Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

10-Q 1 d398023d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012

¨	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 of Incorporation)		(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: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark 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.

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

As of November 13, 2012, there were 280,400 shares of the registrant’s common stock, par value $.01 per share, outstanding.

Table of Contents


	Page
PART I. Financial Information

Item 1. Financial Statements (Unaudited)		2

Unaudited Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011		2

Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011		3

Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011		4

Notes to the Unaudited Condensed Consolidated Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		15

Item 3. Quantitative and Qualitative Disclosure about Market Risk		29

Item 4. Controls and Procedures		32

PART II. Other Information

Item 1. Legal Proceedings		33

Item 1A. Risk Factors		33

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 3. Defaults Upon Senior Securities		33

Item 4. Mine Safety Disclosure		33

Item 5. Other Information		33

Item 6. Exhibits		34

PART I

Item 1.

Financial Statements

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	802		$	9,356
Accounts receivable:
Oil and gas sales		18,785			22,288
Joint interest billings and other — net of allowance for doubtful accounts of $451 and $831 at September 30, 2012 and December 31, 2011, respectively		1,444			1,124
Derivative assets		3,958			11,405
Prepaid expenses		5,828			2,076
Other		656			965

Total current assets		31,473			47,214
PROPERTY, PLANT AND EQUIPMENT:
Oil, NGL and natural gas properties — full cost method:
Proved properties		1,306,686			1,279,276
Unproved properties		14,994			14,914
Less accumulated depreciation, depletion and amortization		(865,282	)		(812,364	)

Net oil, NGL and natural gas properties		456,398			481,826
Other property and equipment, net of accumulated depreciation of $6,695 and $6,114 at September 30, 2012 and December 31, 2011, respectively		860			1,236

Net property, plant and equipment		457,258			483,062
DERIVATIVE ASSETS		1,626			6,875

OTHER ASSETS:
Deferred financing cost		6,352			7,856
Advance to affiliate		2,497			2,391
Other		9,781			6,379

Total other assets		18,630			16,626

TOTAL	$	508,987		$	553,777

LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable	$	4,410		$	4,875
Accrued liabilities		32,617			33,185
Accrued interest payable		10,778			4,074
Derivative liabilities		1,336			5,186
Asset retirement obligation		4,563			3,199

Total current liabilities		53,704			50,519
NONCURRENT LIABILITIES:
Long term debt (Note 7)		358,918			381,879
Asset retirement obligation		42,409			41,441
Derivative liabilities		548			853
Other		5,711			3,931

Total noncurrent liabilities		407,586			428,104
Total liabilities		461,290			478,623

MEZZANINE EQUITY
Redeemable series A preferred stock (Note 9)		235,410			234,558

COMMITMENT AND CONTINGENCIES (Note 12)
STOCKHOLDERS’ DEFICIT:
Common stock (par value, $.01 per share; shares authorized: 1,000,000; shares issued and outstanding: 280,400 as of September 30, 2012 and December 31, 2011)		3			3
Additional paid-in capital		(66,813	)		(66,813	)
Accumulated deficit		(120,903	)		(92,594	)

Total stockholders’ deficit		(187,713	)		(159,404	)
TOTAL	$	508,987		$	553,777

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES:
Oil, NGL and natural gas revenues	$	29,247		$	32,112		$	91,853		$	101,577
(Loss) /Gain on commodity derivatives, net		(9,448	)		25,883			9,100			22,318

Total revenues		19,799			57,995			100,953			123,895

COSTS AND EXPENSES:
Gathering and transportation		393			371			1,195			1,068
Lease operating		8,876			8,324			27,145			26,915
Environmental remediation		—			5			—			1,988
Taxes other than income		2,764			2,611			8,616			6,895
Depreciation, depletion and amortization		12,754			12,320			38,859			37,451
Full cost ceiling impairment		3,088			—			14,641			—
General and administrative		3,351			3,200			9,187			10,322
Accretion		938			798			2,757			2,371

Total costs and expenses		32,164			27,629			102,400			87,010

Operating (loss)/ income		(12,365	)		30,366			(1,447	)		36,885

OTHER EXPENSE (INCOME):
Net gain on interest rate derivatives		—			(2,767	)		—			(1,854	)
Other income		(18	)		(339	)		(169	)		(408	)
Interest and related expenses, net of amounts capitalized		9,165			8,444			27,033			32,502
Loss on extinguishment of debt		—			—			—			1,027

Total other expense		9,147			5,338			26,864			31,267

(LOSS)/INCOME BEFORE INCOME TAX		(21,512	)		25,028			(28,311	)		5,618

INCOME TAX EXPENSE		—			—			—			—

NET (LOSS)/INCOME		(21,512	)		25,028			(28,311	)		5,618

Preferred dividends		8,128			7,318			23,550			11,162

NET (LOSS)/INCOME AVAILABLE TO COMMON STOCKHOLDERS	$	(29,640	)	$	17,710		$	(51,861	)	$	(5,544	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss)/ income	$	(28,311	)	$	5,618
Adjustments to reconcile net (loss)/income to cash provided by operating activities:
Depreciation, depletion and amortization		38,859			37,451
Full cost impairment		14,641			—
Amortization of deferred financing costs		1,504			1,422
Loss on extinguishment of debt		—			1,027
Accretion of asset retirement obligations		2,757			2,371
PIK note interest		—			10,015
Accretion of financing costs		1,891			1,429
Unrealized (gain)/loss on commodity derivatives		8,542			(9,770	)
Unrealized gain on interest rate derivatives		—			(3,510	)
Changes in assets and liabilities — net of acquisitions:
Accounts receivable and accrued revenue		3,183			652
Prepaid expenses and other		(3,299	)		(1,041	)
Accounts payable and accrued liabilities		1,729			2,245
Other		(490	)

Net cash provided by operating activities		41,006			47,909
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil, NGL and natural gas properties		(37	)		(29,696	)
Additions to oil, NGL and natural gas properties		(25,338	)		(54,076	)
Additions of other long term assets		(205	)		(175	)
Net sales of oil, NGL and natural gas properties		135			37

Net cash used in investing activities		(25,445	)		(83,910	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		47,250			395,955
Credit facility payments		(71,250	)		(362,693	)
Deferred financing costs paid		—			(9,352	)
Other		(115	)		—

Net cash (used in) provided by financing activities		(24,115	)		23,910

NET DECREASE IN CASH AND CASH EQUIVALENTS	$	(8,554	)	$	(12,091	)

CASH AND CASH EQUIVALENTS — Beginning of period	$	9,356		$	17,734

CASH AND CASH EQUIVALENTS — End of period	$	802		$	5,643

INCOME TAX PAID, Net of refunds	$	—		$	—

INTEREST PAID — Net of interest capitalized of $786 and $803 in 2012 and 2011, respectively	$	16,480		$	10,649

SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Recapitalization:
Interest paid in kind — series A preferred stock	$	—		$	9,800

Interest paid in kind — second lien	$	—		$	214

Accrued capital costs included in proved properties	$	6,371		$	10,540

Asset retirement obligations incurred	$	715		$	2,105

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

1.	ORGANIZATION

Milagro Oil & Gas, Inc. (the “Company” or “Milagro”) is an independent oil 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 unaudited condensed 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.

The unaudited condensed consolidated financial statements of the Company, included herein, have been prepared by management without audit, and they reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). However, management believes that the disclosures included either on the face of the financial statements or in these notes are sufficient to make the interim information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2011. The operating results for the three months and nine months ended September 30, 2012 are not necessarily indicative of the results to be expected for the full year.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of critical accounting policies is disclosed in Note 3 to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011. Our critical accounting policies are further described under the caption “Critical Accounting Policies” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K. There have been no changes to our significant accounting policies since such date.

Impairment — Full cost ceiling impairment is calculated whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. The full cost ceiling limitation is calculated using 12-month simple average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. Price and operating costs, which are based on current cost conditions, are held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the consolidated statements of operations. An impairment of approximately $3.0 million was recorded for the three months ended September 30, 2012 and approximately $14.6 million was recorded for the nine months ended September 30, 2012. Given the nature of the ceiling test, and the low natural gas prices experienced during 2012 to date, it is reasonably possible that we could have material ceiling charges in the future.

Recently Issued Accounting Pronouncements —

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 standard effective January 1, 2012, and it did not have 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 is currently evaluating the potential impact of this adoption but expects that the adoption of this standard will have no impact on its consolidated financial statements.

