tier Energy and Signal International.

Mo Bawa is a Principal of ACON Investments and has served on our board of directors since 2007. He is responsible for sourcing, evaluating, executing and monitoring transactions principally in the energy sector for ACON. Previously, he was an Associate with Constellation Commodities Group where he was responsible for origination, structuring, evaluation, and negotiation of the firm’s principal investments. Mr. Bawa has also held corporate finance and principal investing positions with Houlihan Lokey Howard & Zukin, Enron Capital & Trade Resources, and Banc of America Securities. Mr. Bawa holds a B.A. in Economics, Management and Public Policy from Rice University and MBA from The Anderson School at UCLA. He also serves on the Boards of Directors of Chroma Oil & Gas and Signal International.

Thomas J. Hauser is a Director of Guggenheim Partners, LLC and has served on our board of directors since April 11, 2011. Guggenheim is an asset management firm with over $120 billion of assets under management. Mr. Hauser joined Guggenheim in 2002 as an analyst on the leveraged credit investing team. During his tenure at Guggenheim, he has covered multiple industries including gaming, leisure, transportation, utilities, energy and real estate. He currently leads an industry team that focuses on investing across the capital structure in the energy, power and transportation sectors. Mr. Hauser earned his Bachelor of Science degree in Finance from St. John’s University and is a member of the Association for Corporate Growth.

Adam Cohn is a Principal at Knowledge Universe Limited, LLC where he has worked since 2000 and has served on our board of directors since 2007, as a representative of West Coast Energy Partners. Prior to Knowledge Universe, Mr. Cohn worked at Whitney & Co., a private equity firm. Prior to Whitney & Co., Mr. Cohn was an investment banker in the Financial Sponsors Group at Bankers Trust Company and Deutsche Bank. He has a Bachelor’s Degree in Business from Skidmore College and a MBA from Columbia University. He also serves on the boards of Knowledge Learning Corporation, Busy Bees Holdings Limited, and Embanet-Compass Knowledge Group Inc.

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Board of Directors

Our board of directors is composed of four members, each of whom is elected annually by our stockholders. There is one vacancy currently. Under the Stockholders’ Agreement dated January 13, 2010, as subsequently amended (the “Stockholders’ Agreement”), which is effective for so long as we are a subsidiary of our parent company, Holdings, holders of our Series A preferred stock have the right to appoint four of the five members of our board of directors.

Messrs. Bawa and Ginns are appointees of ACON, Mr. Hauser is an appointee of Guggenheim and Mr. Cohn is an appointee of West Coast Energy. Our fifth director would be our chief executive officer, but we do not currently have a Chief Executive Officer.

Currently, our only board committee is the audit committee, the members of which are Mo Bawa (who also serves as chairman) and Thomas Hauser. We do not have a compensation or corporate governance and nominating committee, as our full board performs the functions typically designated to these committees. As we are not a “listed issuer” within the meaning of Rule 10A-3 of the Exchange Act, we are not subject to the requirements of such rule. Neither member of the audit committee meets the requirements of an “audit committee financial expert” as defined in the rules of the SEC, nor does any other member of our board of directors. Given the makeup of our board of directors and the fact that we have only one holder of our common stock, we do not believe it is necessary to have a person who meets such requirements serving on the audit committee.

Compliance with Section 16(a) of the Exchange Act

Not applicable

Code of Ethics

We have adopted a code of ethics that applies to all of our employees, as well as each member of our board of directors. A copy of the code of ethics will be provided, without charge, upon written request to Milagro Oil & Gas, Inc., Attention: Human Resources, 1301 McKinney, Suite 500, Houston, Texas 77010, phone: 713-750-1600. We intend to post amendments to or waivers from the code of ethics (to the extent applicable to our principal executive officer, principal financial officer or principal accounting officer) on our website.

Item 11. Executive Compensation

Compensation Discussion and Analysis

General

The following discussion describes and analyzes our compensation for our principal executive officer, principal financial officer, and the two other executive officers as of December 31, 2012.

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. 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, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent region.

Compensation Philosophy and Objectives and Elements of Compensation

Our intent and philosophy in designing compensation packages at the time of hiring new executives has been based in part on providing compensation that we thought was sufficient to enable us to attract the talent necessary to further develop our business while at the same time being prudent in the management of our cash and equity. Compensation of our executive officers after the initial period following their hiring has been influenced by the amounts of compensation that we initially agreed to pay them as well as by our evaluation of their subsequent performance, changes in their levels of responsibility, prevailing market conditions, our financial condition and prospects.

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We have compensated our executives with a combination of salaries, cash bonuses and awards under our profits interest plan, or the Plan. We also believe that it provides an appropriate blend of compensation to retain our executives, reward them for performance in the short term and induce them to contribute to the creation of value in the Company over the long term.

We view the different components of our executive compensation as distinct. We believe we must maintain a sufficiently competitive salary to position us to attract the executives that we need and that it is important that our executives perceive that over time they will continue to have the opportunity to earn a salary that they regard as competitive.

The ability to earn cash bonuses should incentivize executives to effectively pursue goals established by our board of directors and should be regarded by executives as appropriately rewarding effective performance against these goals. In the past we have sought to establish target bonus levels and performance goals for executives at the beginning of the year to help ensure that our performance goals, and the bonus attainable for achieving these goals, were well understood by executives.

