UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-Q

(Mark One)

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

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

Commission file number:  

 

MILAGRO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Delaware (State of Incorporation)		26-1307173 (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

Former name, former address and former fiscal year, if changed since last report: N/A

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 o No o

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 o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

As of November 17, 2011 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)			3
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010			3
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010			4
Unaudited Condensed Consolidated Statements of Changes in Deficit as of September 30, 2011			5
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010			6
Notes to the Unaudited Condensed Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 3. Quantitative and Qualitative Disclosure about Market Risk			35
Item 4. Controls and Procedures			38
PART II. Other Information
Item 1. Legal Proceedings			38
Item 1A. Risk Factors			38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 3. Defaults Upon Senior Securities			40
Item 4. [Removed and Reserved.]			40
Item 5. Other Information			40
Item 6. Exhibits			40
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

 

 

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

		September 30,				December 31,
		2011				2010
		(In thousands,
		except share data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	5,643			$	17,734
Accounts receivable:
Oil and natural gas sales			18,133				18,480
Joint interest billings and other — net of allowance for doubtful accounts of $515 and $615 in 2011 and 2010, respectively (Note 2)			2,225				2,530
Derivative assets			13,466				18,834
Prepaid expenses and other			3,559				2,518
Total current assets			43,026				60,096
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties — full cost method:
Proved properties			1,262,528				1,181,948
Unproved properties			19,049				13,156
Less accumulated depreciation, depletion and amortization			(780,591	)			(743,637	)
Net oil and natural gas properties			500,986				451,467
Other property and equipment, net of accumulated depreciation of $5,933 and $5,436 in 2011 and 2010, respectively			1,396				1,718
Net property, plant and equipment			502,382				453,185
DERIVATIVE ASSETS			8,950				2,646
OTHER ASSETS:
Deferred financing costs			8,357				1,813
Advance to affiliate			2,226				2,248
Other			2,590				2,210
Total other assets			13,173				6,271
TOTAL		$	567,531			$	522,198
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued liabilities		$	37,972			$	39,672
Current portion of debt			—				244,580
Accrued interest payable			10,865				1,959
Derivative liabilities			8				9,427
Asset retirement obligation			2,921				2,921
Total current liabilities			51,766				298,559
NONCURRENT LIABILITIES:
Long-term debt			371,032				92,390
Series A preferred stock (Note 7)			—				223,630
Asset retirement obligation			37,523				37,350
Derivative liabilities			—				2,926
Other			3,148				3,173
Total noncurrent liabilities			411,703				359,469
Total liabilities			463,469				658,028
MEZZANINE EQUITY
Redeemable series A preferred stock (Note 9)			234,274				—
COMMITMENT AND CONTINGENCIES (Note 12)
DEFICIT:
Common shares, (par value, $.01 per share; shares authorized: 1,000,000; shares issued and outstanding: 280,400 as of September 30, 2011 and December 31, 2010, respectively			3				3
Additional paid-in capital			(66,813	)			(66,813	)
Accumulated deficit			(63,402	)			(69,020	)
Total stockholder’s deficit			(130,212	)			(135,830	)
TOTAL		$	567,531			$	522,198

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

MILAGRO OIL AND GAS, INC.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
REVENUES:
Oil and natural gas revenues		$	32,112			$	32,761			$	101,577			$	101,431
Gain on commodity derivatives, net			25,883				7,888				22,318				29,906
Total revenues			57,995				40,649				123,895				131,337
COSTS AND EXPENSES:
Gathering and transportation			371				286				1,068				948
Lease operating			8,324				8,995				26,915				25,396
Environmental remediation			5				—				1,988				—
Taxes other than income			2,611				2,580				6,895				8,160
Depreciation, depletion and amortization			12,320				14,190				37,451				40,481
General and administrative			3,200				4,127				10,322				12,816
Accretion			798				642				2,371				1,878
Total costs and expenses			27,629				30,820				87,010				89,679
Operating income			30,366				9,829				36,885				41,658
OTHER EXPENSE (INCOME):
Net (gain)/loss on interest rate derivatives			(2,767	)			813				(1,854	)			2,072
Other income			(339	)			(23	)			(408	)			(633	)
Interest and related expenses, net of amounts capitalized			8,444				12,130				32,502				36,211
Loss on extinguishment of debt			—				—				1,027				—
Total other expense			5,338				12,920				31,267				37,650
INCOME/(LOSS) BEFORE INCOME TAX			25,028				(3,091	)			5,618				4,008
INCOME TAX EXPENSE			—				—				—				57,422
NET INCOME / (LOSS)			25,028				(3,091	)			5,618				(53,414	)
Preferred dividends			7,318				—				11,162				—
NET INCOME /(LOSS) AVAILABLE TO COMMON SHAREHOLDERS		$	17,710			$	(3,091	)		$	(5,544	)		$	(53,414	)

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

MILAGRO OIL & GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN DEFICIT

										Additional								Total
		Common Stock								Paid in				Accumulated				Stockholders’
		Shares				Par Value				Capital				Deficit				Deficit
		(In thousands, except for share amounts)
BALANCE — December 31, 2010			280,400			$	3			$	(66,813	)		$	(69,020	)		$	(135,830	)
Net income			—				—				—				5,618				5,618
BALANCE — September 30, 2011			280,400			$	3			$	(66,813	)		$	(63,402	)		$	(130,212	)