3.	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 nine months ended September 30, 2012 and 2011, the Company’s most significant customers by reference to oil, NGL and natural gas revenue were as follows:


	2012			2011
Shell Trading (US) Company		22	%		18	%
Enterprise Crude Oil, LLC		18	%		16	%
Smaller customers		60	%		66	%

4.	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 nine months ended September 30, 2012 is as follows (in thousands):


Liability for asset retirement obligation — December 31, 2011	$	44,640
Settlements		(2,008	)
Additions		715
Revisions		868
Accretion expense		2,757

Liability for asset retirement obligation — September 30, 2012	$	46,972

The liability comprises a current balance of approximately $4.6 million and a noncurrent balance of approximately $42.4 million as of September 30, 2012.

Revisions to asset retirement obligations reflect changes in abandonment cost estimates based on current information and consideration of the Company’s current plans.

5.	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 condensed consolidated statement of operations within a single income statement line item. For the nine months ended September 30, 2012, the Company had commodity derivatives in place for 1,567.8 MBoe, or approximately 78% of production, in the form of oil, NGL and natural gas collars and swaps.

Periodically the Company evaluates the unrealized commodity derivatives to determine if it would be beneficial to liquidate any contracts early. In March 2012, the Company liquidated a portion of a natural gas contract for the period from April 2012 through and including September 2012 resulting in cash proceeds of approximately $2.0 million to the Company. The Company re-priced a combination of oil and natural gas derivative contracts in June 2012, which resulted in a realized gain of approximately $3.0 million to the Company. In September 2012, the Company monetized a combination of NGL and natural gas derivative contracts, which resulted in a realized gain of approximately $5.0 million to the Company.

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 West Texas Intermediate (“WTI”) prices. These volumes are disclosed as oil commodity derivative volumes. As of September 30, 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.

All derivative contracts are recorded at fair market value and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts (in thousands):


		Fair Value
Description	Location in Balance Sheet	September 30, 2012		December 31, 2011
Asset derivatives:
Natural gas collars and swaps — current portion	Derivative assets — current	$	3,431	$	11,405
Noncurrent portion	Derivative assets — noncurrent		401		5,897
Oil collars and swaps — noncurrent portion	Derivative assets — noncurrent		1,225		978
NGL collars and swaps — current portion	Derivative assets — current		527		—

		$	5,584	$	18,280

Liability derivatives:
Oil collars and swaps — current portion	Derivative liabilities — current	$	1,293		4,677
NGL collars and swaps — current portion	Derivative liabilities — current		43		509
Oil collars and swaps — noncurrent portion	Derivative liabilities — noncurrent		152		853
Natural gas collars and swaps — noncurrent portion	Derivative liabilities — noncurrent		396		—

		$	1,884	$	6,039

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


Description	Location in Statements of Operations	Three Months Ended September 30,						Nine Months Ended September 30,
		2012			2011			2012			2011
		(in thousands)
Commodity contracts:
Realized gain on commodity contracts	(Loss)/Gain on commodity derivatives, net	$	6,958		$	1,815		$	17,642		$	12,548
Unrealized (loss)/gain on commodity contracts	(Loss)/Gain on commodity derivatives, net		(16,406	)		24,068			(8,542	)		9,770


Total net (loss)/gain on commodity contracts		$	(9,448	)	$	25,883		$	9,100		$	22,318
Interest rate swaps:
Realized (gain)/loss on interest rate swaps	Net (gain) on interest rate derivatives	$	—		$	(1,069	)	$	—		$	1,656
Unrealized gain on interest rate swaps	Net gain on interest rate derivatives		—			(1,698	)		—			(3,510	)

Total net (gain)/loss on interest rate swaps			—			(2,767	)		—			(1,854	)

Total net gain/(loss) on derivative contracts		$	(9,448	)	$	28,650		$	9,100		$	24,172

At September 30, 2012, the Company had the following natural gas collar positions:


	Collars
	Floors						Ceilings
Period	Volume in MMbtu’s		Price/ Price Range		Weighted- Average Price		Price/ Price Range		Weighted- Average Price
Oct 2012 – Dec 2012		975,000	$	3.45 – 6.50	$	4.98	$	3.81 – 8.10	$	6.03
Jan 2013 – Dec 2013		1,080,000		3.50		3.50		5.75		5.75
Jan 2014 – Dec 2014		1,292,020		4.50 – 5.10		4.72		6.15 – 6.20		6.17

At September 30, 2012, the Company had the following natural gas swap positions:


	Swaps
Period	Volume in MMbtu’s		Price/ Price Range		Weighted- Average Price
Oct 2012 – Dec 2012		733,798	$	3.04 – 5.15	$	4.61
Jan 2013 – Dec 2013		2,400,000		3.65 – 4.66		4.15
Jan 2014 – Dec 2014		2,100,000		3.82 – 3.93		3.88

At September 30, 2012, the Company had the following unexecuted natural gas swaption positions:


	Swaptions
Period	Volume in MMbtu’s		Price
Jan 2014 – Dec 2014		1,200,000	$	4.66
Jan 2015 – Dec 2015		900,000		4.99

At September 30, 2012, the Company had the following crude oil collar positions:


	Collars
	Floors						Ceilings
Period	Volume in Bbl’s		Price/ Price Range		Weighted- Average Price		Price/ Price Range		Weighted- Average Price
Oct 2012 – Dec 2012		143,754	$	80.00 – 92.00	$	83.01	$	86.00 – 102.05	$	91.23
Jan 2013 – Dec 2013		348,000		90.00 – 93.00		91.41		97.00 – 111.85		102.71
Jan 2014 – Dec 2014		276,000		90.00 – 93.00		92.13		97.00 – 101.00		99.24

At September 30, 2012, the Company had the following crude oil swap positions:


	Swaps
Period	Volume in Bbl’s		Price/ Price Range		Weighted- Average Price
Oct 2012 – Dec 2012		19,913	$	94.95 – 96.95	$	95.01
Jan 2013 – Dec 2013		197,256		83.00 – 94.95		91.19
Jan 2014 – Dec 2014		24,000		91.00 – 91.50		91.25

At September 30, 2012, the Company had the following crude basis (LLS-WTI) swap positions:

Basis Swaps

Period

Volume
in Bbl’s

Price /
Price Range

Weighted-
Average
Price

Oct 2012 – Dec 2012

119,600

6.60 – 10.75

9.15

At September 30, 2012, the Company had the following natural gas liquids swap positions:


	Swaps
Period	Volume in Bbl’s(a)		Price/Price Range		Weighted- Average Price
Oct 2012 – Dec 2012		44,522	$	47.55 – 52.40	$	51.17
Jan 2013 – Dec 2013		102,000		38.90		38.90
Jan 2014 – Dec 2014		85,200		38.24		38.24

(a)	NGL commodity derivative volumes are based on a blended barrel of liquids that consists of 41% ethane, 29% propane, 7% normal butane, 11% isobutane, and 12% natural gasoline. This blended barrel is an approximation of our actual NGL production volumes.

6.	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 September 30, 2012 and December 31, 2011, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

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		Significant Other Observable Inputs		Significant Unobservable Inputs		Reclassification (a)			Total Balance
	(Level 1)		(Level 2)		(Level 3)		Reclassification (a)			Total Balance
September 30, 2012:
Current Assets
Commodity derivatives — natural gas	$	—	$	3,614	$	—	$	(183	)	$	3,431
Commodity derivatives — oil		—		864		—		(864	)		—
Commodity derivatives — NGL		—		650		—		(123	)		527
Non-Current Assets
Commodity derivatives — natural gas	$	—	$	1,260	$	—	$	(859	)	$	401
Commodity derivatives — oil		—		1,344		—		(119	)		1,225
Commodity derivatives — NGL		—		—		—		—			—
Current Liabilities
Commodity derivatives — natural gas	$	—	$	183	$	—	$	(183	)	$	—
Commodity derivatives — oil		—		2,157		—		(864	)		1,293


	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Quoted Once in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Reclassification (a)			Total Balance
	(Level 1)		(Level 2)		(Level 3)		Reclassification (a)			Total Balance
Commodity derivatives — NGL		—		166		—		(123	)		43
Non-Current Liabilities
Commodity derivatives — natural gas	$	—	$	1,255	$	—	$	(859	)	$	396
Commodity derivatives — oil		—		119		—		(119	)		—
Commodity derivatives — NGL		—		152		—		—			152

December 31, 2011:
Current Assets
Commodity derivatives — natural gas	$	—	$	11,635	$	—	$	(230	)	$	11,405
Commodity derivatives — oil		—		1,750		—		(1,750	)		0
Commodity derivatives — NGL		—		1,555		—		(1,555	)		0
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	)		0
Current Liabilities
Commodity derivatives — natural gas	$	—	$	230	$	—	$	(230	)	$	0
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	)	$	0
Commodity derivatives — oil		—		6,989		—		(6,989	)		0
Commodity derivatives — NGL		—		2,626		—		(1,773	)		853

(a)	Represents the effects of reclassification of the assets and liabilities per master netting agreements to conform to the balance sheet presentation.

