UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

☐ 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

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  ☒    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  ☒    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.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐

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

As of August 13, 2013, 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)
Unaudited Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	3
Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	5
Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	6
Notes to the Unaudited Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3. Quantitative and Qualitative Disclosure about Market Risk	34
Item 4. Controls and Procedures	36
PART II. Other Information
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3. Defaults Upon Senior Securities	38
Item 4. Mine Safety Disclosure	38
Item 5. Other Information	38
Item 6. Exhibits	39

2

PART I

Item  1. Financial Statements

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	13,581		$	2,188
Accounts receivable:
Oil, NGL and natural gas sales		20,486			19,728
Joint interest billings and other — net of allowance for doubtful accounts of $691 and $719 at June 30, 2013 and December 31, 2012, respectively		1,342			977
Derivative assets		1,027			873
Deferred taxes		221			29
Prepaid expenses and other		2,639			4,001
Total current assets		39,296			27,796
PROPERTY, PLANT AND EQUIPMENT (at cost):
Oil, NGL and natural gas properties — full cost method:
Proved properties		1,318,399			1,303,922
Unproved properties		15,703			14,971
Less accumulated depreciation, depletion and amortization		(900,638	)		(877,754	)
Net oil, NGL and natural gas properties		433,464			441,139
Other property and equipment – net of accumulated depreciation of $7,234 and $6,879 at June 30, 2013 and December 31, 2012, respectively		1,246			746
Total property plant and equipment		434,710			441,885
DERIVATIVE ASSETS		775			68
OTHER ASSETS:
Deferred financing fees, net		4,848			5,850
Advance to affiliate		2,416			2,442
Other		1,789			2,719
Total other assets		9,053			11,011
TOTAL	$	483,834		$	480,760

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

3

MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

				June 30,			December 31,
				2013			2012
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES:
		Accounts payable		$	801		$	4,458
		Accrued liabilities			26,691			27,345
		Interest payable			5,027			4,558
		Current debt			379,308			360,265
		Derivative liabilities			405			799
		Deferred taxes			221			29
		Asset retirement obligation			2,793			1,882
			Total current liabilities		415,246			399,336
NONCURRENT LIABILITIES:
		Asset retirement obligation			31,958			35,626
		Derivative liabilities			155			1,127
		Other			1,721			1,777
		Total noncurrent liabilities			33,834			38,530
			Total liabilities		449,080			437,866
MEZZANINE EQUITY
		Redeemable series A preferred stock (Note 10)			236,263			235,694
COMMITMENT AND CONTINGENCIES (Note 13)
STOCKHOLDER’S DEFICIT:
	Common shares, (par value, $.01 per share; shares authorized: 1,000,000; shares issued and outstanding: 280,400 as of June 30, 2013 and December 31, 2012)				3			3
	Additional paid-in capital				(66,813	)		(66,813	)
	Accumulated deficit				(134,699	)		(125,990	)
			Total stockholder’s deficit		(201,509	)		(192,800	)
			TOTAL	$	483,834		$	480,760

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

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MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

		Three Months Ended June 30,						Six Months Ended June 30,
		2013			2012			2013			2012
REVENUES:
	Oil, NGL and natural gas revenues	$	33,463		$	29,266		$	65,539		$	62,606
	Gain on commodity derivatives, net		5,607			17,955			1,803			18,548
	Total revenues		39,070			47,221			67,342			81,154
COSTS AND EXPENSES:
	Gathering and transportation		403			385			803			803
	Lease operating		8,800			8,761			17,899			18,269
	Taxes other than income		2,867			2,799			5,414			5,852
	Depreciation, depletion and amortization		11,630			13,035			23,240			26,105
	Full cost ceiling impairment		-			-			-			11,552
	General and administrative		5,369			3,555			8,839			5,837
	Accretion		759			932			1,509			1,819
	Total costs and expenses		29,828			29,467			57,704			70,237
	Operating income		9,242			17,754			9,638			10,917
OTHER EXPENSE (INCOME):
	Other income		(19	)		(77	)		(37	)		(153	)
	Interest and related expenses, net of amounts capitalized		9,735			8,983			18,385			17,867
	Total other expense		9,716			8,906			18,348			17,714
(LOSS) INCOME BEFORE INCOME TAX			(474	)		8,848			(8,710	)		(6,797	)
INCOME TAX EXPENSE			-			-			-			-
NET(LOSS) INCOME			(474	)		8,848			(8,710	)		(6,797	)
Preferred dividends			8,805			7,836			17,238			15,422
NET (LOSS) INCOME AVAILABLE TO COMMON SHAREHOLDERS		$	(9,279	)	$	1,012		$	(25,948	)	$	(22,219	)

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

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MILAGRO OIL AND GAS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(8,710	)	$	(6,797	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization		23,240			26,105
Full cost impairment		—			11,552
Amortization of deferred financing costs		1,002			1,003
Accretion of asset retirement obligations		1,509			1,819
Recapitalization of debt loss		568			568
OID interest		693			693
Unrealized gain on commodity derivatives		(2,227	)		(7,864	)
Changes in assets and liabilities — net of acquisitions:
Accounts receivable and accrued revenue		(1,123	)		3,642
Prepaid expenses and other		1,363			77
Accounts payable, accrued liabilities and other		(5,679	)		(4,818	)
Other		929			(500	)
Net cash provided by operating activities		11,565			25,480
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil, NGL and natural gas properties		(19,965	)		(14,158	)
Additions of other long term assets		(855	)		(58	)
Proceeds from sale of oil, NGL and natural gas properties		2,271			135
Net cash used in investing activities		(18,549	)		(14,081	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		21,350			26,250
Payments of borrowings		(3,000	)		(45,500	)
Other		27			(108	)
Net cash provided (used in) by financing activities		18,377			(19,358	)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS	$	11,393		$	(7,859	)
CASH AND CASH EQUIVALENTS — Beginning of period	$	2,188		$	9,356
CASH AND CASH EQUIVALENTS — End of period	$	13,581		$	1,397
INCOME TAX PAID, Net of refunds	$	—		$	—
INTEREST PAID — Net of interest capitalized of $507 and $522 in 2013 and 2012, respectively	$	15,165		$	15,426
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital costs included in proved properties	$	4,441		$	2,406
Asset retirement obligations incurred	$	28		$	447

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

6

MILAGRO OIL & GAS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2013 AND 2012

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 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, 2012. The operating results for the three months and six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the full year.

2.     LIQUIDITY AND GOING CONCERN

The Company currently has indebtedness outstanding under the 2011 Credit Facility (as defined in Note 8), which contains customary financial and other covenants. The Company is not in compliance with the financial covenants.   The maximum leverage ratio, as defined, of debt balances as compared to EBITDA is required to be not greater than 4.0 to 1.0, but was 4.93 as of June 30, 2013. The minimum interest coverage ratio, as defined, of EBITDA to interest expense is required to be not less than 2.5 to 1.0, but was 2.36 as of June 30, 2013.