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

		Nine months ended September 30,
		2011				2010
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income/(loss)		$	5,618			$	(53,414	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization			37,451				40,481
Amortization of deferred financing costs			1,422				1,320
Loss on extinguishment of debt			1,027				—
Accretion of asset retirement obligations			2,371				1,878
Deferred income taxes			—				57,422
PIK note interest			10,015				21,200
Accretion of financing costs			1,429				852
Unrealized (gain)/loss on commodity derivatives			(9,770	)			(3,873	)
Unrealized (gain)/loss on interest rate derivatives			(3,510	)			(4,605	)
Stock based compensation			—				1,341
Changes in assets and liabilities:
Accounts receivable and accrued revenue			652				763
Prepaid expenses and other			(1,041	)			(1,005	)
Accounts payable and accrued liabilities			2,245				859
Net cash provided by operating activities			47,909				63,219
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and natural gas properties			(29,696	)			(22,399	)
Additions to oil and natural gas properties			(54,076	)			(17,299	)
Additions of other long-term assets			(175	)			(406	)
Net sales of oil and natural gas properties			37				127
Net cash used in investing activities			(83,910	)			(39,977	)
CASH FLOWS FROM FINANCING ACTITVITIES:
Proceeds from borrowings			395,955				49,000
Credit facility payments			(362,693	)			(42,933	)
Deferred financing costs paid			(9.352	)			(43	)
Net cash provided by financing activities			23,910				6,024
NET CHANGE IN CASH AND CASH EQUIVALENTS		$	(12,091	)		$	29,266
CASH AND CASH EQUIVALENTS — Beginning of period		$	17,734			$	10,531
CASH AND CASH EQUIVALENTS — End of period		$	5,643			$	39,797
INCOME TAX PAID, Net of refunds		$	—			$	—
INTEREST PAID — Net of interest capitalized of $803 and $1,654 in 2011 and 2010, respectively		$	10,649			$	10,272
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Recapitalization:
Issuance of series A preferred stock		$	—			$	198,712
Interest paid in kind — series A preferred stock		$	9,800			$	17,565
Forgiveness of forbearance fee		$	—			$	4,000
Settlement of second lien debt		$	—			$	(194,712	)
Interest paid in kind — second lien		$	214			$	3,635
Interest and fees converted to debt		$	—			$	21,960
Accrued capital and seismic costs included in proved properties		$	10,540			$	1,417
Asset retirement obligations incurred		$	2,105			$	3,103

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

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 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 for the year ended December 31, 2010.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results to be expected for the full year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates — The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. These estimates include oil and natural gas reserve quantities that form the basis for (i) the allocation of purchase price to proved and unproved properties, (ii) calculation of amortization of oil and natural gas properties and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (a) estimated quantities and prices of oil and natural gas sold, but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current plug and abandonment costs, settlement date, inflation rate and credit-adjusted risk-free rate used in estimating asset retirement obligations; and (d) those assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 6. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.

Oil and Natural Gas Properties:

Full Cost Accounting — The Company utilizes the full cost method to account for its investment in oil and natural gas properties. Under the full cost method, which is governed by Rule 4-10 of Regulation S-X of the SEC, all costs of acquisition, exploration, exploitation, and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible exploration and development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Direct internal costs that are capitalized are primarily the salary and benefits of geologists, landmen, and engineers directly involved in acquisition, exploration and development activities. There were approximately $1.1 million and $1.0 million of direct internal costs capitalized for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, direct internal costs capitalized were approximately $3.5 million and $2.8 million, respectively.

Depreciation, Depletion, and Amortization — The cost of oil and natural gas properties; the estimated future expenditures to develop proved reserves; and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and natural gas reserves as estimated by independent engineering consultants. The Company’s depletion rates for the nine months ended September 30, 2011 and 2010 were $16.88 and $15.52 per Mboe, respectively.

Impairment — Full cost ceiling impairment is calculated whereby net capitalized costs related to proved and unproved properties less related deferred income taxes may not exceed a ceiling limitation. The ceiling limitation is the amount equal to the present value discounted at 10% of estimated future net revenues from estimated proved reserves plus the lower of cost or fair value of unproved properties less estimated future production and development costs and net of related income tax effect. The full cost ceiling limitation is calculated using 12-month simple average price of oil and natural gas as of the first day of each month for the period ending as of the balance sheet date and is adjusted for “basis” or location differentials. Price and operating costs, which are based on current cost conditions, are held constant over the life of the reserves. If net capitalized costs related to proved properties less related deferred income taxes exceed the ceiling limitation, the excess is impaired and a permanent write-down is recorded in the unaudited condensed consolidated statements of operations. As of September 30, 2011 and 2010, no ceiling impairment was recorded.

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

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

Unproved property costs fall into two broad categories:

•

Leasehold costs for projects not yet evaluated; and

•

Interest costs related to financing such activities.

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

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

Revenue Recognition and Natural gas Imbalances — Revenues are recognized and accrued as production occurs and physical possession and title pass to the customer. The Company uses the sales method of accounting for revenue. Under this method, oil and natural gas revenues are recorded for the amount of oil and natural gas production sold to purchasers. Natural gas imbalances are created when the sales amount is not equal to the Company’s entitled share of production. The Company’s entitled share is calculated as gross production from the property multiplied by the Company’s net revenue interest in the property. No provision is made for an imbalance unless the oil and natural gas reserves attributable to a property have depleted to the point that there are insufficient reserves to satisfy existing imbalance positions. At that point, a payable or a receivable, as appropriate, is recorded equal to the net value of the imbalance. The Company had recorded a liability of approximately $0.7 million as of both September 30, 2011 and December 31, 2010.

Accounts Receivable — The Company sells oil and natural gas to various customers. Substantially all of the Company’s accounts receivable are due from purchasers of oil and natural gas or from reimbursable expenses billed to the other participants in oil and natural gas wells for which the Company serves as operator. Oil and natural gas sales are generally unsecured. Shell Trading (US) Company accounted for 18% and Enterprise Crude Oil, LLC accounted for 16% of total sales during the nine months ended September 30, 2011. During the nine months ended September 30, 2010, Shell Trading (US) Company accounted for 18% and Enterprise Crude Oil, LLC accounted for 11% of total sales. No other customer accounted for more than 10% of total sales during either period.

As is common industry practice, collateral or other security is generally not required as a condition of sale; rather, the Company relies on credit approval, balance limitation, and monitoring procedures to control the credit approval on accounts receivable. The Company also grants credit to joint owners of oil and natural gas properties, which the Company operates through its subsidiaries. Such amounts are secured by the underlying ownership interests in the properties. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from all customers for collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to allowance. As of September 30, 2011 and December 31, 2010, the Company had allowances of approximately $0.5 million and $0.6 million, respectively. There were no significant write-offs of receivables for the nine months ended September 30, 2011 or the year ended December 31, 2010 and no significant bad debt expense recorded for the same periods.