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 September 30, 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 7) 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 7) 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 September 30, 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 September 2012 weighted average market price) to be approximately $184.3 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, Trade Receivables, and Payables — The fair value approximates carrying value given the short term nature of these investments.

DEBT

The Company’s debt as of September 30, 2012 and December 31, 2011, was comprised of the following amounts (in thousands):


	September 30, 2012			December 31, 2011
First lien Indebtedness — non-current	$	114,000		$	138,000
Notes — non-current		250,000			250,000
Unamortized discount — non-current		(5,082	)		(6,121	)

Total debt	$	358,918		$	381,879

Scheduled maturities or mandatory redemption dates by fiscal year are as follows (amounts in thousands):


Years Ending December 31	Amount
2012	$	—
2013		—
2014		114,000
2015		—
2016		250,000

	$	364,000

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 also includes a $10.0 million sub facility for standby letters of credit, of which approximately $1.6 million has been issued as of September 30, 2012, and a discretionary swing line subfacility of $5.0 million. As of September 30, 2012, the borrowing base for this facility was $165 million with semi-annual re-determinations. A 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. 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 September 30, 2012, the LIBOR based interest rates ranged from 3.62% to 3.70% and the ABR interest rate was 5.50%. Borrowings under the 2011 Credit Facility are secured by all of the Company’s oil and natural gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 Credit Facility will mature, in November 2014.

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 1.64 as of September 30, 2012), minimum interest coverage ratio, as defined, of not less than 2.50 to 1.0 (which was 2.74 as of September 30, 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 September 30, 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 1.32 as of September 30, 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 be in compliance with the financial covenant at the applicable dates. Unless the Company is able to execute one or more of these alternatives, the Company’s maximum leverage ratio may not meet the reduced threshold in the covenants beginning on March 31, 2013. In that event, the Company would have to seek a waiver or amendment to these agreements and, if not granted, the lenders could declare a default and the Company will not be able to borrow additional funds under the facility. Accordingly, there is substantial doubt of the Company’s ability to continue as a going concern. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. As of September 30, 2012, the Company is not aware of any instances of noncompliance with the financial covenants governing the 2011 Credit Facility.

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 September 30, 2012 and December 31, 2011, the Company had deferred financing fees of approximately $6.4 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 three months ended September 30, 2012 and 2011, the Company capitalized interest of approximately $0.3 million and $0.4 million, respectively. In both the nine months ended September 30, 2012 and 2011, the Company capitalized interest of approximately $0.8 million.

Senior Secured Second Lien Notes — During 2011, the Company 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”). The Notes carry a stated 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 of the Company. The outstanding balance of the Notes is presented net of amortized discount of approximately $5.1 million at September 30, 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 110.500% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.500%, 102.625% and 100.000% 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 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.

8.	GUARANTOR AND NON-GUARANTOR CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

The Company is not required to disclose consolidating financial information as its parent company has no independent assets or operations and the Company owns 100% of Milagro Exploration, LLC, Milagro Producing, LLC, 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 unaudited condensed consolidated financial statements.

9.	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 September 30, 2012 the dividends in arrears were approximately $42.2 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 September 30, 2012 and at December 31, 2011 was approximately $212.5 million and $183 million, respectively.

10.

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 September 30, 2012, 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; share ratably in the distribution of assets remaining after payment of liabilities. Holders of Common Stock have no cumulative rights. The holders of a plurality of the outstanding shares of the Common Stock have the ability to elect all of the directors. Holders of Common Stock have no preemptive or other rights to subscribe for shares. Holders of Common Stock are entitled to such dividends as may be declared by the Company’s board of directors 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.

11.

INCOME TAXES

The Company recorded no income tax benefit for the nine months ended September 30, 2012. The Company increased its valuation allowance and reduced its net deferred tax assets to zero during 2010 after considering all available positive and negative evidence related to the realization of its deferred tax assets. The Company’s assessment of the realization of its deferred tax assets has not changed and as a result, the Company continues to maintain a full valuation allowance for its net deferred assets as of September 30, 2012.

As of September 30, 2012, the Company had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2011. The Company does 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 September 30, 2012.

12.

COMMITMENTS AND CONTINGENCIES

Commitments:

The Company leases corporate office space in Houston, Texas. Rental expense was approximately $0.4 million for the three months ended September 30, 2012 and 2011, and was approximately $1.3 million for the nine months ended September 30, 2012 and 2011.

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 2013. The Company paid approximately $0.3 million of these fees to the investment bank in connection with the Company’s refinancing completed in 2011.

The following table summarizes the Company’s contractual obligations and commitments at September 30, 2012, by fiscal year (amounts in thousands):


	2012		2013		2014		2015		2016		Thereafter		Total
Office lease	$	466	$	1,884	$	1,913	$	1,913	$	1,913	$	1,275	$	9,364
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.

13.

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 approximately $128,000 and $122,000, for the three months ended September 30, 2012 and 2011, respectively. For the nine months ended September 30, 2012 and 2011, the Company contributed approximately $509,000 and $484,000, respectively.

14.

RELATED PARTY TRANSACTIONS

As of September 30, 2012 and December 31, 2011, the Company had a receivable of approximately $2.5 million and $2.4 million, respectively, primarily related to monitoring fees paid on behalf of Parent, to certain of 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 sheet.

15.

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.

16.

SUBSEQUENT EVENTS

On October 3, 2012, the Company entered into a consulting agreement (the “Consulting Agreement”) with its Parent, and Sequitur Energy Management II, LLC (“Sequitur”). Under the Consulting Agreement, Sequitur will provide the Company with operational advice and expertise and will also be available to assist in the management of the oil and natural gas assets of the Company and its subsidiaries.

The Consulting Agreement provides Sequitur a fixed fee of approximately $1.8 million per year during the term of the Consulting Agreement. Additionally, Sequitur is entitled to receive an incentive fee based on a formula described in the Consulting Agreement. The Company and Sequitur each have the right to terminate the Consulting Agreement upon the occurrence of certain events. Each have the right to terminate on 270 days’ notice for any reason, but if the Company terminates using such provision, it must pay Sequitur a termination fee of approximately $0.5 million, in addition to continuing to pay the fixed fee during the 270 day period.

Item 2.

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 in our annual report on form 10-K for the year ended December 31, 2011, as well as our quarterly reports for the periods ended March 31, 2012 and June 30, 2012, and in this report, for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

Overview

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

During the nine months ended September 30, 2012, we spent approximately $24.7 million on capital expenditures, before divestitures, to support our business plan. Of this amount, we spent approximately $12.7 million to successfully drill ten gross wells and complete eight of these wells. We drilled five gross (5.0 net) and completed five gross (5.0 net) wells in the Texas Gulf Coast area, drilled two gross (0.31 net) wells in our South Texas area and drilled three gross wells (1.41 net) in our Midcontinent area. We spent approximately $9.0 million on workovers and recompletions primarily in our Texas Gulf Coast and South Louisiana areas. We spent approximately $1.6 million to continue lease acquisitions. We spent approximately $1.1 million of capital expenditures primarily related to seismic, facilities and vehicles. We spent approximately $0.3 million in excess of insurance proceeds received, related to damage from Hurricane Ike for our plugging and abandonment costs.