The Plan is a profits interest incentive program in which we issue to employees profits interests in a limited partnership which owns Class C membership interests in our parent company, Holdings, which is a holding company and the holder of record of 100% of our issued and outstanding common stock. The participants’ profits interests represent the right to receive a percentage of the distributions made by Holdings when such distributions exceed specified internal rate of return thresholds. This Plan is designed to recognize the need for current profitability as well as building long-term value. In addition, the Plan is designed to aid us in retaining the services of key executives and employees by requiring vesting conditions on each grant, which provide that the participant would forfeit the unvested portion of the grant upon their termination of service with us. Vested units may also be forfeited in certain circumstances, including certain termination events, a personal bankruptcy or other specified conditions.

We have used awards under the Plan as the form of equity award for executives. The size of the award is determined based on the executive’s position with us and takes into consideration the executive’s base salary and other compensation as well as an analysis of the grant and compensation practices of other companies in our industry. Typically, our Plan awards to executive officers vest and become exercisable over five years. Our board of directors believes that these awards align the interests of our executive officers with those of the stockholders, because they create the incentive to build stockholder value over the long-term. In addition, our board of directors believes the vesting provision of our equity awards improves our ability to retain our executives.

Compensation Decision Process

Since our formation, our board of directors has overseen the compensation of our executive officers and our executive compensation programs and initiatives. While we have had an Executive Compensation Committee which administers the Plan, the ultimate compensation decisions have been made by the full board of directors. The board of directors has also sought, and received, significant input from our principal executive officer with regard to the performance and compensation of executives other than himself.

Certain of our directors have significant experience with privately held private equity-backed companies such as ours and the executive compensation practices of such companies, and have applied this knowledge and experience to their judgments regarding our compensation decisions.

2012 Compensation

Salary

The salaries of our named executive officers are reflected below and were determined by our board of directors. Compensation is reviewed annually against salaries being paid by other companies of a like size and scope.

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Bonus

Bonus compensation is based on the discretion of our board of directors and upon achievement of performance objectives established by our board of directors annually. Criteria making up the bonus objectives in 2012 included a weighting of the following criteria: annual EBITDA, total production expressed on a per Bcfe basis, reserve replacement, finding and developing costs expressed as dollars per BOE, lease operating expense expressed on a per Mcfe basis and gross general and administrative expenses. These criteria were chosen, in the case of EBITDA, lease operating expense and gross general and administrative expense, as the most significant measure of our cash flows and profitability, and, in the case of total production, reserve replacement and finding and developing costs, as the most significant measures of success during the year in our business. Each category has an annual threshold of 75% of the approved budget, a target of 100% of the approved budget and a stretch goal of 125% of the approved budget. We believe that all goals, while intentionally presenting a significant challenge, are realistic and achievable by our executives in most instances, if they perform their duties with the degree of care and diligence that we expect of them.

Target, threshold and stretch criteria in the table below were established by our board of directors and are the same for each of the named executive officers

	Threshold			Target			Stretch			Results			Bonus Achievement			Weighting			Contribution
EBITDA (in millions)	$	63.7		$	83.8		$	94.7		$	86.6			106	%		30	%		32	%
Total Production (in BCFE)		16.1			17.3			20.7			16.1			75	%		20	%		15	%
Reserve Replacement		90	%		100	%		110	%		124	%		125	%		20	%		25	%
F&D Internal Projects ($/BOE)	$	30.00		$	24.00		$	19.50		$	10.24			125	%		20	%		25	%
Operating Expense/MCFE	$	2.56		$	2.13		$	1.72		$	2.36			87	%		5	%		4	%
Gross General and Administrative expense (in millions)	$	20.0		$	16.8		$	14.4		$	16.6			102	%		5	%		5	%
Total weighted-average bonus																				106	%

Severance and Change of Control Agreements

We have entered into employment letters with certain of our named executive officers providing for certain payments upon termination of their employment with us without cause and upon termination without cause following a change of control. These payments, and the definition for this purpose of change of control, are described in detail below under “Potential Payments upon Termination and Change in Control.”

We believe that these agreements appropriately balance our needs to offer a competitive level of severance protection to our executives and to induce our executives to remain in our employ through the potentially disruptive conditions that may exist around the time of a change in control, while not unduly rewarding executives for a termination of their employment. We note that our change in control terms include so-called “double trigger” provisions, so that the executive is not entitled to the severance payment by the mere occurrence of the change in control. We believe this feature will be an incentive to the executive to remain in our employ if such continuation is required by our partner in a change in control transaction. We also believe that it is appropriate that our executives’ equity awards be treated, in the event of a change of control, like those of other employees and not accelerated if the executive’s employment continues following the change in control event.

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Other Executive Benefits and Perquisites

We provide the following benefits to our executive officers on the same basis as other eligible employees:

• health insurance;

• vacation, personal holidays and sick days;

• life insurance and personal accident insurance;

• short-term and long-term disability; and

• a 401(k) plan.

We believe these benefits are generally consistent with those offered by other companies with which we compete for executive talent.