Prepaid and Other Current Assets:

Prepaid Expenses — The Company will occasionally prepay certain costs that may include insurance, maintenance agreements or rent. These costs are then amortized or expensed in the period the work or service is performed. As of September 30, 2011 and December 31, 2010, the Company had prepaid expense of approximately $2.5 million and $1.5 million, respectively, primarily related to insurance.

Other — The Company is required to make advances to operators for costs incurred on a day-to-day basis to develop and operate ventures in which the Company has an ownership interest. These advances totaled approximately $0.2 million as of both September 30, 2011 and December 31, 2010. Such costs are capitalized to the full cost pool at the time the operator develops the properties. Other assets included a prepaid escrow of approximately $0.8 million as of both September 30, 2011 and December 31, 2010.

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

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

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

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

Asset Retirement Obligation — The Company records a liability for the estimated fair value of its asset retirement obligations, primarily comprised of its plugging and abandonment liabilities, in the period in which it is incurred. The liability is accreted each period through charges to accretion expense. The asset retirement cost is included in the full cost pool. If the liability is settled for an amount other than the recorded amount, the difference is recognized in oil and natural gas properties in the unaudited condensed consolidated balance sheet.

Stock-Based Compensation — The Company estimates the fair value of stock-based compensation provided to employees. When and if issued, the Company estimates the fair value of stock-based compensation at the grant date, and recognizes compensation expense over the period that the employees provide the required service.

Subsequent Events — The Company evaluated subsequent events through November 10, 2011, which is the date the financial statements were issued and no significant events had occurred.

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 is required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.

3. 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, 2011 is as follows (in thousands):

Liability for asset retirement obligation — December 31, 2010		$	40,271
Revisions			(3,141	)
Additions			2,105
Settlements			(1,162	)
Accretion expense			2,371
Liability for asset retirement obligation — September 30, 2011		$	40,444

The liability comprises a current balance of approximately $2.9 million and a noncurrent balance of approximately $37.5 million as of September 30, 2011.

4. STOCK-BASED COMPENSATION

On November 30, 2007, Parent issued six Class C units to Milagro Management Pool, LP (“Management Pool”) with no per unit stated value. No further Class C units have been issued. Management Pool in turn has issued limited partnership interests to the Company’s management and other employees. The maximum number of units that can be allocated to the employees from the Management Pool is one million units. The Management Pool units vest upon the earlier of (i) change of control or (ii) ratably over five years from the date of the initial issuance of the units. If a Management Pool unit owner leaves the employment of the Company, all of such employee’s Management Pool units that are not vested shall be automatically forfeited and vested units shall be redeemed by Management Pool for no consideration.

Stock-based compensation expense for share based compensation granted by the parent to employees of the subsidiary are reflected in the Company’s financial statements. Stock-based compensation is measured at the grant date based on the estimated fair value of the award and is recognized as an expense over the requisite employee service period.

Compensation expense was recognized over the expected term of three years and was fully amortized by the end of 2010. There were no other stock-based compensation programs in place in 2010 or 2011.

5. DERIVATIVE FINANCIAL INSTRUMENTS

The Company produces and sells oil, natural gas and natural gas liquids. 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 instruments. A combination of options, structured as a collar, is the Company’s preferred derivative instrument because there are no up-front costs and the instruments set 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. For the nine months ended September 30, 2011, the Company had hedges in place for 1,064.6 MBoe, or approximately 49% of production, in the form of natural gas, oil and natural gas liquids collars and swaps. In March 2011, the Company liquidated a series of natural gas swaps for the period from April 2011 through and including October 2011. These natural gas swaps carried a strike price of $7.69/Mcf which was significantly above the market prices of natural gas prevailing at that time. The liquidation resulted in cash proceeds of approximately $10.2 million to the Company.

On June 20, 2011, the Company entered into a $100 million interest rate derivative arrangement with a single counterparty whereby the Company agrees to pay floating rate interest of three month LIBOR plus 863 basis points in exchange for receiving a fixed rate of 10.500% through May 15, 2016. This reverse interest rate swap is settled semi-annually on the interest payment dates of the Notes (as defined in Note 7).

On August 9, 2011, as the result of significant turmoil in the global capital markets, the Company terminated the $100 million reverse interest rate swap. As a result of this termination event, Milagro realized a cash settlement of $2.0 million from its counterparty.

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 the unaudited condensed consolidated balance sheets as of September 30, 2011 and December 31, 2010 (in thousands):

				Fair Value
				September 30,				December 31,
Description		Location in Balance Sheet		2011				2010
Asset derivatives:
Natural gas collars and swaps — current portion		Derivative assets — current		$	10,404			$	18,834
Noncurrent portion		Derivative assets — non-current			2,012				2,646
Oil collars and swaps — current portion		Derivative assets — current			3,062				—
Noncurrent portion		Derivative assets — non-current			6,891				—
Natural gas liquids swaps — noncurrent portion		Derivative assets — non-current			47				—
				$	22,416			$	21,480
Liability derivatives:
Oil collars and swaps — current portion		Derivative liabilities — current		$	—			$	5,917
Noncurrent portion		Derivative liabilities — non-current			—				2,926
Natural gas liquids swaps — current portion		Derivative liabilities — current			8				—
				$	8			$	8,843
Interest rate collars:
Current portion		Derivative liabilities — current			—				3,510
				$	—			$	3,510

				Three months ended								Nine months ended
		Location in Statements		September 30,								September 30,
Description		of Operations		2011				2010				2011				2010
				(In thousands)								(In thousands)
Commodity contracts:
Realized gain/(loss) on commodity contracts		Gain/(Loss) on commodity derivatives		$	1,815			$	8,589			$	12,548			$	26,033
Unrealized gain/(loss) on commodity contracts		Gain/(Loss) on commodity derivatives			24,068				(701	)			9,770				3,873
Total net gain/(loss) on commodity contracts				$	25,883			$	7,888			$	22,318			$	29,906
Interest rate swaps:
Realized (gain)/loss on interest rate swaps		Net (gain)/loss on interest rate derivatives		$	(1,069	)		$	2,001			$	1,656			$	6,677
Unrealized gain on interest rate swaps		Net (gain) loss interest rate derivatives			(1,698	)			(1,188	)			(3,510	)			(4,605	)
Total net (gain)/loss on interest rate swaps					(2,767	)			813				(1,854	)			2,072
Total net gain on derivative contracts				$	28,650			$	7,075			$	24,172			$	27,834