We contemplate spending approximately an additional $4.5 million in the remainder of 2012 to support our business plan. We are planning to complete one carryover well and drill or participate in up to five additional wells during the remainder of 2012, including one non-operated development well and one non-operated exploratory well in our South Texas area; one operated exploratory well, one non-operated exploratory well and one non-operated development well in our Southeast area, as well as planning on workover and recompletion projects of existing wells. Our original 2012 capital budget of approximately $54.2 million included approximately $25.0 million for acquisitions. However, we do not anticipate using the funds and therefore revised our 2012 capital budget to remove the capital associated with acquisitions, leaving us with a 2012 budget of approximately $29.2 million which was approved by the board. In light of the price volatility we have experienced this year, we are constantly evaluating the deployment of our capital. See “Liquidity and Capital Resources” for more on our capital expenditures.

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 debt and/or equity securities. See “Liquidity and Capital Resources” for more discussion.

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 September 30, 2012, we had the following oil, NGL and natural gas commodity derivative positions:

% of PDP Hedged


Year	Oil	Natural Gas	NGL
2012	89.4%	89.3%	85.6%
2013	89.0%	53.6%	55.6%
2014	61.0%	65.6%	55.3%

In our effort to achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to manage risk of future sales prices on a portion of our oil, NGL and natural gas production. As of September 30, 2012, we had commodity derivative contracts in place for 493.0 MBoe from October 1, 2012, through the end of 2012, 1,227.3 MBoe during 2013 and 950.5 MBoe during 2014. Based on the expected production set forth in our June 30, 2012 reserve report, we have derivative contracts for approximately 67.8% of our cumulative forecasted 2012, 2013 and 2014 PDP production as of September 30, 2012. For the nine months ended September 30, 2012, we had commodity derivative revenues of approximately $9.1 million, which is comprised of approximately $17.6 million in realized gains and approximately $8.5 million of unrealized losses. 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.

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.

•

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 production taxes. 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 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 resulting 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 general and administrative 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.

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 September 30, 2012, we had approximately $114.0 million of LIBOR-based floating rate indebtedness and base rate indebtedness outstanding under our 2011 Credit Facility and $250 million of the Senior Secured Second Lien Notes due 2016 (the “Notes”) outstanding. In addition, our Series A preferred stock carries a non-cash cumulative dividend with a coupon of 12% per annum.

The 2011 Credit Facility provided for a borrowing base of $165 million at September 30, 2012. A 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. 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 of the 2011 Credit Facility, the higher the interest margin is 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 September 30, 2012, we had approximately $358.9 million outstanding of total indebtedness.

Income Taxes. We recorded no income tax benefit or expense for the nine months ended September 30, 2012. Prior to 2011, we increased our valuation allowance and reduced our net deferred tax assets to zero, 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 September 30, 2012.

As of September 30, 2012, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2011. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to September 30, 2012.

Oil, NGL and Natural Gas Reserves

Our estimated total net proved reserves of oil, NGL and natural gas as of September 30, 2012 and 2011 were as follows:


	As of September 30,
	2012			% Change			2011
Estimated Net Proved Reserves:
Oil (MMBbls)		10.6			12	%		9.5
NGL (MMBbls)		4.7			18	%		4.4
Natural Gas (Bcf)		110.6			(22	)%		141.0

Total oil equivalent (MMBoe)		33.7			(10	)%		37.4
Proved developed reserves as a percentage of net proved reserves		60	%					64	%

Our estimated total net proved reserves decreased in the period ended September 30, 2012 as compared to the same period in 2011 by 3.7 MMBoe or a 10% decrease. The decrease was primarily due to production and price decreases.

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 unaudited condensed consolidated financial statements and the related notes thereto contained elsewhere in this report. Comparative results of operations for the periods indicated are discussed below.

Sales Volumes

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011


	Three Months Ended September 30,
	2012		% Change			2011
Oil (MBbls)		213		14	%		187
NGL (MBbls)		63		9	%		58
Natural gas (MMcf)		2,169		(20	)%		2,726

Total (MBoe)		638		(9	)%		699
Average daily production volumes (MBoe/d)(a)		6.9		(9	)%		7.6

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

For the three months ended September 30, 2012, our net equivalent production volumes decreased by 9% to 638 MBoe (6.9 MBoe/d) from 699 MBoe (7.6 MBoe/d) in 2011. Our production volumes in 2012, as compared to 2011, decreased primarily as a result of the natural decline in production and the delay of scheduled gas drilling projects due to marginal natural gas prices. Natural gas represented approximately 57% and 65% of our total production in the three months ended September 30, 2012 and 2011, respectively.

Revenues. The following tables show (1) our revenues from the sale of oil, NGL and natural gas and (2) the impact of changes in price and sales volumes on our oil, NGL and natural gas revenues during the three months ended September 30, 2012 and 2011. 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 condensed 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.


	Three Months Ended September 30,
	2012			% Change			2011
	(In thousands)
Oil revenues:
Oil revenues		21,540			19	%	$	18,157
Oil derivative settlements		(1,173	)		161	%		(450	)

Oil revenues including oil derivative settlements		20,367			15	%		17,707
NGL revenues:
NGL revenues		1,801			(37	)%		2,857
NGL derivative settlements		1,697			(2671	)%		(66	)

NGL revenues including derivative settlements		3,498			25	%		2,791
Natural gas revenues:
Natural gas revenues		5,906			(47	)%		11,098
Natural gas derivative settlements		6,434			176	%		2,331

Natural gas revenues including derivative settlements		12,340			(8	)%		13,429
Oil, NGL and natural gas revenues:
Oil, NGL and natural gas revenues		29,247			(9	)%		32,112
Oil, NGL and natural gas derivative settlements		6,958			283	%		1,815

Oil, NGL and natural gas revenues including derivative settlements		36,205			7	%		33,927
Oil, NGL and natural gas derivative unrealized gains		(16,406	)		(168	)%		24,068

Oil, NGL and natural gas revenues including derivative settlements and unrealized gains		19,799			(66	)%		57,995

Total revenues		19,799			(66	)%	$	57,995


	Change from Three Months Ended September 30, 2011 to Three Months Ended September 30, 2012
	(In thousands)
Change in revenues from the sale of oil:
Price variance impact	$	754
Sales volume variance impact		2,629

Total change		3,383
Change in revenues from the sale of NGL:
Price variance impact		(1,227	)
Sales volume variance impact		172

Total change		(1,055	)
Change in revenues from the sale of natural gas:
Price variance impact	$	(3,680	)
Sales volume variance impact		(1,512	)

Total change		(5,192	)
Change in revenues from the sale of oil, NGL and natural gas:
Price variance impact	$	(4,153	)
Volume variance impact		1,289
Cash settlement of commodity derivative contracts		5,143
Unrealized gains (losses) due to commodity derivative contracts		(40,473	)

Total change	$	(38,194	)


	Three Months Ended September 30,
	2012			% Change			2011
Oil price:
Oil price per Bbl		101.13			4	%	$	97.10
Oil derivative settlements per Bbl		(5.51	)		129	%		(2.41	)

Oil revenues including oil derivative settlements per Bbl		95.62			1	%	$	94.69
NGL price:
NGL price per Bbl		28.59			(43	)%	$	50.12
NGL derivative settlements per Bbl		26.93			(2,422	)%		(1.16	)

NGL price including derivative settlements per Bbl		55.52			14	%	$	48.96
Natural gas price:
Natural gas price per Mcf		2.72			(33	)%	$	4.07
Natural gas derivative settlements per Mcf		2.97			245	%		0.86

Natural gas price including derivative settlements per Mcf		5.69			15	%	$	4.93
Oil, NGL and natural gas price per BOE:
Oil, NGL and natural gas price per BOE		45.84			0	%	$	45.94
Oil, NGL and natural gas derivative settlements per BOE		10.90			320	%		2.60

Oil, NGL and natural gas price including derivative settlements per BOE		56.74			17	%	$	48.54
Oil, NGL and natural gas derivative unrealized gains per BOE		(25.71	)		(175	)%		34.43

Oil, NGL and natural gas price including derivative settlements and unrealized gains per BOE		31.03			(63	)%	$	82.97

Total price per BOE		31.03			(63	)%	$	82.97

Our oil, NGL and natural gas revenues, including derivatives settlements and unrealized derivative gains, for the three months ended September 30, 2012 decreased approximately $38.2 million, or 66%, from approximately $58.0 million to approximately $19.8 million, when compared to the same period in 2011. Our oil, NGL and natural gas revenues for the three months ended September 30, 2012 decreased by approximately $2.9 million from approximately $32.1 million to approximately $29.2 million. This decrease related to lower prices of NGL and natural gas of approximately $4.9 million and lower natural gas production of approximately $1.5 million, which was partially offset by higher oil prices of approximately $0.8 million and higher oil and NGL production which increased revenue by approximately $2.8 million. Our derivative loss was approximately $9.4 million for the three months ended September 30, 2012, as compared to our derivative revenues of approximately $25.9 million for the prior period. The decrease in commodity derivative revenues was due to a decrease in unrealized gains of approximately $40.5 million due to prices increases, which was offset by increased gains on settled contracts of approximately $5.1 million.