Other Compensation Practices and Policies

Policy regarding the timing of equity awards. As a privately-owned company, there is no market for our capital stock. Accordingly, in fiscal year 2012, we had no program, plan or practice pertaining to the timing of stock option grants to executive officers coinciding with the release of material non-public information. We do not, as of yet, have any plans to implement such a program, plan or practice.

Policy regarding restatements. We do not have a formal policy regarding adjustment or recovery of awards or payments if the relevant performance measures upon which they are based are restated or otherwise adjusted in a manner that would reduce the size of the award or payment. Under those circumstances, our board of directors or a committee thereof, would evaluate whether adjustments or recoveries of awards were appropriate based upon the facts and circumstances surrounding the restatement.

Stock Ownership Policies. We have not established stock ownership or similar guidelines with regards to our executive officers. All of our executive officers currently have an indirect equity interest in our company through their Plan awards and we believe that they regard the potential returns from these interests as a significant element of their potential compensation for services to us.

Summary Compensation Table

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2012 Summary Compensation Table

The following table provides information concerning compensation paid or accrued during the fiscal years ended December 31, 2012, 2011 and 2010 to our principal executive officer, principal financial officer and our two other executive officers, determined at the end of the last fiscal year, and two former executive officers for whom disclosure would have been required but for the fact that they were not serving as executive officers at the end of the fiscal year ended December 31, 2012:

Name and Principal Position	Year	Salary		Bonus			Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation		All Other Compensation			Total
Gary J. Mabie	2012	$	250,000	$	104,167	(3)	$	—	$	—	$	—	$	87,000	(1)	$	441.167
President and Chief	2011	$	250,000	$	90,000		$	—	$	—	$	—	$	78,604	(1)	$	418,604
Operating Officer	2010	$	220,000	$	230,000		$	—	$	—	$	—	$	82,431	(1)	$	532,431
Robert D. LaRocque	2012	$	216,875	$	96,000	(3)	$	—	$	—	$	—	$	—		$	312,875
Chief Financial Officer	2011	$	178,750	$	90,000		$	—	$	—	$	—	$	—		$	268,750
and Treasurer	2010	$	45,000	$	30,000		$	—	$	—	$	—	$	—		$	75,000
Marshall L. Munsell	2012	$	240,000	$	96,000	(3)	$	—	$	—	$	—	$	—		$	336,000
Senior Vice President of	2011	$	237,917	$	170,000		$	—	$	—	$	—	$	—		$	407,917
Business Development	2010	$	235,000	$	245,000		$	—	$	—	$	—	$	—		$	480,000
Lloyd Armstrong	2012	$	185,000	$	49,333	(3)	$	—	$	—	$	—	$			$	234,333
Vice President of	2011	$	183,020	$	125,000		$	—	$	—	$	—	$	—		$	308,020
Production Logistics	2010	$	180,250	$	140,000		$	—	$	—	$	—	$	—		$	320,250
James G. Ivey	2012	$	287,500	$	—		$	—	$	—	$	—	$	300,000	(2)	$	587,500
Former President/ Chief	2011	$	300,000	$	295,000		$	—	$	—	$	—	$	—		$	595,000
Executive Officer	2010	$	248,750	$	260,000		$	—	$	—	$	—	$	—		$	508,750
Thomas C. Langford	2012	$	172,077	$	—		$	—	$	—	$	—	$	—		$	172,077
Former Senior Vice	2011	$	237,917	$	160,000		$	—	$	—	$	—	$	—		$	397,917
President and General	2010	$	235,000	$	245,000		$	—	$	—	$	—	$	—		$	480,000
Counsel

(1)	Represents reimbursement of housing and commuting expenses.
(2)	Reflects severance payments made to Mr. Ivey in connection his departure in December 2012.
(3)	Each of Messrs. Mabie, LaRocque and Munsell will receive additional bonus payments in April and May 2013.   Mr. Mabie will receive two payments of $104,167 and Messrs. LaRocque and Munsell will receive two payments of $96,000.  Mr. Armstrong will receive one payment of $49,333 in April 2013.

Grants of Plan-Based Awards

There were no grants of plan-based awards during 2012 to the Named Executive Officers.

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Outstanding Equity Awards at Fiscal Year-End

The following table shows the grants of equity awards to our named executive officers that were outstanding on December 31, 2012, the last day of our fiscal year.

OUTSTANDING EQUITY AWARDS AT 2012 FISCAL YEAR-END

	Option Awards										Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)(1)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Gary J. Mabie		—		—		—		—		—		40,000		—		—		—
Robert D. LaRocque		—		—		—		—		—		16,000		—		—		—
Marshall L. Munsell		—		—		—		—		—		—		—		—		—
Lloyd Armstrong		—		—		—		—		—		2,600		—		—		—

(1) The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2012.

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Option Exercises and Stock Vested Table

The table below shows the number of shares of our common stock acquired by our named executive officers during 2012 upon the vesting of Plan awards.

Option Exercises and Stock Vested

as of Fiscal Year-End December 31, 2012

	Option Awards				Stock Awards
Name	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($)		Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)(1)
Gary J. Mabie		—		—		10,000		—
Robert D. LaRocque		—		—		4,000		—
Marshall L. Munsell		—		—		14,000		—
Lloyd Armstrong		—		—		2,300		—

(1) The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2012.