The Company is currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the leverage ratio and interest coverage ratio. Alternatives that were considered include using cash flow from operations or issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.  As another alternative, the Company has launched a private exchange offering to exchange a portion of the Notes (as defined in Note 8) for equity, cash and/or new notes (“Exchange Offer”). If a minimum principal amount of at least $237.5 million of the outstanding principal amount of the Notes are not tendered (excluding any such Notes validly withdrawn) in the Exchange Offer, the conditions to the Exchange Offer will not have been achieved and the Company will be unable to consummate the restructuring.  As a result, the lenders under the 2011 Credit Facility may accelerate their debt, which would also cause a default and acceleration of the debt under the Notes, all of which will have a material adverse effect on our liquidity, business and financial condition and may result in the Company’s bankruptcy or the bankruptcy of its subsidiaries. Any actual or potential bankruptcy or liquidity crisis may materially harm the Company’s relationships with its customers, affiliates and suppliers and otherwise result in significant permanent harm to the Company’s ability to operate its business. If the Exchange Offer is not consummated and, as a result, the possible early maturity of the 2011 Credit Facility is not resolved, the Company’s customers, affiliates and suppliers may determine that the Company is likely to face a potential bankruptcy or liquidity crisis and the harm to these relationships, the Company’s market share and other aspects of the Company’s business may occur immediately.  

7

The Company is in breach of its financial covenants as of June 30, 2013. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of these covenant breaches, the Company has classified approximately $133.4 million of borrowings under the 2011 Credit Facility and approximately $245.9 million of the Notes as current liabilities.  At June 30, 2013, this results in current liabilities exceeding current assets by approximately $375.9 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent the Company from borrowing additional funds under the 2011 Credit Facility.

Effective June 14, 2013, the Company and the lenders under the 2011 Credit Facility entered into a Forbearance and Consent Agreement. Under the terms of the Forbearance and Consent Agreement, the lenders agreed to forbear, until July 15, 2013 from exercising their rights and remedies, under the 2011 Credit Facility. This forbearance expired on July 15, 2013 and the lenders have taken no further action.

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

3.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of critical accounting policies is disclosed in Note 4 to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012. 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. Except as noted below, there have been no changes to our significant accounting policies since such date.

Impairment of oil, NGL and natural gas properties. For the six months ended June 30, 2013, based on the average oil and natural gas prices in effect on the first day of each month during the first six months of 2013 and last six months of 2012 ($3.44 per MMBtu for Henry Hub gas and $91.60 per Bbl for West Texas Intermediate oil, adjusted for differentials), the Company was not required to record an impairment to its oil, NGL and natural gas properties. For the six months ended June 30, 2012, the Company reported an impairment of approximately $11.6 million to its oil, NGL and natural gas properties. The impairment occurred and was recorded 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 months of 2011 ($3.53 per MMBtu for Henry Hub gas and $94.65 per Bbl for West Texas Intermediate oil, adjusted for differentials). In addition, the unamortized cost of the Company’s oil and natural gas properties exceeded the ceiling limit and the Company recorded an impairment of approximately $11.6 million to its oil and natural gas properties.

Recently Issued Accounting Pronouncements —

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 adopted this standard effective January 1, 2013. See Note 7.

The FASB recently issued ASU 2013-01 which clarifies which instruments and transactions are subject to the offsetting disclosure requirementsestablished by ASU 2011-11.The new ASU addresses preparer concerns that the scope of the disclosure requirements under ASU 2011-11 was overly broad and imposed unintended costs that were not commensurate with estimated benefits to financial statement users. In choosing to narrow the scope of the offsetting disclosures, the FASB determined that it could make them more operable and cost effective for preparers while still giving financial statement users sufficient information to analyze the most significant presentation differences between financial statements prepared in accordance with U.S. GAAP and those prepared under IFRS.

Like ASU 2011-11, ASU 2013-01 is effective for all entities (public and nonpublic) for fiscal years beginning on or after January 1, 2013, and interim periods therein. Therefore, calendar year-end public filers needed to include the disclosures in their first-quarter Form 10-Q filings for 2013. Retrospective application is required for any period presented that begins before the entity’s initial application of the new requirements.  See Note 7.

8

4.     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 six months ended June 30, 2013 and 2012, the Company’s most significant customers by reference to oil, NGL and natural gas revenue were as follows:

	2013		2012
Shell Trading (US) Company	17	%	21	%
Enterprise Crude Oil, LLC	28	%	18	%
Smaller customers, less than 2%	55	%	61	%

5.     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 six months ended June 30, 2013 is as follows (in thousands):

Liability for asset retirement obligation — December 31, 2012	$	37,508
Settlements		(477	)
Additions		28
Revisions		(352	)
Accretion expense		1,509
Divestitures		(3,465	)
Liability for asset retirement obligation — June 30, 2013	$	34,751

The liability comprises a current balance of approximately $2.8 million and a noncurrent balance of approximately $32.0 million as of June 30, 2013.

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

6.     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 line item. For the six months ended June 30, 2013, the Company had commodity derivatives in place for 829.9 MBoe, or approximately 68% of production, in the form of oil, NGL and natural gas collars and swaps. Oil contracts settle against NYMEX West Texas Intermediate (WTI) prices, gas contracts settle against NYMEX Henry Hub prices and NGL contracts settle against Mont Belvieu Oil Price Information System (OPIS) prices.

9

Periodically the Company evaluates the unrealized commodity derivatives to determine if it would be beneficial to liquidate any contracts early. During the six months ended June 30, 2013, the Company did not liquidate any commodity contracts early.

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 price on the derivative contract . 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. As of June 30, 2013, no counterparties had executed swaption 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	June 30		December 31
Asset derivatives:
Natural gas collars and swaps — current portion	Derivative assets — current	$	312	$	836
Noncurrent portion	Derivative assets — noncurrent		—		68
Oil collars and swaps — current portion	Derivative assets —current		26		37
Noncurrent portion	Derivative assets — noncurrent		474		—
NGL collars and swaps — current portion	Derivative assets —current		689		—
Noncurrent portion	Derivative assets — noncurrent		301		—
		$	1,802	$	941
Liability derivatives:
Natural gas collars and swaps — current portion	Derivative liabilities — current	$	70	$	179
Noncurrent portion	Derivative liabilities — noncurrent		155		470
Oil collars and swaps — current portion	Derivative liabilities — current		335		590
Noncurrent portion	Derivative liabilities — noncurrent		—		550
NGL collars and swaps — current portion	Derivative liabilities — current		—		30
Noncurrent portion	Derivative liabilities — noncurrent		—		107
		$	560	$	1,926