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

At September 30, 2011, the Company had the following natural gas collar positions:

		Collars
						Floors								Ceilings
										Weighted-								Weighted-
		Volume in								Average								Average
Period		MMbtu’s				Price Range				Price				Price Range				Price
October 2011 — December 2011			1,360,164			$	3.50-7.00			$	5.68			$	5.25-10.60			$	8.25
January 2012 — December 2012			2,400,000				4.25-6.50				5.94				5.35-8.10				7.41
January 2013 — December 2013			2,040,000				4.70-5.00				4.80				5.75-5.85				5.77
January 2014 — December 2014			1,292,020				4.50-5.10				4.72				6.15-6.20				6.17

At September 30, 2011, the Company had the following natural gas swap positions:

		Swaps
										Weighted-
		Volume in				Price/				Average
Period		MMbtu’s				Price Range				Price
October 2011 — December 2011			514,781			$	7.93-8.43			$	8.26
January 2012 — December 2012			2,496,914				5.00-5.15				5.05
January 2013 — December 2013			1,200,000				5.20				5.20
January 2014 — December 2014			1,200,000				5.20				5.20

At September 30, 2011, the Company had the following oil collar positions:

		Collars
		Floors												Ceilings
										Weighted-								Weighted-
		Volume in								Average								Average
Period		Bbl’s				Price Range				Price				Price Range				Price
October 2011 — December 2011			117,322			$	68.00-80.00			$	71.99			$	80.71-93.24			$	84.57
January 2012 — December 2012			481,563				80.00-90.00				81.25				86.00-96.50				91.44
January 2013 — December 2013			348,000				90.00-93.00				91.41				97.00-102.95				102.71
January 2014 — December 2014			276,000				90.00-93.00				92.13				97.00-101.00				99.24

At September 30, 2011, the Company had the following oil swap positions:

		Swaps
										Weighted-
		Volume in				Price/				Average
Period		Bbl’s				Price Range				Price
October 2011 — December 2011			27,181			$	99.85-101.60			$	99.93
January 2012 — December 2012			29,021				101.60				101.60
January 2013 — December 2013			24,000				91.00-91.50				91.25
January 2014 — December 2014			24,000				91.00-91.50				91.25

At September 30, 2011, the Company had the following natural gas liquids swap positions:

		Swaps
										Weighted-
		Volume in				Price/				Average
Period		Bbl’s				Price Range				Price
October 2011 — December 2011			45,000			$	56.79			$	56.79
January 2012 — December 2012			132,000				51.00 - 51.25				51.14
January 2013 — December 2013			87,600				46.25 - 47.00				46.66
January 2014 — December 2014			78,000				43.75				43.75

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, 2011 and December 31, 2010, 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				Significant
		in Active				Other				Significant
		Markets for				Observable				Unobservable
		Identical Assets				Inputs				Inputs				Total
		(Level 1)				(Level 2)				(Level 3)				Balance
September 30, 2011:
Commodity derivatives — natural gas		$	—			$	12,416			$	—			$	12,416
Commodity derivatives — oil			—				9,953				—				9,953
Commodity derivatives — natural gas liquids							39								39
December 31, 2010:
Commodity derivatives — natural gas			—			$	21,480				—			$	21,480
Commodity derivatives — oil			—				(8,843	)			—				(8,843	)
Interest rate collars			—				(3,510	)			—				(3,510	)

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, 2011 and December 31, 2010, the impact of the credit valuation adjustments on the overall valuation of the Company derivative positions is not significant to the overall valuation. As a result, derivative valuations in their entirety are classified in Level 2 of the fair value hierarchy.

Debt Instruments — The 2011 First Lien Credit Agreement accrues (as defined in Note 7) interest on a variable-rate basis. The Notes (as defined in Note 7) accrue interest on a fixed rate basis. The Company estimates the carrying value of the first lien indebtedness to approximate its fair value based on the terms of similar instruments that would be available to the Company. The Company estimates the fair market value of the Notes based upon market evaluation to be approximately $210 million as of September 30, 2011.

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

7. DEBT

The Company’s debt as of September 30, 2011 and December 31, 2010, was comprised of the following amounts (in thousands):

		September 30,				December 31,
		2011				2010
Revolver — current		$	—			$	184,580
Revolver — non-current			127,500				—
Second lien — current			—				60,000
Second lien — non-current			—				92,390
Senior Secured Second Lien Notes — non-current			243,532				—
Series A preferred stock — non-current			—				223,630
Total debt		$	371,032			$	560,600

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

Years Ending December 31		Amount
2011		$	—
2012			—
2013			—
2014			127,500
2015			—
2016			243,532
		$	371,032

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250.0 million of the Notes. We used the proceeds of this offering, together with borrowings under First Lien Agreement, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”). The weighted average interest rate at December 31, 2010 was 9.01% as compared to the weighted average interest rate at September 30, 2011 of 8.23%.

First Lien Credit — Prior to the 2011 Refinancing, our first lien credit agreement (the “Prior First Lien Agreement”) among Milagro Exploration, LLC and Milagro Producing, LLC, each an indirect wholly-owned subsidiary of the Company (collectively, the “Borrowers”), the Company, each of the lenders from time to time party thereto and Wells Fargo Bank, N.A. as administrative agent for the lenders, provided for a borrowing base of $179 million. The borrowing base was calculated using -the estimated value of the Company’s oil and natural gas properties, was redetermined on a semi-annual basis (with the Company and the lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on the Company’s oil and natural gas properties, reserves, other indebtedness and other relevant factors.

Amounts outstanding under the Prior First Lien Agreement bore interest at specified margins over LIBOR of between 3.00% and 3.75% for Eurodollar loans or at specified margins over the ABR of between 2.00% and 2.75% for ABR loans. Such margins fluctuated based on the utilization of the facility. As of December 31, 2010, the LIBOR based interest rate was 4.04% and the base-rate interest rate was 6.00%. Borrowings under the Prior First Lien Agreement were secured by all of the Company’s oil and natural gas properties. The lenders’ commitments to extend credit were scheduled to expire, and amounts drawn under the Prior First Lien Agreement would have matured, in November 2011.