Pension Benefits

We do not maintain any defined benefit pension plans.

Nonqualified Deferred Compensation

We do not maintain any nonqualified deferred compensation plans.

Employment Arrangements

We have entered into employment agreements with certain of our named executive officers.

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Our agreement with Mr. Mabie became effective February 8, 2010 and had a term of one year. This agreement was extended through February 8, 2012 and monthly thereafter. We and the board of directors are currently in discussion with Mr. Mabie to extend the term of this agreement. He currently receives an annual base salary of $250,000 and pursuant to the agreement is entitled to an annual bonus as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. Pursuant to the agreement, the board of directors also evaluates Mr. Mabie’s salary on an annual basis and will determine if any additional increases are warranted. Pursuant to the agreement, Mr. Mabie is also subject to a non-solicitation agreement for six months after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Pursuant to the agreement, payments under the agreement to Mr. Mabie in connection with his termination or a change of control are described below under “— Potential Payments Upon Termination or Change of Control.”

Our agreement with Mr. LaRocque became effective January 1, 2011 and had a term of eleven months, with automatic renewal for additional one year periods unless either we or Mr. LaRocque elects not to renew. He currently receives an annual base salary of $240,000 and is entitled to an annual bonus of up to 120% of his base salary as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. The board of directors also evaluates Mr. LaRocque’s salary on an annual basis and will determine if any additional increases are warranted. The employment agreement prohibits Mr. LaRocque from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Mr. LaRocque is also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreement to Mr. LaRocque in connection with his termination or a change of control are described below under “— Potential Payments Upon Termination or Change of Control.”

Our agreement with Mr. Munsell became effective November 30, 2007 and had a term of one year, with automatic renewal for additional one year periods unless either we or Mr. Munsell elect not to renew. He currently receive an annual base salary of $240,000 and is entitled to an annual bonus of up to 120% of his base salary as may be determined from time to time in the sole discretion of the board of directors based on the achievement of certain performance criteria. The board of directors also evaluates his salary on an annual basis and will determine if any additional increases are warranted. The employment agreement prohibits Mr. Munsell from competing with us during his employment and for a period of one year thereafter if he is terminated for cause or he resigns without good reason. Mr. Munsell is also subject to a non-solicitation agreement for two years after his termination for any reason (other than in connection with a change of control event) and a confidentiality obligation after cessation of his employment with us. Payments under the agreement to Mr. Munsell in connection with his termination or a change of control are described below under “— Potential Payments Upon Termination or Change of Control.”

Potential Payments upon Termination and Change of Control

The following tables describe the potential payments upon termination or a change in control for our named executive officers other than Messrs. Ivey and Langford, as they are no longer employed by us.

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Name: Gary J. Mabie

Title: President and Chief Operating Officer

Executive Benefits and Payments Upon Termination(1)	Voluntary Termination ($)		For Cause Termination ($)		Involuntary Not for Cause Termination or Voluntary Termination for Good Reason ($)		Death or Disability ($)		Retirement ($)		After a Change in Control ($) (2)
Compensation
Severance(3)		—		—		250,000		—		—		500,000
Bonus(4)		—		—		—		—		—		—
Plan awards (5)		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		11,086		1,165,000		—		11,086
Total(7)		—		—		261,086		1,165,000		—		511,086

Name: Robert D. LaRocque

Title: Chief Financial Officer and Treasurer

Executive Benefits and Payments Upon Termination(1)	Voluntary Termination ($)		For Cause Termination ($)		Involuntary Not for Cause Termination or Voluntary Termination for Good Reason ($)		Death or Disability ($)		Retirement ($)		After a Change in Control ($)(2)
Compensation
Severance(3)		—		—		240,000		—		—		480,000
Bonus(4)		—		—		288,000		—		—		288,000
Plan awards(5)		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		44,062		1,160,000		—		44,062
Total		—		—		572,062		1,160,000		—		812,062

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Name: Marshall L. Munsell

Title: Senior Vice President of Business Development

Executive Benefits and Payments Upon Termination(1)	Voluntary Termination ($)		For Cause Termination ($)		Involuntary Not for Cause Termination or Voluntary Termination for Good Reason ($)		Death or Disability ($)		Retirement ($)		After a Change in Control ($) (2)
Compensation
Severance(3)		—		—		240,000		—		—		480,000
Bonus(4)		—		—		288,000		—		—		288,000
Plan awards (5)		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		44,062		1,160,000		—		44,062
Total		—		—		572,062		1,160,000		—		812,062

Name: Lloyd Armstrong

Title: Vice President of Production Logistics

Executive Benefits and Payments Upon Termination(1)	Voluntary Termination ($)		For Cause Termination ($)		Involuntary Not for Cause Termination or Voluntary Termination for Good Reason ($)		Death or Disability ($)		Retirement ($)		After a Change in Control ($)
Compensation
Severance		—		—		—		—		—		—
Bonus		—		—		—		—		—		—
Plan awards		—		—		—		—		—		—
Benefits and Perquisites
Health Continuation and Welfare Benefits(6)		—		—		—		940,000		—		—
Total		—		—		—		940,000		—		—