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

Description	Location in Statements of Operations	Three Months Ended June 30,					Six Months Ended June 30,
		2013			2012		2013			2012
		(in thousands)
Commodity contracts:
Realized (loss)/gain on commodity contracts	Gain on commodity derivatives, net	$	(598	)	$	6,567	$	(424	)	$	10,684
Unrealized gain on commodity contracts	Gain on commodity derivatives, net		6,205			11,388		2,227			7,864
Total net gain on commodity contracts		$	5,607		$	17,955	$	1,803		$	18,548

10

At June 30, 2013, 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
Jul 2013 – Dec 2013		540,000	$	3.50	$	3.50	$	5.75	$	5.75

At June 30, 2013, the Company had the following natural gas swap positions:

	Swaps
Period	Volume in MMbtu’s		Price/ Price Range			Weighted- Average Price
Jul 2013 – Dec 2013		2,071,588	$3.41	–	4.22	$	3.70
Jan 2014 – Dec 2014		4,298,670	3.82	–	4.52		3.97
Jan 2015 – Dec 2015		1,056,000			4.14		4.14

At June 30, 2013, the Company had the following unexecuted natural gas swaption positions:

	Swaptions
Period	Volume in MMbtu’s			Price/ Price Range			Weighted- Average Price
Jan 2014 – Dec 2014		(2,280,000	)	$4.22	–	4.66	$	4.45
Jan 2015 – Dec 2015		(1,380,000	)	4.52	–	4.99		4.83

At June 30, 2013, 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
Jul 2013 – Dec 2013		258,993	$80.00	–	92.00	$	87.82	$95.25	–	103.75	$	99.04
Jan 2014 – Dec 2014		450,301	80.00	–	90.00		84.94	95.25	–	98.50		96.75

At June 30, 2013, the Company had the following crude oil swap positions:

	Swaps
Period	Volume in Bbl’s		Price/ Price Range			Weighted- Average Price
Jul 2013 – Dec 2013		34,403	$83.00	–	91.50	$	85.88
Jan 2014 – Dec 2014		24,000	91.00	–	91.50		91.25

At June 30, 2013, the Company had the following NGL swap positions:

	Swaps
Period	Volume in Bbl’s(a)		Price/Price Range			Weighted- Average Price
Jul 2013 – Dec 2013		92,237	$36.75	–	38.90	$	37.94
Jan 2014 – Dec 2014		159,162	35.90	–	38.24		37.15

(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.

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7.     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 June 30, 2013 and December 31, 2012, 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			Total
	(Level 1)		(Level 2)		(Level 3)		(a)			Balance
June 30, 2013:
Current Assets
Commodity derivatives — natural gas	$	—	$	516	$	—	$	(204	)	$	312
Commodity derivatives — oil		—		320		—		(294	)		26
Commodity derivatives — NGL		—		689		—		—			689
Non-Current Assets
Commodity derivatives — natural gas	$	—	$	33	$	—	$	(33	)	$	—
Commodity derivatives — oil		—		474		—		—			474
Commodity derivatives — NGL		—		301		—		—			301
Current Liabilities
Commodity derivatives — natural gas	$	—	$	274	$	—	$	(204	)	$	70
Commodity derivatives — oil		—		629		—		(294	)		335
Commodity derivatives — NGL		—		—		—		—			—
Non-Current Liabilities
Commodity derivatives — natural gas	$	—	$	188	$	—	$	(33	)	$	155
Commodity derivatives — oil		—		—		—		—			—
Commodity derivatives — NGL		—		—		—		—			—
December 31, 2012:
Current Assets
Commodity derivatives — natural gas	$	—	$	853	$	—	$	(17	)	$	836
Commodity derivatives — oil		—		614		—		(577	)		37
Commodity derivatives — NGL		—		—		—		—			—
Non-Current Assets
Commodity derivatives — natural gas	$	—	$	68	$	—	$	—		$	68
Commodity derivatives — oil		—		—		—		—			—
Commodity derivatives — NGL		—		—		—		—			—
Current Liabilities
Commodity derivatives — natural gas	$	—	$	196	$	—	$	(17	)	$	179
Commodity derivatives — oil		—		1,167		—		(577	)		590
Commodity derivatives — NGL		—		30		—		—			30
Non-Current Liabilities
Commodity derivatives — natural gas	$	—	$	470	$	—	$	—		$	470
Commodity derivatives — oil		—		550		—		—			550
Commodity derivatives — NGL		—		107		—		—			107

(a) Represents the effects of reclassification of the assets and liabilities per master netting agreements to conform to the balance sheet presentation.  All derivative positions are subject to master netting agreements and the Company’s policy is to offset as described below.

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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.

None of the Company’s agreements are subject to collateral requirements.  There is no cash collateral held or paid by the Company.

The Company has trade receivables and trade payables subject to master netting or similar agreements, that are not included in the above tabular disclosure. These amounts may offset (or conditionally offset) the net amounts presented in the above tabular disclosure.

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 June 30, 2013 and December 31, 2012, 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 8) accrues interest on a variable-rate basis. The fair value of the 2011 Credit Facility is characterized as a Level 3 measurement in the fair value hierarchy. The Notes (as defined in Note 8) accrue interest on a fixed rate basis. The fair value of the Notes is characterized as a Level 2 measurement in the fair value hierarchy, as the trading volume is limited. As of June 30, 2013, 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 June 30, 2013 weighted average market price) to be approximately $199.4 million. As of December 31, 2012, the Company estimated the 2011 Credit Facility fair value to be approximately $115.0 million. As of the same date, the fair value of the Notes was estimated to be approximately $185.0 million.

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

8.     DEBT

The Company’s debt as of June 30, 2013 and December 31, 2012 was comprised of the following amounts (in thousands):

	June 30, 2013			December 31, 2012
2011 Credit Facility — current	$	133,350		$	115,000
Notes — current		250,000			250,000
Unamortized discount — current		(4,042	)		(4,735	)
Total debt	$	379,308		$	360,265

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

Years Ending December 31
2013	$	—
2014 (1)		133,350
2015		—
2016 (1)		250,000
2017		—
	$	383,350

(1) Although having a maturity date which is more than 12 months after June 30, 2013, classified as current in financial statements due to the inability to comply with the 2011 Credit Facility maximum leverage ratio and minimum interest coverage ratio as of June 30, 2013. See Note 2 for further discussion.

As described in more detail below, in May 2011, we completed an offering of an aggregate of $250 million of the Notes. We used the proceeds of this offering, together with borrowings under our prior first lien credit agreement, to refinance substantially all of our existing indebtedness (the “2011 Refinancing”). The weighted average interest rate at June 30, 2013 was 9.62% as compared to the weighted average interest rate at December 31, 2012 of 8.36%.