As part of the 2011 Refinancing, the Company entered into a $300 million Amended and Restated First Lien Credit Agreement (“2011 First Lien Agreement”) that matures in November 2014. The 2011 First Lien Agreement also includes a $10.0 million subfacility for standby letters of credit, of which approximately $1.6 million has been issued as of September 30, 2011, and a discretionary swing line subfacility of $5.0 million. The initial borrowing base for this facility was established at $170 million with semi-annual re-determinations to begin in November 2011. Amounts outstanding under the 2011 First Lien Agreement 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. As of September 30, 2011, the LIBOR based interest rates ranged from 3.79% to 3.81% and the base interest rate was 5.75%. Borrowings under the 2011 First Lien Agreement 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 First Lien Agreement will mature, in November 2014.

The 2011 First Lien Agreement 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 First Lien Agreement to current liabilities) of not less than 1.0 to 1.0 (which was 1.48 as of September 30, 2011), minimum interest coverage ratio, as defined, of not less than 2.25 to 1.0 (which was 3.86 as of September 30, 2011), maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.5 to 1.0 (which was 3.80 as of September 30, 2011) and maximum secured leverage ratio, as defined, of secured debt balances as compared to EBITDA of not greater than 2.0 to 1.0 (which was 1.32 as of September 30, 2011). The interest coverage ratio increases from 2.25 to 1.0 during 2011 and 2.5 to 1.0 thereafter. The leverage ratio, as defined, reduces from 4.5 to 1.0 during 2011 to 4.25 to 1.0 during 2012 and 4.0 to 1.0 thereafter. 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, 2011, the Company is in compliance with the financial covenants governing the 2011 First Lien Agreement.

Second Lien — As part of the 2010 recapitalization, the Borrowers entered into a Term Loan Agreement (the “Prior Second Lien Term Loan Agreement”) between the Borrowers, each of the lenders from time to time party thereto and Guggenheim Corporate Funding, LLC, as administrative agent. The Term Loan Agreement provides for three types of loans which are the Term Loans (new loans advanced in full on the closing date), the Delayed Draw Loans (term loans available to be drawn in the future based on certain terms and conditions), and the Converted Loans (existing loans converted from our prior second lien credit agreement). As of December 31, 2010 the interest rate was 10.25%. As part of the 2010 recapitalization, the Borrowers and the certain of the prior second lien debt holders entered into a Second Lien Payable-in-Kind Facility Agreement (the “Prior Second Lien PIK Facility”), in which the prior second lien debt holders which did not convert their loans under the Prior Second Lien Term Loan Agreement agreed to continue their existing loans consisting of principal and accrued interest totaling approximately $62.6 million.

Concurrently with the closing of the 2011 Refinancing, the Company repaid in full the approximately $152.6 million in aggregate principal amount outstanding under the Prior Second Lien Credit Agreement and the Prior Second Lien PIK Facility, together with the accrued interest thereon to the date of such repayment.

Series A Preferred Stock — As part of the 2010 recapitalization, the Company entered into agreements to exchange a portion of prior second lien indebtedness for $205.5 million of Series A Preferred Stock (the “Series A”), consisting of 2,700,000 shares issued at $76.12 per share, mandatorily redeemable in 2016. The preferred shareholders receive a 12% dividend each year paid in-kind. There were no dividends paid during 2010 or during the nine months ended September 30, 2011. There was an increase of approximately $10.3 million of Series A from December 31, 2010 to May 11, 2011, which was primarily related to the accrual of the in-kind dividend that was recorded as interest expense. Upon completion of the 2011 Refinancing, including the amendment of the terms of the Series A as described in Note 9, we reclassified the Series A as mezzanine equity for financial reporting purposes because there is no longer a mandatory redemption provision.

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, 2011 and December 31, 2010, the Company had deferred financing fees of $8.4 million and $2.1 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, 2011 and 2010, the Company capitalized interest of $0.4 million and $0.6 million, respectively. For the nine months ended September 30, 2011 and 2010, the Company capitalized interest of $0.8 million and $1.7 million, respectively.

Senior Secured Second Lien Notes — As part of the 2011 Refinancing, the Company issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7.0 million (the “Notes”). The Notes carry a face interest rate of 10.500%, interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 First Lien Agreement, and effectively rank junior to any existing and future first lien secured indebtedness of the Company. The outstanding balance of the Notes is presented net of unamortized discount of $6.5 million at September 30, 2011.

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

In connection with the offering of the Notes, the Company entered into a registration rights agreement with the initial purchasers. Under the terms of the registration rights agreement, the Company has filed a registration statement, which must be declared effective no later than 300 days after the closing date, to allow for the registration of “exchange notes” with terms substantially identical to the Notes. The exchange notes are to be exchanged for the Notes within 30 days after the registration statement becomes effective. If the Company fails to comply with these requirements on or before the date specified, then the Company will pay special interest to each holder of entitled securities until all registration defaults have been cured. With respect to the first 90-day period immediately following the occurrence of the first registration default, special interest will be paid at the rate of 0.25% per annum. Such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults have been cured, up to a maximum rate of special interest for all registration defaults of 1.0% per annum.

8. GUARANTOR AND NON-GUARANTOR

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

9. MEZZANINE EQUITY

In connection with the 2011 Refinancing, the Company amended the terms of the Series A. Prior to the amendment, the Series A was treated as debt for accounting purposes, as there was a mandatory redemption date. The amendment made the Series A a perpetual instrument and provides the holders with an option to redeem the preferred shares. The amendment also 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, as a result of the amendment, the Series A was reclassified from long-term debt to mezzanine equity.

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, 2011, the dividends in arrears were $11.2 million.

The fair value of the Series A approximates the carrying value at the time of the 2011 Refinancing.

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

11. INCOME TAXES

We recorded no income tax benefit for the nine months ended September 30, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2010 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 assets as of September 30, 2011.

As of September 30, 2011, we had no unrecognized tax benefits. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to 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, 2011 and 2010 and was approximately $1.3 million and $1.6 million for the nine months ended September 30, 2011 and 2010, respectively.