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(1)	For purposes of this analysis, we assumed that the effective date of termination is December 31, 2012, and that the executive’s compensation is as follows: Mr. Mabie’s base salary is equal to $250,000 and annual incentive target opportunity is equal to 125% of base salary, Mr. LaRocque’s base salary is equal to $240,000 and annual incentive target opportunity is equal to 120% of base salary; and Mr. Munsell’s base salary is equal to $240,000 and annual incentive target opportunity is equal to 120% of base salary. We have assumed for purposes of this table that all bonus targets established by our board of directors have been met and our board of directors approved the payment of a bonus to the amount reflected. We have not reflected any payment for unused vacation accrued during the year. Mr. Armstrong is not entitled to any severance or change of control payments so no assumptions were needed regarding his base salary or incentive target opportunity.
(2)	Payments in connection with a change of control event (as defined in the employment agreements for each named executive officer) are payable if (i) they are terminated by us without cause (as defined in the employment agreements) or they terminate for good reason (as defined in the employment agreements) within 24 months after the change of control event or (ii) they terminate their employment for any reason within 30 days of the six month anniversary of the change of control event.
(3)	Under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason,” severance is calculated as 1x base salary and is payable in accordance with standard payroll practices. Under “After a Change in Control,” severance is calculated as 2x base salary and is payable in accordance with standard payroll practices.
(4)	Under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason” and “After a Change in Control,” bonus is calculated assuming all performance criteria have been met.
(5)	All unvested Plan awards are automatically forfeited for no consideration in connection with a termination of the employee for any reason. In addition, all Plan awards become fully vested in connection with a change of control. The participant’s profits interests under the Plan represent the right to receive a percentage of the distribution made by Holdings when such distributions exceed specified internal rate of return thresholds. Those thresholds had not been met as of December 31, 2012
(6)	Health and Welfare Benefits Continuation is calculated as 18 months of COBRA expense under “Involuntary Not for Cause Termination or Voluntary Termination for Good Reason” and “After a Change in Control.” In both categories, the benefits payable will be reduced to the extent that the named executive officer becomes eligible to comparable benefits from a new employer or other entity. Welfare Benefits include various life, accident and disability insurance policies. For the purposes of this analysis, the maximum payout was calculated by assuming accidental death. Benefits will be paid in accord with each policy’s schedule of insurance and terms of the covered losses including the age of the participant.
(7)	Our agreement with Mr. Mabie became effective February 8, 2010 and had a term of one year. This agreement was extended through February 8, 2012 and monthly thereafter.

Compensation Committee Interlocks and Insider Participation

All compensation decisions are made by our board of directors. Other than Mr. Ivey, none of the members of our board of directors is or has been an officer or employee of our company or had any related person transactions involving us. Other than Mr. Ivey, none of our executive officers currently serves, or in the past year has served, as a member of the board of directors or compensation committee (or other committee serving an equivalent function) of any entity that has one or more executive officers serving on our board of directors or compensation committee.

Director Compensation

None of the members of our board of directors received any compensation from us during 2012, other than the compensation paid to Mr. Ivey as chief executive officer while he served on the board of directors. Certain of our equity sponsors (for which certain of our directors serve as representatives on our board of directors) may under certain conditions receive fees pursuant to the Monitoring Agreement described below under “Certain Relationships and Related Party Transactions.

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

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth information with respect to the beneficial ownership of our common stock and our Series A preferred stock as of March 28, 2013.

Name and Address of Beneficial Owner	Number of Shares of Common Stock Beneficially Owned(1)		Percentage			Number of Shares of Preferred Stock Beneficially Owned(2)		Percentage(3)
ACON Funds Management, L.L.C.(4) 1133 Connecticut Avenue, NW, Suite 700 Washington, DC 20036		123,376		44.0	%		917,178		34.0	%
Guggenheim Investment Management, LLC(5) 135 East 57th Street, 6th Floor New York, New York 10022		83,840		29.9	%		502,135		18.6	%
Touradji Capital Management, LP(6) 101 Park Avenue, 48th Floor New York, NY 10178		—		—			425,921		15.8	%
West Coast Energy Partners(7) 1250 Fourth Street Santa Monica, California 90401		39,536		14.1	%		389,850		14.4	%
FS Investment Corporation(8) 280 Park Avenue New York, NY 10017		12,057		4.3	%		283,947		10.5	%
PineBridge Investments LLC(9) 277 Park Avenue, 42nd Floor New York, NY 10172		—		—			180,969		6.7	%
Other stockholders(10)		21,591		7.7	%		—		—
Total		280,400		100	%		2,700,000		100	%

(1) Our parent company, Holdings, is a holding company and the holder of record of 100% of our issued and outstanding common stock. The number of shares of our common stock shown as beneficially owned is based on the respective beneficial ownership interest of each investor in Holdings and assumes the Class C membership interests in Holdings are not currently entitled to distributions. Holdings has three classes of membership interests outstanding: Class A, substantially all of which is owned by affiliates of ACON Funds Management, Guggenheim Investment Management and West Coast Partners; Class B, which is held by the original investors from 2005; and Class C, which are non-voting profit interests issued to our management team. All voting and investment decisions with respect to our common stock are made by the board of directors of Holdings, which is made up of representatives of ACON, Guggenheim and West Coast, as well as our chief executive officer.