Production costs. Per unit production cost for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 increased $2.69/Boe, or 16%, and total production costs for the 2012 period, as compared to the 2011 period, increased by approximately $0.7 million, or 6%. Our per unit and total production costs for the three months ended September 30, 2012 and 2011 are as set forth below.


	Unit-of-Production (Per Boe Based on Sales Volumes) Three Months Ended September 30,
	2012		% Change			2011
Production costs:
Gathering & transportation	$	0.62		17	%	$	0.53
Operating & maintenance		13.00		21	%		10.70
Workover expenses		0.92		(24	)%		1.21

Lease operating expenses		14.54		17	%		12.44
Remediation expenses		—		(100	)%		0.01
Taxes other than income		4.33		16	%		3.74

Production costs	$	18.87		16	%	$	16.19


	Production Costs
	Three Months Ended September 30,
	2012		% Change			2011
	(In thousands)
Production costs:
Gathering & transportation	$	393		6	%	$	371
Operating & maintenance		8,291		11	%		7,477
Workover expenses		585		(31	)%		847
Lease operating expenses		9,269		7	%		8,695
Remediation expenses		—		(100	)%		5
Taxes other than income		2,764		6	%		2,611

Production costs	$	12,033		6	%	$	11,311

Gathering and transportation costs for the three months ended September 30, 2012 and September 30, 2011 were approximately $0.4 million.

Operating and maintenance expenses for the three months ended September 30, 2012 were approximately $8.3 million, compared to approximately $7.5 million in the 2011 period, an increase of approximately $0.8 million, or 11%. This increase in operating and maintenance expenses was due primarily to higher cost associated with pressure safety valve inspections and other repair costs.

Workover expenses for the three months ended September 30, 2012 were approximately $0.6 million, compared to approximately $0.8 million in the 2011 period, a decrease of approximately $0.2 million, or 31%. This decrease in workover expenses was due primarily to a decrease in the number and cost of our workovers in 2012 as compared to 2011.

Taxes other than income for the three months ended September 30, 2012 were approximately $2.8 million, compared to approximately $2.6 million in the 2011 period, an increase of approximately $0.2 million, or 6%. This increase in taxes was due to higher actual ad valorem taxes incurred in the current year.

General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized expenses include the expenses 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 three months ended September 30, 2012 and 2011 were as follows:


	Three Months Ended September 30,
	2012		% Change			2011
	(In thousands, except per unit measurements which are based on sales volumes)
General and administrative expenses — gross	$	4,500		4	%	$	4,328
Capitalized general and administrative expenses		1,149		2	%		1,128

General and administrative expenses — net	$	3,351		5	%	$	3,200

General and administrative expenses — gross $ per Boe	$	7.05		14	%	$	6.19

Our gross general and administrative expenses for the three months ended September 30, 2012 were approximately $4.5 million compared to approximately $4.3 million in the same period of 2011, an increase of approximately $0.2 million, or 4%, primarily as a result of higher compensation and legal and accounting costs in 2012. After capitalization, our net general and administrative expenses increased by approximately $0.2 million, or 5%, to approximately $3.4 million. Per unit general and administrative expense increased by 14% due to lower production volumes.

Depletion of oil, NGL and natural gas properties.


	Three Months Ended September 30,
	2012		% Change			2011
	(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil, NGL and natural gas properties	$	12,468		3	%	$	12,119
Depletion of oil, NGL and natural gas properties (per Boe)	$	19.54		13	%	$	17.34

Our depletion expense for the three months ended September 30, 2012 was approximately $12.5 million compared to approximately $12.1 million in the same period of 2011, an increase of approximately $0.4 million, or 3%. An increase in our depletion rate, due to a higher depreciable base and lower reserves, contributed to an increase in depletion expense of approximately $1.5 million. This was offset by lower production volumes resulting in lower depletion expense of approximately $1.1 million.

Impairment of oil and natural gas properties. For the three months ended September 30, 2012, based on the average oil and natural gas prices on the first day of each month during the last twelve months ($2.82 per MMBtu for Henry Hub gas and $91.48 per Bbl for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and natural gas properties exceeded the ceiling limit and we recorded an impairment of approximately $3.0 million to our oil and natural gas properties. An impairment of approximately $14.6 million was recorded for the nine months ended September 30, 2012 and an impairment of approximately $18.2 million was recorded for the year ended December 31, 2011.

Net interest expense. Our interest expense for the three months ended September 30, 2012 was approximately $9.2 million or a 10% increase from the approximately $8.4 million of interest expense accrued for the three months ended September 30, 2011. The increase in interest expense during 2012 from 2011 related primarily to higher interest on our 2011 Credit Facility due to a higher outstanding balance during the three months ended September 2012.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Sales Volumes


	Nine Months Ended September 30,
	2012		% Change			2011
Oil (MBbls)		643		11	%		577
NGL (MBbls)		192		11	%		173
Natural gas (MMcf)		7,093		(18	)%		8,616

Total (MBoe)		2,017		(8	)%		2,186

Average daily production volumes (MBoe/d)(a)		7.4		(8	)%		8.0

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

For the nine months ended September 30, 2012 and 2011, our net equivalent production volumes decreased by 8% to 2,017 MBoe (7.4 MBoe/d) from 2,186 MBoe (8.0 MBoe/d) in 2011. Our production volumes in 2012 as compared to 2011 decreased primarily as a result of natural decline in production and due to the delay of scheduled gas drilling projects due to marginal natural gas prices. Natural gas represented approximately 59% and 66% of our total production in the nine months ended September 30, 2012 and 2011, respectively.

Revenues. The following tables shows (1) our revenues from the sale of oil, NGL and natural gas and (2) the impact of changes in price and sales volumes on our oil, NGL and natural gas revenues during the nine months ended September 30, 2012 and 2011. 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. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.


	Nine Months Ended September 30,
	2012			% Change			2011
	(In thousands)
Oil revenues:
Oil revenues	$	67,678			17	%	$	57,969
Oil derivative settlements		(2,704	)		(50	)%		(5,425	)

Oil revenues including oil derivative settlements		64,974			24	%		52,544
NGL revenue:
NGL revenues		7,018			(13	)%		8,078
NGL derivative settlements		2,116			(3306	)%		(66	)

NGL revenues including derivative settlements		9,134			14	%		8,012
Natural gas revenues:
Natural gas revenues		17,157			(52	)%		35,530
Natural gas derivative settlements		18,230			1	%		18,039

Natural gas revenues including derivative settlements		35,387			(34	)%		53,569
Oil, NGL and natural gas revenues:
Oil, NGL and natural gas revenues		91,853			(10	)%		101,577
Oil, NGL and natural gas derivative settlements		17,642			41	%		12,548

Oil, NGL and natural gas revenues including derivative settlements		109,495			(4	)%		114,125
Oil, NGL and natural gas derivative unrealized gains (losses)		(8,542	)		(187	)%		9,770

Oil, NGL and natural gas revenues including derivative settlements and unrealized gains (losses)		100,953			(19	)%		123,895

Total revenues	$	100,953			(19	)%	$	123,895


	Change from Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2012
	(In thousands)
Change in revenues from the sale of oil:
Price variance impact	$	2,758
Sales volume variance impact		6,951

Total change		9,709
Change in revenues from the sale of NGL:
Price variance impact	$	(1,754	)
Sales volume variance impact		694

Total change		(1,060	)
Change in revenues from the sale of natural gas:
Price variance impact	$	(14,647	)
Sales volume variance impact		(3,726	)

Total change		(18,373	)
Change in revenues from the sale of oil, NGL and natural gas:
Price variance impact	$	(13,643	)
Volume variance impact		3,919
Cash settlement of commodity derivative contracts		5,094
Unrealized gains due to commodity derivative contracts		(18,312	)