First Lien Credit — During 2011, the Company entered into a $300 million Amended and Restated First Lien Credit Agreement (“2011 Credit Facility”) that matures in November 2014. The 2011 Credit Facility includes a $10.0 million sub facility for standby letters of credit, of which approximately $1.3 million has been issued as of June 30, 2013, and a discretionary swing line subfacility of $5.0 million with semi-annual re-determinations. A borrowing base redetermination was conducted in May of 2013 and no change was made to the existing $135 million borrowing base. As of June 30, 2013 the borrowing base remained at $135 million. Amounts outstanding under the 2011 Credit Facility bear interest at specified margins over LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over the Alternate Base Rate (ABR) of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. As of June 30, 2013, there were no LIBOR based loans and the ABR interest rate was 6.0% plus a 2% penalty spread. Borrowings under the 2011 Credit Facility are secured by all of the Company’s oil, NGL and natural gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 Credit Facility will mature, in November 2014.

The maximum leverage ratio, as defined, of debt balances as compared to EBITDA is required to be not greater than 4.0 to 1.0, but was 4.93 as of June 30, 2013. The minimum interest coverage ratio, as defined, of EBITDA to interest expense is required to be not less than 2.5 to 1.0, but was 2.36 as of June 30, 2013.

The Company is currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the leverage ratio and interest coverage ratio. Alternatives that were considered include using cash flow from operations or issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.  As another alternative, the Company has launched a private exchange offering to exchange a portion of the Notes for equity, cash and/or new notes. If a minimum principal amount of at least $237.5 million of the outstanding principal amount of the Notes are not tendered (excluding any such Notes validly withdrawn) in the Exchange Offer, the conditions to the Exchange Offer will not have been achieved and the Company will be unable to consummate the restructuring. As a result, the lenders under the 2011 Credit Facility may accelerate their debt, which would also cause a default and acceleration of the debt under the Notes, all of which will have a material adverse effect on our liquidity, business and financial condition and may result in the Company’s bankruptcy or the bankruptcy of its subsidiaries. Any actual or potential bankruptcy or liquidity crisis may materially harm the Company’s relationships with its customers, affiliates and suppliers and otherwise result in significant permanent harm to the Company’s ability to operate its business. If the Exchange Offer is not consummated and, as a result, the possible early maturity of the 2011 Credit Facility is not resolved, the Company’s customers, affiliates and suppliers may determine that the Company is likely to face a potential bankruptcy or liquidity crisis and the harm to these relationships, the Company’s market share and other aspects of the Company’s business may occur immediately.  

The Company is not in compliance with its financial covenants at June 30, 2013. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of these covenant breaches, the Company has classified approximately $133.4 million of borrowings under the 2011 Credit Facility and approximately $245.9 million of the Notes as current liabilities.  At June 30, 2013, this results in current liabilities exceeding current assets by approximately $375.9 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent the Company from borrowing additional funds under the 2011 Credit Facility.

Effective June 14, 2013, the Company and the lenders under the 2011 Credit Facility entered into a Forbearance and Consent Agreement. Under the terms of the Forbearance and Consent Agreement, the lenders agreed to forbear, until July 15, 2013 from exercising their rights and remedies, under the 2011 Credit Facility. This forbearance expired on July 15, 2013 and the lenders have taken no further action.

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

  Senior Secured Second Lien Notes — As part of the 2011 Refinancing, the Company issued Senior Secured Second Lien Notes due May 11, 2016 with a face value of $250 million, at a discount of $7 million (the “Notes”). The Notes carry a stated interest rate of 10.500%, interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 Credit Facility, and effectively rank junior to any existing and future first lien secured indebtedness of the Company. The outstanding balance of the Notes is presented net of unamortized discount at June 30, 2013.

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

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 June 30, 2013 and December 31, 2012, the Company had deferred financing fees of approximately $4.8 million and $5.9 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 each of the three months ended June 30, 2013 and 2012, the Company capitalized interest of approximately $0.3 million. For each of the six months ended June 30, 2013 and 2012, the Company capitalized interest of approximately $0.5 million.

9.     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.

10.   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 June 30, 2013 the dividends in arrears were approximately $67.8 million.

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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 June 30, 2013 and at December 31, 2012 was approximately $91.0 million and $218 million, respectively.

11.   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 June 30, 2013, 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.

12.   INCOME TAXES

The Company recorded no income tax benefit for the three months ended June 30, 2013. 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 June 30, 2013.

As of June 30, 2013, the Company had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2012. 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 June 30, 2013.

13.   COMMITMENTS AND CONTINGENCIES

Commitments:

The Company leases corporate office space in Houston, Texas. Rental expense was approximately $0.4 million and $0.6 million for the three months ended June 30, 2013 and 2012, respectively.

In 2012, a Consulting Agreement was entered into with Sequitur Energy Management II, LLC, for management services at a fixed fee of $1.75 million to be performed in 2012 and 2013. The fixed fee is to be paid in 12 monthly installments during the term of this agreement. The amount outstanding as of June 30, 2013, is approximately $0.3 million.

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. The amount outstanding at June 30, 2013 is approximately $0.7 million.  This contract has been extended to 2014.

The following table summarizes the Company’s contractual obligations and commitments at June 30, 2013, by fiscal year (amounts in thousands):

	2013		2014		2015		2016		2017		Thereafter		Total
Office lease	$	939	$	1,879	$	1,879	$	1,879	$	1,253	$	—	$	7,829
Management consulting agreement	$	292		—		—		—		—		—	$	292
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 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.

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14.   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 $210,000 and $136,000, for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, respectively, the Company contributed approximately $383,000 and $381,000.

15.   RELATED PARTY TRANSACTIONS

As of June 30, 2013 and December 31, 2012, the Company had a receivable of approximately $2.4 million 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.

16.   SEGMENT INFORMATION

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

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

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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, 2012, as well as 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 six months ended June 30, 2013, we spent approximately $18.2 million on capital expenditures excluding capitalized general and administrative expenses, before divestitures, to support our business plan. Of this amount, we spent approximately $11.0 million to successfully drill thirteen gross wells and complete eleven of these wells. We also completed two carryover wells that were drilled in 2012. We drilled nine gross (nine net) and completed seven gross (seven net) operated wells in the Texas Gulf Coast area, drilled and completed two gross (0.19 net) non-operated wells in our South Texas area and drilled and completed two gross (0.36 net) non-operated wells in our Midcontinent area. We spent approximately $4.6 million on workovers and recompletions primarily in our Texas Gulf Coast and South Texas areas. We spent approximately $1.1 million of capital expenditures to continue leasing. The remaining approximately $1.5 million of capital expenditures were primarily related to facilities, seismic and plugging and abandonment costs.

We contemplate spending up to an additional approximately $15.2 million for the remainder of 2013 to support our business plan. We are planning to complete two carryover operated wells and drill or participate in up to six additional wells during the remainder of 2013, including two non-operated exploratory wells in our South Texas area; one non-operated development well in our Mid-Continent area; one non-operated development well in our Southeast area; two operated development wells in our Southeast area and one operated exploratory well in our Texas Gulf Coast area; as well as planning on workover and recompletion projects of existing wells.  In light of price volatility, we are constantly evaluating the deployment of our capital. See “Liquidity and Capital Resources” for more on our capital expenditures.