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(2) The holders of our Series A preferred stock are party to the Stockholders’ Agreement, which will remain in effect for so long as we remain a subsidiary of Holdings. The Stockholders’ Agreement provides our Series A preferred stockholders with the right to, among other things, appoint four of the five members of our board of directors. The Stockholders’ Agreement also places restrictions on the ability of the holders of our Series A preferred stock to transfer their shares and requires that certain actions be approved unanimously or by a supermajority of our board of directors.

(3) Based on 2,700,000 shares of our Series A preferred stock outstanding as of March 28, 2013.

(4)	Includes shares held by ACON Milagro Second Lien Investors, LLC. Jonathan Ginns and Mo Bawa exercise voting and investment authority over these shares and serve as the representatives of ACON on our board of directors. See “Management — Board of Directors.”
(5)	Includes shares held by 1888 Fund, Ltd., Copper River CLO Ltd., Green Lane CLO Ltd., NZC Guggenheim Master Fund Limited, Sands Point Funding Ltd., Guggenheim Energy Opportunities Fund, LP, Kennecott Funding Ltd., IN-FP1, LLC and New Energy LLC. Guggenheim Investment Management, LLC is a wholly-owned subsidiary of Guggenheim Capital, LLC, which exercises voting and investment authority over these shares. Thomas J. Hauser serves as the representative of Guggenheim on our board of directors. See “Item 10. Directors, Executive Officers and Corporate Governance — Board of Directors.”
(6)	Includes shares held by Touradji Private Equity Master Fund Ltd. which is managed by Touradji Capital Management, LP. Mr. Paul Touradji is the General Partner of Touradji Capital Management and has voting and investment authority over the shares.
(7)	Adam Cohn exercises voting and investment authority over these shares and serves as the representative of West Coast Energy Partners on our board of directors. See “Item 10. Directors, Executive Officers and Corporate Governance — Board of Directors.”

(8) Mr. Brad Mardhall exercises voting and investment authority over these shares.

(9) Includes shares held by AIG Vantage Capital, L.P. and AIG PEP IV Co-Investment, L.P. Jonathan Sterns exercises voting and investment authority over these shares.

(10) Includes investors who individually beneficially own less than 1% of our outstanding common stock. Members of our management team do not beneficially own any shares of our capital stock other than Class C membership interests in Holdings. See “Item 11. Executive Compensation.”

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.

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

Certain Relationships and Related Party Transactions

In the ordinary course of our business and in connection with our financing activities, we have entered into transactions with certain of our affiliates and significant stockholders. All of the transactions set forth below were approved by the unanimous vote of our board of directors. We believe that we have executed all of the transactions set forth below on terms no less favorable to us than could have been obtained from unaffiliated third parties.

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Monitoring Agreement

In connection with the acquisition of Petrohawk Energy Corporation’s Gulf Coast assets in November 2007, Holdings entered into a Monitoring Agreement with our equity sponsors ACON, Guggenheim and West Coast (the “Monitoring Agreement”). Pursuant to the terms of the Monitoring Agreement, the equity sponsors agreed to provide Holdings with management and advisory services during the term of the Monitoring Agreement, including, but not limited to, services relating to: (a) financing matters; (b) acquisitions, dispositions and corporate change of control transactions, (c) commodity risk management, (d) day-to-day operational matters and (e) such other services as agreed to in writing. On the date Holdings entered into the Monitoring Agreement, the equity sponsors were paid a one-time equity commitment fee of $8.3 million. In addition, during the term of the Monitoring Agreement, and in exchange for services provided under the Monitoring Agreement, we are required to pay our equity sponsors an annual fee of $2.5 million payable in four quarterly installments. Although we are not a party to the Monitoring Agreement and therefore have no liability for payment of the fees thereunder, because Holdings is a holding company with no operations or assets other than our outstanding common stock, Holdings is dependent on distributions from us to fund its payment obligations under the Monitoring Agreement. In addition, because 100% of our common stock is held by Holdings, Holdings has the ability to require us to make distributions. However, as a result of restrictions under our prior first lien credit agreement and our existing first lien credit agreement, to date we have not been permitted to make distributions to Holdings sufficient to pay the monitoring fee and as a result the monitoring fee has continued to accrue. As of December 31, 2012, this accrued obligation was an aggregate of $10.6 million. We expect similar restrictions on distributions to make these payments will continue in the indenture governing these notes and the 2011 Credit Facility. The Monitoring Agreement will continue in effect until all of the equity sponsors consent to its termination. As part of the Monitoring Agreement, Holdings agreed to indemnify the equity sponsors for claims resulting from services provided thereunder; provided such claims do not arise out of an equity sponsor’s gross negligence or willful misconduct. Further, the Monitoring Agreement does not limit the equity sponsors’ ability to provide similar services to other companies, including competitors, and does not require the equity sponsors to present Holdings with any corporate opportunity before informing a third party of such opportunity.