Total change	$	(22,942	)


	Nine Months Ended September 30,
	2012			% Change			2011
Oil price:
Oil price per Bbl	$	105.25			5	%	$	100.47
Oil derivative settlements per Bbl		(4.21	)		(55	)%		(9.40	)

Oil revenues including oil derivative settlements per Bbl	$	101.04			11	%	$	91.07
NGL price:
NGL revenues	$	36.55			(22	)%	$	46.69
NGL derivative settlements per Bbl		11.02			(3,000	)%		(0.38	)

NGL revenues including derivative settlements	$	47.57			3	%	$	46.31
Natural gas price:
Natural gas per Mcf	$	2.42			(41	)%	$	4.12
Natural gas derivative settlements per Mcf		2.57			23	%		2.09

Natural gas revenues including derivative settlements per Mcf	$	4.99			(20	)%	$	6.21
Oil, NGL and natural gas price per BOE:
Oil, NGL and natural gas revenues per BOE	$	45.54			(2	)%	$	46.46
Oil, NGL and natural gas derivative settlements per BOE		8.75			52	%		5.74

Oil, NGL and natural gas revenues including derivative settlements per BOE	$	54.29			4	%	$	52.20
Oil, NGL and natural gas derivative unrealized gains per BOE		(4.24	)		(195	)%		4.47

Oil, NGL and natural gas revenues including derivative settlements and unrealized gains per BOE	$	50.05			(12	)%	$	56.67

Total price per BOE	$	50.05			(12	)%	$	56.67

Our oil, NGL and natural gas revenues, including derivatives settlements and unrealized derivative gains (losses), for the nine months ended September 30, 2012 decreased by approximately $22.9 million, or 19%, from approximately $123.9 million to approximately $101.0 million, when compared to the same period in 2011. Our oil, NGL and natural gas revenues for the nine months ended September 30, 2012 decreased by approximately $9.7 million, from approximately $101.6 million to approximately $91.9 million. This decrease related to lower prices of NGL and natural gas of approximately $14.0 million and lower production of natural gas of approximately $6.3 million, which was partially offset by higher oil prices of approximately $3.1 million and higher production of oil and NGL, which increased revenue by approximately $7.5 million. Our derivative revenue was approximately $9.1 million for the nine months ended September 30, 2012, as compared to approximately $22.3 million for the 2011 period. The decrease in derivative revenues was due to a decrease in unrealized gains of commodity derivatives of approximately $18.3 million due to price increases, which was offset by an increase in realized gains of commodity derivatives of approximately $5.1 million.

Production costs. Production volumes in the nine months ended September 30, 2012 decreased 8% as compared to the same period in 2011 from 2,186 MBoe to 2,017 MBoe. Per unit production cost in 2012 increased by $1.46/Boe, or 9%, and total production costs in 2012 increased by approximately $0.1 million, as compared to 2011. Our per unit and total production costs for the nine months ended September 30, 2012 and 2011 are as set forth below.


	Unit-of-Production (Per Boe Based on Sales Volumes) Nine Months Ended September 30,
	2012		% Change			2011
Production costs:
Gathering & transportation	$	0.59		20	%	$	0.49
Operating & maintenance		12.51		10	%		11.33
Workover expenses		0.95		(3	)%		0.98

Lease operating expenses		14.05		10	%		12.80
Remediation expenses		0		(100	)%		0.91
Taxes other than income		4.27		36	%		3.15

Production costs	$	18.32		9	%	$	16.86


	Production Costs
	Nine Months Ended September 30,
	2012		% Change			2011
	(In thousands)
Production costs:
Gathering & transportation	$	1,195		12	%	$	1,068
Operating & maintenance		25,228		2	%		24,766
Workover expenses		1,917		(11	)%		2,149

Lease operating expenses		28,340		1	%		27,983
Remediation expenses		—		(100	)%		1,988
Taxes other than income		8,616		25	%		6,895

Production costs	$	36,956		0	%	$	36,866

Gathering and transportation costs for the nine months ended September 30, 2012 were approximately $1.2 million, compared to approximately $1.1 million in 2011, an increase of approximately $0.1 million, or 12%.

Operating and maintenance expenses for the nine months ended September 30, 2012 were approximately $25.2 million, compared to approximately $24.8 million in the same period of 2011, an increase of approximately $0.4 million, or 2%. This increase in operating and maintenance expenses was due to higher labor and maintenance cost, which was partially offset by lower legal costs.

Workover expenses for the nine months ended September 30, 2012 were approximately $1.9 million, compared to approximately $2.1 million in the same period in 2011. The decrease of approximately $0.2 million is related to the reduction in the number of workovers performed in 2012 compared to 2011.

Environmental remediation expenses for the nine months ended September 30, 2011 were approximately $2.0 million and were incurred in 2011 as a result of a litigation settlement. There were no remediation costs incurred in the nine months ended September 30, 2012.

Taxes other than income for the nine months ended September 30, 2012 were approximately $8.6 million, compared to approximately $6.9 million in the same period of 2011, an increase of approximately $1.7 million or 25%. This increase in taxes was due primarily to higher actual ad valorem taxes incurred in the current year.

General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized expenses include the expenses 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 nine months ended September 30, 2012 and 2011 were as follows:


	Nine Months Ended September 30,
	2012		% Change			2011
	(In thousands, except per unit measurements which are based on sales volumes)
General and administrative expenses — gross	$	11,871		(14	)%	$	13,841
Capitalized general and administrative expenses		2,684		(24	)%		3,519

General and administrative expenses — net	$	9,187		(11	)%	$	10,322

General and administrative expenses — gross $ per Boe	$	5.89		(7	)%	$	6.33

Our gross general and administrative expenses for the nine months ended September 30, 2012 were approximately $11.9 million compared to approximately $13.8 million in the same period of 2011, a decrease of approximately $1.9 million, or 14%, primarily as a result of reduced compensation costs and lower legal and accounting costs related to our indebtedness. After capitalization, our net general and administrative expenses decreased by approximately $1.1 million, or 11%, to approximately $9.2 million. Per unit general and administrative expense decreased by 7% due to lower compensation and bonuses in 2012 and lower legal and accounting costs related to our indebtedness. This was offset by a decrease in production volumes.

Depletion of oil, NGL and natural gas properties.


	Nine Months Ended September 30,
	2012		% Change			2011
	(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil, NGL and natural gas properties	$	38,114		3	%	$	36,898
Depletion of oil, NGL and natural gas properties (per Boe)	$	18.89		12	%	$	16.88

Our depletion expense for the nine months ended September 30, 2012 was approximately $38.1 million compared to approximately $36.9 million in the same period of 2011, an increase of approximately $1.2 million, or 3%. An increase in our depletion rate, due to a higher depreciable base and lower reserves attributed to an increase in depletion expense of approximately $4.4 million. This was offset by lower production volumes resulting in lower depletion expense of approximately $3.2 million.

Impairment of oil and natural gas properties. For the nine months ended September 30, 2012, we reported an impairment of approximately $14.6 million to our oil, NGL and natural gas properties. The impairment occurred and was recorded in part in the first and in part in the third quarter of 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 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 and natural gas properties exceeded the ceiling limit and we recorded an impairment of approximately $3.0 million to our oil and natural gas properties. An impairment of approximately $14.6 million was recorded for the nine months ended September 30, 2012 and an impairment of approximately $18.2 million was recorded for the year ended December 31, 2011.

Net interest expense. Our interest expense for the nine months ended September 30, 2012 was approximately $27.0 million as compared to approximately $32.5 million for the same period in 2011. Total interest expense for the nine months ended September 30, 2012 benefited from our converting the Series A preferred from a debt instrument to mezzanine equity. This was partially offset by the increase in interest expense due to the assumption of a higher coupon on the 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.