We currently have indebtedness outstanding under the 2011 Credit Facility (as defined below under “-Liquidity and Capital Resources”), which contains customary financial and other covenants.  We are in breach of our financial covenants as of June 30, 2013. The maximum leverage ratio, as defined, of debt balances as compared to EBITDA is required to be not greater than 4.0 to 1.0, but was 4.93 as of June 30, 2013. The minimum interest coverage ratio, as defined, of EBITDA to interest expense is required to be not less than 2.5 to 1.0, but was 2.36 as of June 30, 2013.

We are currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio and minimum interest coverage ratio. Alternatives that were considered include using cash flow from operations or issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.  As another alternative, we have launched a private exchange offering (the “Exchange Offer”) to exchange a portion of the Notes (as defined below under “-Liquidity and Capital Resources”) for equity, cash and/or new notes, which was originally to expire on June 17, 2013, but has been extended to August 30, 2013.  If the conditions to the Exchange Offer are not achieved, we will be unable to consummate the restructuring.  As a result, the lenders under the 2011 Credit Facility may accelerate their debt, which would also cause a default and acceleration of the debt under the Notes, all of which will have a material adverse effect on our liquidity, business and financial condition and may result in our bankruptcy or the bankruptcy of our subsidiaries. Any actual or potential bankruptcy or liquidity crisis may materially harm our relationships with our customers, affiliates and suppliers and otherwise result in significant permanent harm to our ability to operate our business. If the Exchange Offer is not consummated and, as a result, the possible early maturity of the 2011 Credit Facility is not resolved, our customers, affiliates and suppliers may determine that we are likely to face a potential bankruptcy or liquidity crisis and the harm to these relationships, our market share and other aspects of our business may occur immediately.  

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We are in breach of our financial covenants as of June 30, 2013. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of these covenant breaches, we have classified approximately $133.4 million of borrowings under the 2011 Credit Facility and approximately $245.9 million of the Notes as current liabilities.  At June 30, 2013, this results in current liabilities exceeding current assets by approximately $375.9 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent us from borrowing additional funds under the 2011 Credit Facility.

Effective June 14, 2013, the Company and the lenders under the 2011 Credit Facility entered into a Forbearance and Consent Agreement. Under the terms of the Forbearance and Consent Agreement, the lenders agreed to forbear, until July 15, 2013 from exercising their rights and remedies, under the 2011 Credit Facility. This forbearance expired on July 15, 2013 and the lenders have taken no further action.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about our ability to continue as a going concern.  Our condensed consolidated financial statements for the quarter ended June 30, 2013 have been prepared assuming we will continue as a going concern and no adjustments to the financial statements have been made to account for this uncertainty.

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 swaps with approved counterparties to meet this requirement. The approved counterparties are limited to those financial institutions that participate in the 2011 Credit Facility. As of June 30, 2013, we had the following oil, NGL and natural gas commodity derivative positions:

% of PDP Hedged

Year	Oil		Natural Gas		NGL
2013	90.0	%	90.0	%	90.0	%
2014	90.0	%	90.0	%	90.0	%

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 June 30, 2013, we had commodity derivative contracts in place for 821 MBoe from July 1, 2013, through the end of 2013, 1,350 MBoe during 2014 and 176 MBoe during 2015. Based on the expected production set forth in our January 1, 2013 reserve report, we have derivative contracts for approximately 90.0% of our cumulative forecasted 2013 and 2014 PDP production as of June 30, 2013.  For the six months ended June 30, 2013, we had commodity derivative gains of approximately $1.8 million, which is comprised of approximately $0.4 million in realized losses and approximately $2.2 million of unrealized gains. 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.

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• 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 June 30, 2013, we had approximately $133.4 million of LIBOR-based floating rate indebtedness and base rate indebtedness outstanding under our 2011 Credit Facility and $250 million of the Notes outstanding. In addition, our Series A preferred stock carries a non-cash cumulative dividend with a coupon of 12% per annum.

A 2011 Credit Facility borrowing base redetermination was conducted in May of 2013 which resulted in the borrowing base remaining at $135 million. As of June 30, 2013, the borrowing base was $135 million. Interest on the 2011 Credit Facility is calculated based on floating rates of LIBOR and base rate with a sliding margin that reflects usage under the facility. The higher the usage under the 2011 Credit Facility, the higher the interest margin 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 June 30, 2013, we had approximately $379.3 million outstanding of total indebtedness.

Income Taxes. We recorded no income tax benefit or expense for the six months ended June 30, 2013. Prior to 2012, 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 June 30, 2013.

As of June 30, 2013, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2012. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to June 30, 2013.

20

Oil, NGL and Natural Gas Reserves

Our estimated total net proved reserves of oil, NGL and natural gas as of June 30, 2013 and 2012 were as follows:

	As of June 30,
	2013			% Change			2012
Estimated Net Proved Reserves:
Oil (MMBbls)		11.3			5	%		10.8
NGL (MMBbls)		4.6			(2	)%		4.7
Natural Gas (Bcf)		108.7			(10	)%		120.9
Total oil equivalent (MMBoe)		34.0			(5	)%		35.7
Proved developed reserves as a percentage of net proved reserves		58	%		(2	)%		60	%

Our estimated total net proved reserves decreased in the period ended June 30, 2013 as compared to the same period in 2012 by 1.7 MMBoe or a 5% 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.

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Sales Volumes

	Three Months Ended June 30,
	2013		% Change			2012
Oil (MBbls)		236		10	%		214
NGL (MBbls)		64		(2	)%		65
Natural gas (MMcf)		1,843		(22	)%		2,352
Total (MBoe)		607		(10	)%		671
Average daily production volumes (MBoe/d)(a)		6.7		(10	)%		7.4

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

For the three months ended June 30, 2013, our net equivalent production volumes decreased by 10% to 607 MBoe (6.7 MBoe/d) from 671 MBoe (7.4 MBoe/d) in 2012. Our production volumes in 2013, as compared to 2012, decreased primarily as a result of the natural decline in production, the delay of scheduled gas drilling projects due to marginal natural gas prices and a lengthy shut-in at our West Lake Verret field during April. Natural gas represented approximately 51% and 58% of our total production in the three months ended June 30, 2013 and 2012, respectively.