Development Services Agreement

Two of our wholly-owned subsidiaries, Milagro Producing, LLC (“Producing”) and Milagro Exploration, LLC (“Exploration”), are parties to a Development Services Agreement (the “Development Services Agreement”). Pursuant to the Development Services Agreement, Exploration provides Producing with oil and gas services relating to Producing’s owned and acquired properties. These services include: (a) geological and geophysical services, (b) project marketing services, (c) drilling, completion and operating services (including acting as an operator for oil and gas properties), (d) accounting services, (e) revenue distribution and joint interest billing services, (f) governmental compliance and regulatory filings support, (g) general business services, (h) land services, (i) production handling, marketing and hedging, and (j) such additional services as the parties mutually agree. In return for services provided under the Development Services Agreement, Exploration receives reimbursement for costs incurred and the right to hold title to or be the licensee of all geological and geophysical data procured during the course of its work performed under the Development Services Agreement. In addition, Producing provides the funds required for Exploration to develop and acquire one or more proprietary seismic programs with all data derived from such a program being the property of Exploration. Upon termination of the Development Services Agreement, and in some cases before then, Exploration will reimburse Producing for the costs associated with acquiring the proprietary seismic program. The Development Services Agreement will remain in effect as long as Producing remains in existence and may be terminated at any time for any reason by Producing.

Director Independence

Our board of directors is currently composed of four members, each of whom is elected annually by our stockholders. There is one vacancy currently. Under the Stockholders’ Agreement, which is effective for so long as we are a subsidiary of Holdings, holders of our Series A preferred stock have the right to appoint four members of our board of directors. The fifth director would be our chief executive officer, but we do not currently have a chief executive officer.  As a result, none of our directors are considered independent at this time.

Item 14. Principal Accounting Fees and Services

Deloitte has served as our independent auditors for each of the past two fiscal years.

The following table presents aggregate fees for professional services rendered by our independent registered public accounting firm, Deloitte for the audit of our annual consolidated financial statements for the years ended December 31, 2012 and 2011.

	Year Ended December 31,
	(in thousands)
	2012		2011
Audit fees(1)	$	1,050	$	1,128
Audit- related fees(2)		—		880
All other fees		150		121
Total fees	$	1,200	$	2,129

(1) Audit fees are comprised of annual audit fees and quarterly review fees.

(2) Audit-related fees for fiscal year 2011 are comprised of fees related to accounting consultation fees and our registration statement on Form S-4.

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Policy on Board Pre-Approval of Services of Independent Registered Public Accounting Firm

Our board of directors has responsibility for appointing, setting compensation and overseeing the work of the independent registered public accounting firm. In recognition of this responsibility, the board of directors has established a policy to pre-approve all audit and permissible non-audit services provided by the independent registered public accounting firm. Prior to engagement of the independent registered public accounting firm for the following year’s audit, management will submit to the board of directors for approval a description of services expected to be rendered during that year for each of following categories of services:

Audit services include audit work performed in the preparation and audit of the annual financial statements, review of quarterly financial statements, reading of annual, quarterly and current reports, as well as work that generally only the independent auditor can reasonably be expected to provide, such as the provision of consents and comfort letters in connection with the filing of registration statements.

Audit-related services are for assurance and related services that are traditionally performed by the independent auditor, including due diligence related to mergers and acquisitions and special procedures required to meet certain regulatory requirements.

Tax services consist principally of assistance with tax compliance and reporting, as well as certain tax planning consultations.

Other services are those associated with services not captured in the other categories. We generally do not request such services from our independent auditor.

Prior to the engagement, the board of directors pre-approves these services by category of service. The fees are budgeted, and the Board requires the independent registered public accounting firm and management to report actual fees versus the budget periodically throughout the year by category of service. During the year, circumstances may arise when it may become necessary to engage the independent registered public accounting firm for additional services not contemplated in the original pre-approval. In those instances, the board of directors requires specific pre-approval before engaging the independent registered public accounting firm.

The board of directors may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the audit board of directors at its next scheduled meeting.

The services described above for 2012 and 2011 provided by Deloitte were approved by the board of directors pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

1. Financial Statements. Reference is made to the Index to Consolidated Financial Statements at Item 8 of this annual report on Form 10-K.

2. Financial Statement Schedules. All schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes to the financial statements.

3. Exhibits.

Description of Exhibits

Number Exhibit No.	Description
2.1	Agreement and Plan of Conversion between Milagro Mezz, LLC and Milagro Holdings, LLC dated October 8, 2009 (incorporated by reference to Exhibit 2.5 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
2.2	Certificate of Conversion of Milagro Mezz, LLC dated October 8, 2009 (incorporated by reference to Exhibit 2.6 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
3.1	Certificate of Incorporation of Milagro Mezz, Inc. dated October 8, 2009 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 of Milagro Oil &Gas, Inc. filed on October 27, 2011).
3.2	Certificate of Amendment to Certificate of Incorporation of Milagro Mezz, Inc. dated January 11, 2010 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
3.3	Certificate of Designation of Milagro Mezz, Inc. dated January 13, 2010 (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-4 of Milagro Oil &Gas, Inc. filed on October 27, 2011).
3.4	Certificate of Amendment to Certificate of Incorporation of Milagro Mezz, Inc. dated February 24, 2011 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
3.5	Certificate of Amendment to Certificate of Incorporation of Milagro Mezz, Inc. dated May 11, 2011 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
3.6	Bylaws of Milagro Mezz, Inc. dated October 8, 2009 (incorporated by reference to Exhibit 3.6 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
3.7	First Amendment to Bylaws of Milagro Mezz, Inc. dated August 18, 2010 (incorporated by reference to Exhibit 3.7 to the Registration Statement on Form S-4 of Milagro Oil &Gas, Inc. filed on October 27, 2011).
4.1	Indenture dated as of May 11, 2011 by and among Milagro Oil & Gas, Inc., the guarantors named therein, and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
4.2	Stockholders’ Agreement of Milagro Mezz, Inc. dated January 13, 2010 (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-4 of Milagro Oil &Gas, Inc. filed on October 27, 2011).
4.3	First Amendment to Stockholders’ Agreement of Milagro Mezz, Inc. dated August 30, 2010 (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).