Sources and Uses of Cash

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


	Nine Months Ended September 30,
	2012			% Change			2011
	(In thousands)
Net loss	$	(28,311	)		(604	)%	$	5,618
Non-cash items		68,194			69	%		40,435
Changes in working capital and other items		1,123			(39	)%		1,856

Net cash provided by operating activities		41,006			(14	)%		47,909
Net cash used in investing activities		(25,445	)		(70	)%		(83,910	)
Net cash (used in) provided by financing activities		(24,115	)		(201	)%		23,910

Net decrease in cash and cash equivalents	$	(8,554	)		(29	)%	$	(12,091	)

Analysis of net cash provided by operating activities

Net cash provided by operating activities for the nine months ended September 30, 2012 were approximately $41.0 million, as compared to approximately $47.9 million for the same period in 2011, an approximately $6.9 million, or 14%, decrease. The decrease in net cash provided by operating activities from 2011 to 2012 was primarily due to approximately $4.6 million of lower revenues and higher operating costs of approximately $1.6 million, which decreased operating cash flow activities by approximately $6.2 million. This decrease was also related to working capital changes of approximately $0.7 million in 2012 compared to 2011.

Analysis of net cash used in investing activities

Net cash used in investing activities for the nine months ended September 30, 2012 was approximately $25.4 million, compared to approximately $83.9 million in the same period in 2011, an approximately $58.5 million, or 70%, decrease. The decrease relates primarily to a reduction in drilling of approximately $28.4 million due to declines in gas prices and acquisitions of approximately $29.7 million and the receipt of approximately $4.4 million of insurance proceeds related to the 2011 flooding of our West Lake Verrett properties and damages caused by Hurricane Ike.

Analysis of net cash used in financing activities

Net cash used in financing activities for the nine months ended September 30, 2012 was approximately $24.1 million as compared to approximately $23.9 million of cash provided by financing activities for the same period in 2011, a decrease of approximately $48.0 million, or 201%. This decrease reflected the additional repayment of borrowings, net of proceeds, of approximately $24.0 million in 2012 as compared to proceeds, net of payments, of approximately $33.2 million in 2011. This decrease was partially offset by approximately $9.2 million of lower financing activities primarily related to deferred financing costs.

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.

We contemplate spending approximately an additional $4.5 million in the remainder of 2012 to support our business plan. We are planning to complete the one carryover wells and drill or participate in up to five additional wells during the remainder of 2012, including one non-operated development well and one non-operated exploration well in our South Texas area, one operated exploratory well and two non-operated exploratory well and one non-operated development well in our Southeast area, as well as planning on workover and recompletion projects of existing wells. Our original 2012 capital budget of approximately $54.2 million included approximately $25.0 million for acquisitions. However, we do not anticipate using the funds and therefore revised our 2012 capital budget to remove the capital associated with acquisitions, leaving us with a 2012 budget of approximately $29.2 million which was approved by the board. In light of the price volatility we have experienced this year, we are constantly evaluating the deployment of our capital. See “Liquidity and Capital Resources” for more on our capital expenditures.

Capital resources

Cash. As of September 30, 2012 and December 31, 2011, we had approximately $0.8 million and $9.4 million of cash and cash equivalents, respectively.

First Lien Credit. During 2011, we entered into a $300 million Amended and Restated First Lien Credit Agreement that matures in November 2014. The initial borrowing base for the 2011 Credit Facility was established at $170 million with semi-annual re-determinations to begin in November 2011. As of September 30, 2012, the borrowing base was $165 million. A 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 million

per month for the following six months, ending at $135 million in April 2013. Amounts outstanding, under the 2011 Credit Facility bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the 2011 Credit Facility are secured by all of our oil, 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 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 1.64 as of September 30, 2012), minimum interest coverage ratio, as defined, of not less than 2.50 to 1.0 (which was 2.74 as of September 30, 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 September 30, 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 1.32 as of September 30, 2012). The maximum leverage ratio will reduce to 4.00 to 1.0 as of March 31, 2013 and all periods thereafter. The Company is currently exploring a range of alternatives to be in compliance with the financial covenant at the applicable dates. Unless the Company is able to execute one or more of these alternatives, the Company’s maximum leverage ratio may not meet the reduced threshold in the covenants beginning on March 31, 2013. In that event, the Company would have to seek a waiver or amendment to these agreements and, if not granted, the lenders could declare a default and the Company will not be able to borrow additional funds under the facility. Accordingly, there is substantial doubt of the Company’s ability to continue as a going concern.

In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt and liens, changes of control and asset sales. At September 30, 2012, we are not aware of any instances of noncompliance with the financial covenants governing the 2011 Credit Facility.

Senior Secured Second Lien Notes. During 2011, 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 stated 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 $5.1 million at September 30, 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 110.500% of par. Additional optional redemption provisions allow for the retirement of all or a portion of the outstanding senior secured second lien notes at 110.500%, 102.625% and 100.000% beginning on each of May 15, 2014, May 15, 2015 and November 15, 2015, respectively. If a change of control occurs, each noteholder may require us to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus any accrued and unpaid interest and special interest, if any, to, but not including, the date of repurchase. The indenture governing the Notes contains covenants that, among other things, limit our ability to incur or guarantee additional indebtedness or issue certain preferred stock; declare or pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; transfer or sell assets; make investments; create certain liens; consolidate, merge or transfer all or substantially all of its assets; engage in transactions with affiliates; and create unrestricted subsidiaries.

Outlook

Since the beginning of the year, 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 2012 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.

Our intent for the remainder of 2012 is to manage our operational and capital spending within the available free cash flow generated by our assets. To the extent we do not find suitable acquisition or drilling opportunities, we will pay down our debt balance.

As of September 30, 2012, we had approximately $51.0 million of available borrowing capacity under our 2011 Credit Facility. See “Liquidity and Capital Resources” for more discussion on our borrowing base and debt covenants.

For the nine months ended September 30, 2012, we realized approximately $17.6 million in gains under our commodity derivative agreements. Based on the NYMEX strip pricing for oil, NGL and natural gas as of September 30, 2012, we expect to realize approximately $1.6 million of commodity derivative gains during the last three months of 2012.

For 2012, our revised capital program is budgeted at approximately $29.2 million, which we believe is sufficient to maintain current operations and replace 100% of our annual production. For the three months ending December 31, 2012, our revised 2012 capital budget contemplates spending approximately $4.5 million in connection with the completion of one carryover well and drill or participate in up to five additional wells including one non-operated development well and one non-operated exploratory well in our South Texas area, and one operated exploratory well and one non-operated exploratory well and one non-operated development well in our Southeast area, as well as planning on workover and recompletion projects of existing wells. The table below sets forth our revised 2012 capital budget activity.


	2012 Budget(a)		Amount Spent Through September 30, 2012		Amount Remaining(b)
	(In millions)
Drilling	$	14.2	$	12.7	$	1.5
Workovers and recompletions		11.3		9.0		2.3
Geological, geophysical, leasing and seismic		1.2		1.9		(0.7	)
Plugging and abandonment		1.5		0.3		1.2
Facilities, vehicles and other		1.0		0.8		0.2

Total operations capital budget	$	29.2	$	24.7	$	4.5

(a)	Revised 2012 capital budget approved by our Board of Directors.

(b)	Calculated based upon the 2012 capital budget less amounts spent through September 30, 2012.

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

•

changes in commodity prices;

•

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

•

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;

•

our liquidity and the availability of financing; and

•

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

Off Balance Sheet Arrangements

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

Critical Accounting Policies

Recently Issued Accounting Pronouncements

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. We are required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. We adopted this standard effective January 1, 2012, which did not have an impact on our 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. We are currently evaluating the potential impact of this adoption but expect that the adoption of this standard will have no impact on our consolidated financial statements.

Item 3.

Quantitative and Qualitative Disclosures 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. We are 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 September 30, 2012, a 1% increase in interest rates would increase interest expense by approximately $1.1 million per year, based on our approximately $114.0 million of floating rate indebtedness and base rate indebtedness outstanding under our 2011 Credit Facility that would be affected by such a movement in interest rates.

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 the first half of 2012 included the pace at which the domestic and global economies recovered from the current recession, the economic crisis in Europe, the ongoing tensions and uprisings in the Middle East and North Africa, and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations were able to manage oil supply through export quotas.

Natural gas prices are primarily driven by North American market forces. However, global LNG shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe to North America. Factors that can affect the price of natural gas include changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Over the past several years, natural gas prices have been volatile. Our average pre-hedged sales price for natural gas in the first half of 2012 was $2.28 per Mcf, which was 45% lower than the price of $4.15 per Mcf that we received in the first half of 2011. Natural gas prices in the first half of 2012 were dependent upon many factors including the balance between North American supply and demand.

We have utilized swaps and costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure that we can execute at least a portion of our capital spending plans with internally generated funds. The following table details derivative contracts that settled during 2012 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain/(loss) upon settlement.