21

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 June 30, 2013 and 2012. 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 June 30,
	2013			% Change			2012
	(In thousands)
Oil revenues:
Oil revenues	$	24,564			10	%	$	22,300
Oil derivative settlements		(164	)		(267	)%		98
Oil revenues including oil derivative settlements		24,400			9	%		22,398
NGL revenues:
NGL revenues		1,809			(13	)%		2,073
NGL derivative settlements		87			(81	)%		454
NGL revenues including derivative settlements		1,896			(25	)%		2,527
Natural gas revenues:
Natural gas revenues		7,090			45	%		4,893
Natural gas derivative settlements		(521	)		(109	)%		6,015
Natural gas revenues including derivative settlements		6,569			(40	)%		10,908
Oil, NGL and natural gas revenues:
Oil, NGL and natural gas revenues		33,463			14	%		29,266
Oil, NGL and natural gas derivative settlements		(598	)		(109	)%		6,567
Oil, NGL and natural gas revenues including derivative settlements		32,865			(8	)%		35,833
Oil, NGL and natural gas derivative unrealized gains		6,205			(46	)%		11,388
Oil, NGL and natural gas revenues including derivative settlements and unrealized gains		39,070			(17	)%		47,221
Total revenues	$	39,070			(17	)%	$	47,221

	Change from Three Months Ended June 30, 2012 to Three Months Ended June 30, 2013
	(In thousands)
Change in revenues from the sale of oil:
Price variance impact	$	(26	)
Sales volume variance impact		2,290
Total change		2,264
Change in revenues from the sale of NGL:
Price variance impact	$	(236	)
Sales volume variance impact		(28	)
Total change		(264	)
Change in revenues from the sale of natural gas:
Price variance impact	$	4,157
Sales volume variance impact		(1,960	)
Total change		2,197
Change in revenues from the sale of oil, NGL and natural gas:
Price variance impact	$	3,895
Volume variance impact		302
Cash settlement of commodity derivative contracts		(7,165	)
Unrealized gains (losses) due to commodity derivative contracts		(5,183	)
Total change	$	(8,151	)

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	Three Months Ended June 30,
	2013			% Change			2012
Oil price:
Oil price per Bbl	$	104.08			0	%	$	104.21
Oil derivative settlements per Bbl		(0.69	)		(250	)%		0.46
Oil revenues including oil derivative settlements per Bbl	$	103.39			(1	)%	$	104.67
NGL price:
NGL price per Bbl	$	28.27			(11	)%	$	31.89
NGL derivative settlements per Bbl		1.36			(81	)%		6.98
NGL price including derivative settlements per Bbl	$	29.63			(24	)%	$	38.87
Natural gas price:
Natural gas price per Mcf	$	3.85			85	%	$	2.08
Natural gas derivative settlements per Mcf		(0.28	)		(111	)%		2.56
Natural gas price including derivative settlements per Mcf	$	3.57			(23	)%	$	4.64
Oil, NGL and natural gas price per BOE:
Oil, NGL and natural gas price per BOE	$	55.13			26	%	$	43.62
Oil, NGL and natural gas derivative settlements per BOE		(0.99	)		(110	)%		9.79
Oil, NGL and natural gas price including derivative settlements per BOE	$	54.14			1	%	$	53.41
Oil, NGL and natural gas derivative unrealized gains per BOE		10.22			(40	)%		16.97
Oil, NGL and natural gas price including derivative settlements and unrealized gains per BOE	$	64.36			(9	)%	$	70.38
Total price per BOE	$	64.36			(9	)%	$	70.38

Our oil, NGL and natural gas revenues, including derivatives settlements and unrealized derivative gains, for the three months ended June 30, 2013 decreased approximately $8.2 million, or 17%, from approximately $47.2 million to approximately $39.1 million, when compared to the same period in 2012. Our oil, NGL and natural gas revenues for the three months ended June 30, 2013 increased by approximately $4.2 million from approximately $29.3 million to approximately $33.5 million. This increase related to higher prices of natural gas of approximately $4.2 million and higher oil production of approximately $2.3 million, which was partially offset by lower prices of oil and NGL of approximately $0.3 million and lower natural gas and NGL production of approximately $2.0 million. Our derivative gain was approximately $5.6 million for the three months ended June 30, 2013, as compared to approximately $18.0 million for the prior period. The decrease in commodity derivative revenues was due to a loss on settled contracts of approximately $0.6 million as compared to prior year gains of approximately $6.6 million, which was due to early settlements in 2012, and decreased gains on unrealized commodity derivatives of approximately $5.2 million, which was due to price increases.

Production costs. Per unit production cost for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012 increased $2.08/Boe, or 12%, and total production costs for the 2013 period, as compared to the 2012 period, increased by approximately $0.1 million, or 1%. Our per unit and total production costs for the three months ended June 30, 2013 and 2012 are as set forth below.

	Unit-of-Production (Per Boe Based on Sales Volumes) Three Months Ended June 30,
	2013		% Change			2012
Production costs:
Gathering & transportation	$	0.66		16	%	$	0.57
Operating & maintenance		13.37		4	%		12.89
Workover expenses		1.13		565	%		0.17
Lease operating expenses		15.16		11	%		13.63
Taxes other than income		4.72		13	%		4.17
Production costs	$	19.88		12	%	$	17.80

	Production Costs
	Three Months Ended June 30,
	2013		% Change			2012
	(In thousands)
Production costs:
Gathering & transportation	$	403		5	%	$	385
Operating & maintenance		8,114		(6	)%		8,645
Workover expenses		686		491	%		116
Lease operating expenses		9,203		1	%		9,146
Taxes other than income		2,867		2	%		2,799
Production costs	$	12,070		1	%	$	11,945

Gathering and transportation expenses for the three months ended June 30, 2013 and June 30, 2012 were approximately $0.4 million. Per unit gathering and transportation expensed increased primarily due to decreased production.

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Operating and maintenance expenses for the three months ended June 30, 2013 and June 30, 2012 were approximately $8.1 million and $8.6 million, respectively. Per unit operating and maintenance expenses increased primarily due to decreased production.

Workover expenses for the three months ended June 30, 2013 were approximately $0.7 million, compared to approximately $0.1 million in the 2012 period, an increase of approximately $0.6 million, or 491%. This increase in workover expenses was due primarily to an increase in the number and cost of our workovers in 2013 as compared to 2012.

Taxes other than income for the three months ended June 30, 2013 were approximately $2.9 million, compared to approximately $2.8 million in the 2012 period, an increase of approximately $0.1 million, or 2%. This increase in taxes was due primarily to the changes in commodity production in 2013 compared to 2012.

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, development and exploitation 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 June 30, 2013 and 2012 were as follows:

	Three Months Ended June 30,
	2013		% Change			2012
	(In thousands, except per unit measurements which are based on sales volumes)
General and administrative expenses — gross	$	7,036		50	%	$	4,679
Capitalized general and administrative expenses		1,667		48	%		1,124
General and administrative expenses — net	$	5,369		51	%	$	3,555
General and administrative expenses — gross $ per Boe	$	11.59		66	%	$	6.98

Our gross general and administrative expenses for the three months ended June 30, 2013 were approximately $7.0 million compared to approximately $4.7 million in the same period of 2012, an increase of approximately $2.3 million, or 50%, primarily as a result of higher compensation related to bonuses and legal and accounting costs in 2013 related to the engagement of outside consultants to advise our business primarily related to the Exchange Offer. See “-Liquidity and Capital Resources” below. After capitalization, our net general and administrative expenses increased by approximately $1.8 million, or 51%, to approximately $5.4 million. Per unit general and administrative expense increased by 66% due to higher general and administrative expense and lower production volumes.