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 2011. The Company paid $0.3 million in fees out of the $1.0 million to the investment bank in connection with the 2011 Refinancing.

The following table summarizes the Company’s contractual obligations and commitments at September 30, 2011, by fiscal year (amounts in thousands):

		2011				2012				2013				2014				2015				Thereafter				Total
Office lease		$	442			$	1,798			$	1,884			$	1,913			$	1,913			$	3,188			$	11,138
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 unaudited condensed 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. For the three months ended September 30, 2011 and 2010, the Company contributed $122,000 and $63,000, respectively. For the nine months ended September 30, 2011 and 2010, the Company contributed $484,000 and $221,000, respectively.

14. RELATED PARTY TRANSACTIONS

As of September 30, 2011 and December 31, 2010, the Company had a receivable of $2.2 million for 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

The FASB issued authoritative guidance establishing standards for reporting information about operating segments. 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 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.

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 unaudited condensed 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 registration statement on Form S-4, File No. 333-177534 filed on October 27, 2011 and 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, exploitation, development and production of oil and natural gas reserves. We were formed as a limited liability company in 2005 with a focus on properties located onshore in the U.S. Gulf Coast. In November 2007, we acquired the Gulf Coast assets of Petrohawk Energy Corporation for approximately $825.0 million. The acquisition was funded through borrowings under our prior first lien credit agreement and our prior second lien credit agreement. The acquisition included properties primarily in the onshore Gulf Coast region in Texas, Louisiana and Mississippi. Since this acquisition, we have acquired additional proved producing reserves that we believe have upside potential, implemented an active drilling, workover and recompletion program and expanded our geographic diversity by moving into the Midcontinent area.

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

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

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250.0 million of our 10.500% Senior Second Lien Notes due 2016 (the “Notes”). We used the proceeds of this offering, together with borrowings under our amended and restated first lien credit agreement (the “New Credit Facility”), to refinance substantially all of our existing indebtedness (the “2011 Refinancing”). See “Liquidity and Capital Resources-” for more on our capital expenditures.

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

Sources of Our Revenues

We derive our revenues from the sale of oil and natural gas that are produced from our properties. Our revenues are a function of the production volumes we sell and the prevailing market prices at the time of sale. Under the terms and conditions of our New Credit Facility, we are required to hedge at least 50% but no more than 90% of our monthly forecasted proved developed producing (“PDP”) production by product. We are permitted to use zero-cost collars and out-right swaps with approved counterparties to meet this requirement. The approved counterparties are limited to those financial institutions that participate in the New Credit Facility. We had until September 8, 2011 to meet the 50% and 90% hedging tests. As of September 30, 2011, we had the following hedged positions:

% of PDP Hedged
Year		Oil				Natural gas				NGLs
2011			81	%			78	%			88	%
2012			86	%			62	%			74	%
2013			79	%			53	%			60	%
2014			77	%			51	%			63	%

In our effort to achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. As of September 30, 2011, we had hedging contracts in place for 501,994 Boe from October 1, 2011, through the end of 2011, 1,458,736 Boe during 2012, 999,600 Boe during 2013 and 793,337 Boe during 2014. Based on the expected production set forth in our September 1, 2011 reserve report, we have hedged approximately 66% of our forecasted 2011, 2012, 2013 and 2014 PDP production as of September 30, 2011. In 2010, we realized commodity hedging gains of approximately $39.4 million, but we expect this to be significantly less in 2011. As of September 30, 2011, we have realized commodity hedging gains of approximately $12.5 million, and unrealized hedging gains of approximately $9.8 million. The use of certain types of derivative instruments may prevent us from realizing the benefit of upward price movements for the portion of the production that is hedged. As of September 30, 2011, we have met the above stated hedging obligations.

Components of Our Cost Structure

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

•

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

•

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

•

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

•

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

•

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

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

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

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

Interest. We have relied on a series of debt financings to fund our short-term liquidity and a portion of our long-term financing needs. On December 31, 2010, we had approximately $337.0 million of LIBOR-based floating rate indebtedness outstanding under our prior first lien credit agreement and prior second lien credit agreements. In addition, our Series A preferred stock carries a non-cash cumulative coupon of 12% per annum.

As part of the Refinancing, we issued $250 million of the Notes and entered into the New Credit Facility which provides for a current borrowing base of $170 million. Interest on the New Credit Facility is calculated based on floating rates of LIBOR and Base Rate with a sliding margin that reflects usage under the facility. The higher the usage under this New Credit Facility, the higher the interest margin over the floating rate index. We expect to continue to utilize indebtedness to grow and, as a result, expect to continue to pay interest throughout the term of the Notes. On September 30, 2011 we had $371.0 million outstanding of indebtedness.

Income Taxes. We recorded no income tax benefit or expense for the nine months ended September 30, 2011. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2010 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, 2011.

As of September 30, 2011, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2010. 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 and Natural Gas Reserves

Our estimated total proved reserves of oil and natural gas as of September 30, 2011 and 2010 were as follows:

		As of September 30,
		2011				% Chg				2010
Estimated Proved Reserves:
Oil and NGLs (MMBbls)			13.9				28	%			10.9
Natural gas (Bcf)			141.0				15	%			122.9
Total oil equivalent (MMBoe)			37.4				19	%			31.4
Proved developed reserves as a percentage of net proved reserves			64	%							72	%

Our estimated total proved reserves increased 19% in the period ended September 30, 2011 as compared to the same period in 2010. This increase in our estimated proved reserves was primarily the result of additional reserves obtained through two acquisitions completed in December 2010 and September 2011.

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 herein. Comparative results of operations for the periods indicated are discussed below.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Sales Volumes

		Three Months Ended September 30,
		2011				% Change				2010
Oil and NGLs (MBbls)			245				(2	)%			251
Natural gas (MMcf)			2,726				(21	)%			3,436
Total (MBoe)			699				(15	)%			824
Average daily production volumes (MBoe/d)(a)			7.60				(15	)%			8.96

For the three months ended September 30, 2011 and 2010, our net equivalent production volumes decreased by 15% to 699 MBoe (7.60 MBoe/d) from 824 MBoe (8.96 MBoe/d) in 2010. Our production volumes in 2011 as compared to 2010 decreased primarily due to natural decline in production and the shutting in of producing properties in Louisiana due to flooding from the Mississippi River. This decrease was partially offset by increased production related to an acquisition in December 2010. Natural gas represented approximately 65% and 70% of our total production in the three months ended September 30, 2011 and 2010, respectively.