	As of September 30, 2012
Oil collars
Volumes (Bbls)		433,156
Average floor price (per Bbl)	$	83.03
Average ceiling price (per Bbl)	$	93.84

Loss upon settlement	$	(1,957,848	)

Oil swaps
Volumes (Bbls)		62,016
Average swap price (per Bbl)	$	98.88

Gain upon settlement	$	784,196

LLS-WTI Basis swaps
Volumes (Bbls)		217,200
Average swap price (per Bbl)	$	9.87

Loss upon settlement	$	(1,530,144	)

Total oil loss upon settlement	$	(2,703,796	)

Natural gas collars
Volumes (Mcf)		2,925,000
Average floor price (per Mcf)	$	4.98
Average ceiling price (per Mcf)	$	6.03

Gain upon settlement	$	9,009,500

Natural gas swaps
Volumes (Mcf)		2,624,064
Average swap price (per Mcf)	$	3.74

Gain upon settlement	$	9,219,284

Total natural gas gain upon settlement	$	18,228,784

NGL swaps
Volumes (Mcf)		147,733
Average swap price (per Mcf)	$	51.30
Gain upon settlement	$	2,116,288

Total NGL gain upon settlement	$	2,116,288

Total oil, NGL and natural gas gain upon settlement	$	17,641,276

The following commodity derivative contracts were in place as of September 30, 2012:


Natural Gas	Type	Mmbtu/Mo or Avg Mmbtu/Mo	Price/Mmbtu
Oct-12 – Dec-12	Collar	150,000	$6.50 – $8.10
Oct-12 – Dec-12	Collar	50,000	4.25 – 5.35
Oct-12 – Dec-12	Collar	125,000	3.45 – 3.81
Oct-12 – Dec-12	Swap	75,000	5.15
Oct-12 – Dec-12	Swap	53,990	3.04
Oct-12 – Dec-12	Swap	115,610	5.00
Jan-13 – Dec-13	Collar	90,000	3.50 – 5.75
Jan-13 – Dec-13	Swap	100,000	4.66
Jan-13 – Dec-14	Swap	100,000	3.79
Jan-14 – Dec-14	Collar	40,000	5.10 – 6.20
Jan-14 – Nov-14	Collar	73,820	4.50 – 6.15
Jan-14 – Dec-14	Swap	75,000	3.82
Jan-14 – Dec-14	Swap	40,000	4.52

Oil		Volume	Price
Oct-12 – Dec-12	Collar	10,000	$80.00 – $ 93.24
Oct-12 – Dec-12	Collar	25,081	80.00 – 86.00
Oct-12 – Dec-12	Collar	5,000	90.00 – 96.50
Oct-12 – Dec-12	Collar	7,837	92.00 – 102.05
Oct-12 – Dec-13	Swap	9,190	94.95
Oct-12 – Dec-12	Basis Swap	15,333	6.60
Oct-12 – Dec-12	Basis Swap	24,533	10.75
Jan-13 – Dec-13	Collar	8,000	92.00 – 102.95
Jan-13 – Dec-14	Collar	2,000	92.00 – 100.00
Jan-13 – Dec-14	Collar	2,000	90.00 – 97.00
Jan-13 – Dec-14	Collar	2,000	93.00 – 101.00
Jan-13 – Dec-14	Collar	2,000	91.00 – 97.00
Jan-13 – Dec-14	Collar	3,000	91.00 – 98.00
Jan-13 – Dec-14	Collar	2,000	92.00 – 98.00
Jan-13 – Dec-13	Collar	2,000	93.00 – 102.00
Jan-13 – Dec-13	Collar	6,000	90.00 – 111.85
Jan-13 – Dec-14	Swap	1,000	91.00
Jan-13 – Dec-14	Swap	1,000	91.50
Jan-14 – Dec-14	Collar	10,000	93.00 – 100.25


NGL		Volume	Price
Oct-12 – Dec-12	Swap	5,000	$51.00
Oct-12 – Dec-12	Swap	6,000	51.25
Oct-12 – Dec-12	Swap	2,957	52.40
Oct-12 – Dec-12	Swap	883	47.55
Jan-13 – Dec-13	Swap	8,500	38.90
Jan-14 – Dec-14	Swap	7,100	38.24

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 health of the industry. During the nine months ended September 30, 2012, ten customers collectively accounted for 77% of our oil, NGL and natural gas revenues and during the nine months ended September 30, 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. Shell Trading (US) Company accounted for 22% and Enterprise Crude Oil, LLC accounted for 18% of total sales during the nine months ended September 30, 2012. During the nine months ended September 30, 2011, Shell Trading (US) Company accounted for 18% and Enterprise Crude Oil, LLC accounted for 16% of total sales. No other customer accounted for more than 10% of total sales during either period.

Counterparty Risk

We have exposure to financial institutions in the form of derivative transactions in connection with our commodity derivatives. 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. We also have exposure to financial institutions which are lenders under our credit facilities. If any lender 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 credit facility.

Item 4.

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 Chief Financial Officer and Treasurer, 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 September 30, 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 intends to retain the services of additional third party accounting personnel as well as to modify existing internal controls in a manner designed to ensure future compliance. However, we are unable to predict the timing or expense to take these actions. Our management currently believes the additional accounting resources expected to be retained for the purposes of being an SEC reporting company will remediate the weakness with respect to insufficient personnel. In addition, we have identified a material weakness as we had no controls in place related to the safeguarding of certain assets (specifically emission credits). To remediate this material weakness, we have established internal controls subsequent to September 30, 2012 that segregate duties between the purchase and sale of emission credits, require an appropriate approval by persons with relevant authority, and require the periodic reconciliation of emission credit accounts with the applicable governing agency that tracks transaction activity.

Changes in Internal Control Over Financial Reporting

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

PART II

Item 1.

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, personal injury and 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 adverse effect on our consolidated financial position, results of operations or cash flow. We record reserves for contingencies when information available indicates that a toss is probable and the amount of the loss can be reasonably estimated.

Item 1A.

Risk Factors.

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

As of September 30, 2012, we had approximately $358.9 million in outstanding indebtedness and had approximately $51.0 million of available borrowing capacity under our amended and restated first lien credit agreement. Our level of indebtedness will have several important effects on our operations, including:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

We recorded a net loss for the nine months ended September 30, 2012 and the years ended December 31, 2011, 2010 and 2009 of $28.3 million and $23.6 million, $70.6 million and $8.6 million, respectively. We cannot assure you that our current level of operating results will continue or improve. Our activities could require additional equity or debt financing. Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of oil and natural gas, rates of production, timing of capital expenditures and drilling success. Negative changes in these variables could have a material adverse effect on our business, financial condition and results of operations.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3.

Defaults Upon Senior Securities.

None.

Item 4.

Mine Safety Disclosure.

Not applicable.

Item 5.

Other Information.

None.

Item 6.

Exhibits

10.1 Consulting Agreement among Milagro Oil & Gas, Inc., Milagro Holdings, LLC and Sequitur Energy Management II, LLC dated October 3, 2012.

31.1 Certification of Principal Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

31.2 Certification of Principal Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

32.1 Certification of Principal Executive Officer pursuant to Rule 13a-14(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) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.


101.INS		XBRL Instance Document.*

101.SCH		XBRL Taxonomy Extension Schema Document.*

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.*

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.*

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.*

In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this quarterly report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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, and Section 2IE of the Exchange Act). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil, NGL and natural gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future or proposed operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•

our ability to finance our planned capital expenditures;

•

the volatility in commodity prices for oil, NGL 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, NGL 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, NGL and natural gas reserves and the actual future production rates and associated costs;

•

availability of pipeline capacity and other means of transporting our oil, NGL 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 Part II, Section 1A of this quarterly report on Form 10-Q and the section entitled “Risk Factors” included in our annual report on Form 10-K for the year ended December 31, 2011 and quarterly reports on form 10-Q for the period ended March 31, 2012 and June 30, 2012. 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.

SIGNATURES

Milagro Oil & Gas. Inc. has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		MILAGRO OIL & GAS, INC.

Date: November 13, 2012	By:	/s/ James G. Ivey
			James G. Ivey
			President and Chief Executive Officer

Date: November 13, 2012	By:	/s/ Robert D. LaRocque
			Robert D. LaRocque
			Chief Financial Officer and Treasurer