Depletion of oil, NGL and natural gas properties.

	Three Months Ended June 30,
	2013		% Change			2012
	(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil, NGL and natural gas properties	$	11,300		(12	)%	$	12,796
Depletion of oil, NGL and natural gas properties (per Boe)	$	18.62		2	%	$	19.07

Our depletion expense for the three months ended June 30, 2013 was approximately $11.3 million compared to approximately $12.8 million in the same period of 2012, a decrease of approximately $1.5 million, or 12%. A decrease in our depletion rate due primarily to a lower depreciable base contributed to a decrease in depletion expense of approximately $0.3 million and lower production volumes resulting in lower depletion expense of approximately $1.2 million.

Impairment of oil and natural gas properties. For the three months ended June 30, 2013 and 2012, based on the average oil and natural gas prices in effect on the first day of each month for the twelve months during the periods then ended, we were not required to record an impairment to our oil, NGL and natural gas properties.

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Net interest expense. Our net interest expense for the three months ended June 30, 2013 was approximately $9.7 million or a 8% increase from the approximately $9.0 million of net interest expense accrued for the three months ended June 30, 2012. The increase in net interest expense during 2013 from 2012 related primarily to higher interest on our 2011 Credit Facility due to a higher outstanding balance during the three months ended June 30, 2013.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Sales Volumes

	Six Months Ended June 30,
	2013		% Change			2012
Oil (MBbls)		455		6	%		430
NCL (MBbls)		128		(1	)%		129
Natural gas (MMcf)		3,864		(22	)%		4,925
Total (MBoe)		1,227		(11	)%		1,380
Average daily production volumes (MBoe/d)(a)		6.8		(11	)%		7.6

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

For the six months ended June 30, 2013, our net equivalent production volumes decreased by 11% to 1,227 MBoe (6.8 MBoe/d) from 1,380 MBoe (7.6 MBoe/d) in 2012. Our production volumes in 2013, as compared to 2012, decreased primarily as a result of the natural decline in production, the delay of scheduled gas drilling projects due to marginal natural gas prices and a lengthy shut-in at our West Lake Verret field during March and April. Natural gas represented approximately 52% and 59% of our total production in the six months ended June 30, 2013 and 2012, 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 six months ended June 30, 2013 and 2012. 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.

	Six Months Ended June 30,
	2013			% Change			2012
	(In thousands)
Oil revenues:
Oil revenues	$	48,300			5	%	$	46,138
Oil derivative settlements		(383	)		(75	)%		(1,530	)
Oil revenues including oil derivative settlements		47,917			7	%		44,608
NGL revenues:
NGL revenues		3,738			(28	)%		5,217
NGL derivative settlements		93			(78	)%		419
NGL revenues including derivative settlements		3,831			(32	)%		5,636
Natural gas revenues:
Natural gas revenues		13,501			20	%		11,251
Natural gas derivative settlements		(134	)		(101	)%		11,795
Natural gas revenues including derivative settlements		13,367			(42	)%		23,046
Oil, NGL and natural gas revenues:
Oil, NGL and natural gas revenues		65,539			5	%		62,606
Oil, NGL and natural gas derivative settlements		(424	)		(104	)%		10,684
Oil, NGL and natural gas revenues including derivative settlements		65,115			(11	)%		73,290
Oil, NGL and natural gas derivative unrealized gains		2,227			(72	)%		7,864
Oil. NGL and natural gas revenues including derivative settlements and unrealized gains		67,342			(17	)%		81,154
Total revenues	$	67,342			(17	)%	$	81,154

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	Change from Six Months Ended June 30, 2012 to Six Months Ended June 30, 2013
	(In thousands)
Change in revenues from the sale of oil:
Price variance impact	$	(492	)
Sales volume variance impact		2,654
Total change		2,162
Change in revenues from the sale of NGL:
Price variance impact	$	(1,450	)
Sales volume variance impact		(29	)
Total change		(1,479	)
Change in revenues from the sale of natural gas:
Price variance impact	$	5,953
Sales volume variance impact		(3,703	)
Total change		2,250
Change in revenues from the sale of oil, NGL and natural gas:
Price variance impact	$	4,011
Sales volume variance impact		(1,078	)
Cash settlement of commodity derivative contracts		(11,108	)
Unrealized gains (losses) due to commodity derivative contracts		(5,637	)
Total change	$	(13,812	)

	Six months ended June 30,
	2013			% Change			2012
Oil price:
Oil price per Bbl	$	106.15			(1	)%	$	107.30
Oil derivative settlements per Bbl		(0.84	)		(76	)%		(3.56	)
Oil revenues including oil derivative settlements per Bbl	$	105.31			2	%	$	103.74
NGL price:
NGL price per Bbl	$	29.20			(28	)%	$	40.44
NGL derivative settlements per Bbl		0.73			(78	)%		3.25
NGL price including derivative settlements per Bbl	$	29.93			(31	)%	$	43.69
Natural gas price:
Natural gas price per Mcf	$	3.49			53	%	$	2.28
Natural gas derivative settlements per Mcf		(0.03	)		(101	)%		2.40
Natural gas price including derivative settlements per Mcf	$	3.46			(26	)%	$	4.68
Oil, NGL and natural gas price per BOE:
Oil, NGL and natural gas price per BOE	$	53.41			18	%	$	45.37
Oil, NGL and natural gas derivative settlements per BOE		(0.35	)		(105	)%		7.74
Oil, Oil, NGL and natural gas price including derivative settlements per BOE	$	53.06			0	%	$	53.11
Oil, NGL and natural gas derivative unrealized gains per BOE		1.81			(68	)%		5.70
Oil, NGL and natural gas price including derivative settlements and unrealized gains per BOE	$	54.87			(7	)%	$	58.81
Total price per BOE	$	54.87			(7	)%	$	58.81

Our oil, NGL and natural gas revenues, including derivatives settlements and unrealized derivative gains, for the six months ended June 30, 2013 decreased approximately $13.8 million, or 17%, from approximately $81.2 million to approximately $67.3 million, when compared to the same period in 2012. Our oil, NGL and natural gas revenues for the six months ended June 30, 2013 increased by approximately $2.9 million from approximately $62.6 million to approximately $65.5 million. This increase related to higher prices of natural gas of approximately $6.0 million and higher oil production of approximately $2.7 million, which was partially offset by lower oil and NGL prices of approximately $1.9 million and lower natural gas and NGL production of approximately $3.7 million. Our derivative gain was approximately $1.8 million for the six months ended June 30, 2013, as compared to approximately $18.5 million for the prior period. The decrease in commodity derivative revenues was due to a loss on settled contracts of approximately $0.4 million as compared to prior year gains of approximately $10.7 million, which was due to early settlements, and decreased gains on unrealized commodity derivatives of approximately $5.6 million, which was due to price increases.