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Number Exhibit No.	Description
10.1	Monitoring Agreement dated as of November 30, 2007 among Milagro Holdings, LLC, Acon Funds Management, L.L.C., Guggenheim Corporate Funding, LLC and West Coast Energy Management Partners LLC (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
10.2	Amended and Restated First Lien Credit Agreement dated as of May 11, 2011 among Milagro Exploration, LLC and Milagro Producing, LLC, as borrowers, Milagro Oil & Gas, Inc., as guarantor, Wells Fargo Bank, N.A., as administrative agent, issuer and swing line lender, and the lenders from time to time parties thereto (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-4 of Milagro Oil &Gas, Inc. filed on October 27, 2011).
10.3	Employment Agreement of Robert D. LaRocque dated January 1, 2011 (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
10.4	Employment Agreement of Gary Mabie dated May 14, 2010 (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
10.5	Employment Agreement of Marshall L. Munsell dated November 30, 2007 (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
10.6	Employment Agreement of Thomas C. Langford dated November 30, 2007 (incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-4 of Milagro Oil & Gas, Inc. filed on October 27, 2011).
10.7	Consulting Agreement among Milagro Oil & Gas, Inc., Milagro Holdings, LLC and Sequitur Energy Management II, LLC dated October 3, 2012 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Milagro Oil & Gas, Inc. filed on November 13, 2012).
10.8	Severance Agreement and Mutual Relapse between Milagro Holdings, LLC and James G. Ivey dated effective December 27, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K/A of Milagro Oil & Gas, Inc. filed on January 3, 2013).
21.1*	Subsidiaries of Milagro Oil & Gas, Inc.
31.1*	Certification of Principal Executive Officer. pursuant to Rule 13a-14(a)/Rule 15d-4(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Principal Financial Officer. pursuant to Rule 13a-14(a)/Rule 15d-4(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1*	Certification of Principal Executive Officer. pursuant to Rule 13a-14(b)/Rule 15d-4(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2*	Certification of Principal Financial Officer. pursuant to Rule 13a-14(b)/Rule 15d-4(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
99.1*	Reserve report letter as of December 31, 2012, as prepared by W.D. Von Gonten & Co.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed herewith.

+ Management contract or compensatory plan or arrangement.

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GLOSSARY OF OIL & GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this prospectus. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.

3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.

BBbl. One billion Bbls.

Bcf. One billion cubic feet of natural gas.

Boe. One barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGL.

Boe/d. Boe per day.

Completion. The installation of permanent equipment for the production of oil or natural gas. Completion of the well does not necessarily mean the well will be profitable.

Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or natural gas well.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Fault. A break in the rocks along which there has been movement of one side relative to the other side.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGL.

MBoe/d. MBoe per day.

Mcf. One thousand cubic feet of natural gas.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGL.

MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

MMcf. One million cubic feet of natural gas.

Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest we own.

Net Production. Production that we own less royalties and production due others.

Oil. Crude oil, condensate or other liquid hydrocarbons.

Operator. The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.

Pay. The vertical thickness of an oil and natural gas producing zone. Pay can be measured as either gross pay, including non-productive zones or net pay, including only zones that appear to be productive based upon logs and test data.

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Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized Measure. The after-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Trend. A geographical area that has been known to contain certain types of combinations of reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons.

Undeveloped Acreage. Acreage which is not allocated or assignable to producing wells or wells capable of production.

Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	MILAGRO OIL & GAS, INC.
Date: March 28, 2013	By:	/s/ Gary J. Mabie
		Name: Gary J. Mabie
		Title: President and Chief Operating Officer (Principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity In Which Signed	Date
/s/ Gary J. Mabie	President and Chief Operating  Officer	March 28, 2013
Gary J. Mabie	(Principal executive officer)
/s/ Robert D. LaRocque	Chief Financial Officer and Treasurer	March 28, 2013
Robert D. LaRocque	(Principal financial officer)
/s/ Robert D. LaRocque	Chief Financial Officer and Treasurer	March 28, 2013
Robert D. LaRocque	(Principal accounting officer)
/s/ Jonathan Ginns	Director	March 28, 2013
Jonathan Ginns
/s/ Mo Bawa	Director	March 28, 2013
Mo Bawa
/s/ Thomas J. Hauser	Director	March 28, 2013
Thomas J. Hauser
/s/ Adam Cohn	Director	March 28, 2013
Adam Cohn

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Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

The registrant has not sent, and does not expect to send, an annual report or proxy statement to its security holders.

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