Revenues. The following tables show (1) the average prices we received, (2) our revenues from the sale of oil and natural gas and (3) the impact of changes in price and sales volumes on our oil and natural gas revenues during the three months ended September 30, 2011 and 2010. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.

		Three Months Ended September 30,
		2011				% Change				2010
Oil revenues:
Oil price per Bbl		$	85.78				21	%		$	70.86
Oil derivative settlement gains (losses) per Bbl			(2.11	)			(484	)%			0.55
Oil revenues including oil derivative settlements per Bbl		$	83.67				17	%		$	71.41
Natural gas revenues:
Natural gas per Mcf		$	4.07				(7	)%		$	4.36
Natural gas derivative settlement gains (losses) per Mcf			0.86				(65	)%			2.46
Natural gas revenues including derivative settlements per Mcf		$	4.93				(28	)%		$	6.82
Oil and natural gas revenues:
Oil and natural gas per BOE		$	45.94				16	%		$	39.76
Oil and natural gas derivative settlement gains (losses) per BOE			2.60				(75	)%			10.42
Oil and natural gas revenues including derivative settlement gains (losses) per BOE		$	48.54				(3	)%		$	50.18
Oil and natural gas derivative unrealized gains (losses) per BOE			34.43				(4150	)%			(0.85	)
Oil and natural gas revenues including derivative settlements and unrealized gains (losses) per BOE		$	82.97				68	%		$	49.33
Total price per BOE		$	82.97				68	%		$	49.33

		Three months ended September 30,
		2011				% Change				2010
		(In thousands)
Oil revenues:
Oil revenues		$	21,014				18	%		$	17,787
Oil derivative settlements			(516	)			(476	)%			137
Oil revenues including oil derivative settlements			20,498				14	%			17,924
Natural gas revenues:
Natural gas revenues			11,098				(26	)%			14,974
Natural gas derivative settlements			2,331				(72	)%			8,452
Natural gas revenues including derivative settlements			13,429				(43	)%			23,426
Oil and natural gas revenues:
Oil and natural gas revenues			32,112				(2	)%			32,761
Oil and natural gas derivative settlements			1,815				(79	)%			8,589
Oil and natural gas revenues including derivative settlement gains (losses)			33,927				(18	)%			41,350
Oil and natural gas derivative unrealized gains (losses)			24,068				3534	%			(701	)
Oil and natural gas revenues including derivative settlements and unrealized gains (losses)			57,995				43	%			40,649
Total revenues		$	57,995				43	%		$	40,649

		Change from Three Months
		Ended September 30, 2010 to Three
		Months Ended September 30, 2011
		(In thousands)
Change in revenues from the sale of oil:
Price variance impact		$	3,694
Sales volume variance impact			(467	)
Total change			3,227
Change in revenues from the sale of natural gas:
Price variance impact		$	(779	)
Sales volume variance impact			(3,097	)
Total change			(3,876	)
Change in revenues from the sale of oil and natural gas:
Price variance impact		$	2,915
Volume variance impact			(3,564	)
Cash settlement of derivative hedging contracts			(6,774	)
Unrealized gains due to derivative hedging contracts			24,768
Total change		$	17,345

Our oil and natural gas revenues, including derivatives settlements and unrealized gains (losses), for the three months ended September 30, 2011 increased by approximately $17.3 million, or 43%, when compared to the same period in 2010. The pre-hedged revenue decreased by approximately $0.6 million. This change is the result of higher prices of oil of approximately $3.7 million, which was partially offset by lower natural gas prices of approximately $0.8 million and lower production, which decreased revenue by approximately $3.6 million. The increase in hedged gains was due primarily to gains on unrealized commodity derivatives of approximately $24.8 million which were offset by realized losses of settled commodity derivatives of approximately $6.8 million.

Production costs. Production volumes in the three months ended September 30, 2011 decreased 15% as compared to the same period in 2010 from 0.7 MMBoe to 0.8 MMBoe. Per unit production cost in 2011 increased by $1.78/Boe, or 12%, and total production costs in 2011 decreased by $0.6 million, or 5%, as compared to 2010. Our per unit and total production costs for the three months ended September 30, 2011 and 2010 are as set forth below.

		Unit-of-Production
		(Per Boe Based on Sales Volumes)
		Three months ended September 30,
		2011				% Change				2010
Production costs:
Gathering & transportation		$	0.53				51	%		$	0.35
Operating & maintenance			10.70				10	%			9.70
Workover expenses			1.21				0	%			1.21
Lease operating expenses			12.44				10	%			11.26
Remediation expenses			0.01				100	%			—
Taxes other than income			3.74				19	%			3.13
Production costs		$	16.19				13	%		$	14.39

		Production Costs
		Three months ended September 30,
		2011				% Change				2010
		(In thousands)
Production costs:
Gathering & transportation		$	371				30	%		$	286
Operating & maintenance			7,477				(6	)%			7,996
Workover expenses			847				(15	)%			999
Lease operating expenses			8,695				(6	)%			9,281
Remediation expenses			5				100	%			—
Taxes other than income			2,611				1	%			2,580
Production costs		$	11,311				(5	)%		$	11,861

Operating and maintenance expenses for the three months ended September 30, 2011 were approximately $7.5 million, compared to approximately $8.0 million in the same period of 2010, a decrease of approximately $0.5 million, or 6%. This decrease in operating and maintenance expenses was due primarily to the collection of insurance proceeds of $0.5 million related to business interruption from the flooding of the Mississippi river.

Workover expenses for the three months ended September 30, 2011 were approximately $0.8 million, compared to approximately $1.0 million for the same period in 2010, a decrease of approximately $0.2 million, or 15%. This decrease was due primarily to a decrease in the number and cost of our workovers in 2011 as compared to 2010.

Environmental remediation expenses for the three months ended September 30, 2011 were approximately $5,000 and were incurred in 2011 as the result of our participation in a settlement involving environmental remediation in a field in which we have an ownership interest. There were no remediation costs incurred in the 2010 period.

Taxes other than income for the three months ended September 30, 2011 and 2010 were approximately $2.6 million for both periods and consisted primarily of production and ad valorem tax.

General and administrative expenses. We capitalize a portion of our general and administrative expenses. Capitalized expenses include the cost of technical employees who work directly on our exploration activities, a portion of our associated technical organization expenses such as supervision, telephone and postage, and a portion of our interest on unproved capital projects. Our total general and administrative expenses (gross, capitalized and net) and our per unit general and administrative expenses for the three months ended September 30, 2011 and 2010 were as follows:

		Three months ended September 30,
		2011				% Change				2010
		(In thousands, except per unit measurements which are based on sales volumes)
General and administrative expenses — gross		$	4,328				(15	)%		$	5,069
Capitalized general and administrative expenses			1,128				20	%			942
General and administrative costs — net		$	3,200				(22	)%		$	4,127
General and administrative expenses — gross $ per Boe		$	6.19				1	%		$	6.15

Our gross general and administrative expenses for the three months ended September 30, 2011 were approximately $4.3 million compared to approximately $5.1 million in the same period of 2010, a decrease of approximately $0.7 million, or 15%, primarily as a result of there being no stock-based compensation expense in 2011, as compared to $0.4 million in 2010. After capitalization, our general and administrative expenses decreased by approximately $0.9 million, or 22%, to approximately $3.2 million. Per unit general and administrative expense increased slightly due to a decrease in production volumes that was offset by the decrease in compensation expense and increase in capitalized expenses.

Depletion of oil and natural gas properties.

		Three months ended September 30,
		2011				% Change				2010
		(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil and natural gas properties		$	12,119				(10	)%		$	13,447
Depletion of oil and natural gas properties (per Boe)		$	17.34				6	%		$	16.32

Our depletion expense for the three months ended September 30, 2011 was approximately $12.1 million compared to approximately $13.4 million in the same period of 2010, a decrease of approximately $1.3 million, or 10%. This decrease in depletion expense was largely the result of decreased production volumes, which resulted in lower depletion expense by approximately $2.0 million. This was partially offset by an increase in our depletion rate resulting in an increase in depletion expense of approximately $0.7 million.

Net interest expense. Our interest expense for the three months ended September 30, 2011 and 2010 was approximately $8.4 million and $12.1 million, respectively. Total interest expense for the three months ended September 30, 2011 benefited from our 2011 Refinancing that converted the Series A preferred stock from a debt instrument to mezzanine equity, offset by the increase in interest expense due to the assumption of a higher coupon on the Notes.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Sales Volumes

		Nine Months Ended September 30,
		2011				% Change				2010
Oil and NGLs (MBbls)			750				1	%			740
Natural gas (MMcf)			8,616				(18	)%			10,527
Total (MBoe)			2,186				(12	)%			2,495
Average daily production volumes (MBoe/d)(a)			8.01				(12	)%			9.14

For the nine months ended September 30, 2011 and 2010, our net equivalent production volumes decreased by 12% to 2,186 MBoe (8.0 MBoe/d) from 2,495 MBoe (9.1 MBoe/d) in 2010. Our production volumes in 2011 as compared to 2010 decreased primarily due to natural decline in production and the shutting in of producing properties in Louisiana due to flooding from the Mississippi River. This decrease was partially offset by increased production related to an acquisition in December 2010. Natural gas represented approximately 66% and 70% of our total production in the nine months ended September 30, 2011 and 2010, respectively.

Revenues. The following tables show (1) the average prices we received, (2) our revenues from the sale of oil and natural gas and (3) the impact of changes in price and sales volumes on our oil and natural gas revenues during the nine months ended September 30, 2011 and 2010. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to our consolidated statement of operations within a single income statement line item. We include both commodity derivative settlements and unrealized commodity derivative gains (losses) within revenues.

		Nine Months Ended September 30,
		2011				% Change				2010
Oil revenues:
Oil price per Bbl		$	88.06				23	%		$	71.81
Oil derivative settlement gains (losses) per Bbl			(7.32	)			(2,915	)%			0.26
Oil revenues including oil derivative settlements per Bbl		$	80.74				12	%		$	72.07
Natural gas revenues:
Natural gas per Mcf		$	4.12				(10	)%		$	4.59
Natural gas derivative settlement gains (losses) per Mcf			2.09				(15	)%			2.45
Natural gas revenues including derivative settlements per Mcf		$	6.21				(12	)%		$	7.04
Oil and natural gas revenues:
Oil and natural gas per BOE		$	46.46				14	%		$	40.65
Oil and natural gas derivative settlement gains (losses) per BOE			5.74				(45	)%			10.43
Oil and natural gas revenues including derivative settlement gains (losses) per BOE		$	52.20				2	%		$	51.08
Oil and natural gas derivative unrealized gains (losses) per BOE			4.47				188	%			1.55
Oil and natural gas revenues including derivative settlements and unrealized gains (losses) per BOE		$	56.67				8	%		$	52.63
Total price per BOE		$	56.67				8	%		$	52.63

		Nine months ended September 30,
		2011				% Change				2010
		(In thousands)
Oil revenues:
Oil revenues		$	66,047				24	%		$	53,140
Oil derivative settlements			(5,491	)			(2,916	)%			195
Oil revenues including oil derivative settlements			60,556				14	%			53,335
Natural gas revenues:
Natural gas revenues			35,530				(26	)%			48,291
Natural gas derivative settlements			18,039				(30	)%			25,838
Natural gas revenues including derivative settlements			53,569				(28	)%			74,129
Oil and natural gas revenues:
Oil and natural gas revenues			101,577				0	%			101,431
Oil and natural gas derivative settlements			12,548				(52	)%			26,033
Oil and natural gas revenues including derivative settlement gains (losses)			114,125				(10	)%			127,464
Oil and natural gas derivative unrealized gains (losses)			9,770				152	%			3,873
Oil and natural gas revenues including derivative settlements and unrealized gains (losses)			123,895				(6	)%			131,337
Total revenues		$	123,895				(6	)%		$	131,337