26

Production costs. Per unit production cost for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012 increased $1.59/Boe, or 9%, and total production costs for the 2013 period, as compared to the 2012 period, decreased by approximately $0.8 million, or 3%. Our per unit and total production costs for the six months ended June 30, 2013 and 2012 are as set forth below.

	Unit-of-Production (Per Boe Based on Sales Volumes) Six Months Ended June 30,
	2013		% Change			2012
Production costs:
Gathering & transportation	$	0.65		12	%	$	0.58
Operating & maintenance		13.37		9	%		12.27
Workover expenses		1.22		26	%		0.97
Lease operating expenses		15.24		10	%		13.82
Taxes other than income		4.41		4	%		4.24
Production costs	$	19.65		9	%	$	18.06

	Production Costs
	Six months ended June 30,
	2013		% Change			2012
	(In thousands)
Production costs:
Gathering & transportation	$	803		0	%	$	803
Operating & maintenance		16,405		(3	)%		16,937
Workover expenses		1,494		12	%		1,333
Lease operating expenses		18,702		(2	)%		19,073
Taxes other than income		5,414		(7	)%		5,852
Production costs	$	24,116		(3	)%	$	24,925

Gathering and transportation expenses for the six months ended June 30, 2013 and June 30, 2012 were approximately $0.8 million. Per unit gathering and transportation expensed increased primarily due to decreased production.

Operating and maintenance expenses for the six months ended June 30, 2013 and June 30, 2012 were approximately $16.4 million and $16.9 million, respectively. Per unit operating and maintenance expenses increased primarily due to decreased production.

Workover expenses for the six months ended June 30, 2013 were approximately $1.5 million, compared to approximately $1.3 million in the 2012 period, an increase of approximately $0.2 million, or 12%. This increase in workover expenses was due primarily to an increase in the number and cost of our workovers in 2013 as compared to 2012.

Taxes other than income for the six months ended June 30, 2013 were approximately $5.4 million, compared to approximately $5.9 million in the 2012 period, a decrease of approximately $0.5 million, or 7%. This decrease in taxes was due primarily to the changes in commodity production in 2013 compared to 2012.

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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, development and exploitation 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 six months ended June 30, 2013 and 2012 were as follows:

	Six Months Ended June 30,
	2013		% Change			2012
	(In thousands, except per unit measurements which are based on sales volumes)
General and administrative expenses — gross	$	11,873		61	%	$	7,372
Capitalized general and administrative expenses		3,034		98	%		1,535
General and administrative expenses — net	$	8,839		51	%	$	5,837
General and administrative expenses — gross $ per Boe	$	9.68		81	%	$	5.34

Our gross general and administrative expenses for the six months ended June 30, 2013 were approximately $11.9 million compared to approximately $7.4 million in the same period of 2012, an increase of approximately $4.5 million, or 61%, primarily as a result of higher compensation related to bonuses and legal and accounting costs in 2013 related to the engagement of outside consultants to advise our business primarily related to the Exchange Offer. See “-Liquidity and Capital Resources” below. After capitalization, our net general and administrative expenses increased by approximately $3.0 million, or 51%, to approximately $8.8 million. Per unit general and administrative expense increased by 81% due to higher general and administrative expense and lower production volumes.

Depletion of oil, NGL and natural gas properties.

	Six months ended June 30,
	2013		% Change			2012
	(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil, NGL and natural gas properties	$	22,714		(11	)%	$	25,646
Depletion of oil, NGL and natural gas properties (per Boe)	$	18.51		0	%	$	18.59

Our depletion expense for the six months ended June 30, 2013 was approximately $22.7 million compared to approximately $25.6 million in the same period of 2012, a decrease of approximately $2.9 million, or 11%. A decrease in our depletion rate, due primarily to a lower depreciable base, contributed to a decrease in depletion expense of approximately $0.1 million and lower production volumes resulting in lower depletion expense of approximately $2.8 million.

Impairment of oil and natural gas properties. For the six months ended June 30, 2013, based on the average oil and natural gas prices in effect on the first day of each month during the first six months of 2013 and last six months of 2012 ($3.44 per MMBtu for Henry Hub gas and $91.60 per Bbl for West Texas Intermediate oil, adjusted for differentials), we were not required to record an impairment to our oil, NGL and natural gas properties. For the six months ended June 30, 2012, we reported an impairment of approximately $11.6 million to our oil, NGL and natural gas properties. The impairment occurred and was recorded 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 months 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 cost 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.

Net interest expense. Our net interest expense for the six months ended June 30, 2013 was approximately $18.4 million or a 3% increase from the approximately $17.9 million of net interest expense accrued for the six months ended June 30, 2012. The increase in net interest expense during 2013 from 2012 related primarily to higher interest on our 2011 Credit Facility due to a higher outstanding balance during the six months ended June 30, 2013.

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.

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Sources and Uses of Cash

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

	Six months ended June 30,
	2013			% Change			2012
	(In thousands)
Net loss	$	(8,710	)		28	%	$	(6,797	)
Non-cash items		24,785			(27	)%		33,876
Changes in working capital and other items		(4,510	)		182	%		(1,599	)
Net cash provided by operating activities		11,565			(55	)%		25,480
Net cash used in investing activities		(18,549	)		32	%		(14,081	)
Net cash provided by (used in) financing activities		18,377			195	%		(19,358	)
Net increase (decrease) in cash and cash equivalents	$	11,393			243	%	$	(7,959	)

Analysis of net cash provided by operating activities

Net cash provided by operating activities for the six months ended June 30, 2013 was approximately $11.6 million, as compared to approximately $25.5 million for the same period in 2012, an approximately $13.9 million, or 55%, decrease. The decrease in net cash provided by operating activities from 2012 to 2013 was due to lower revenues, which decreased operating cash flow activities by approximately $8.2 million and higher expenses, which decreased operating cash flow activities by approximately $2.8 million. This decrease was also related to working capital changes of approximately $2.9 million from 2012 to 2013 related to the payment of payables.

Analysis of net cash used in investing activities

Net cash used in investing activities for the six months ended June 30, 2013 was approximately $18.5 million, compared to approximately $14.1 million in the same period in 2012, an approximately $4.5 million, or 32%, increase. The increase relates primarily to increased drilling and workovers, offset by proceeds from the sale of oil and natural gas properties.

Analysis of net cash used in financing activities

Net cash provided by financing activities for the six months ended June 30, 2013 was approximately $18.4 million as compared to approximately $19.4 million of cash used by financing activities for the same period in 2012, an increase of approximately $37.7 million, or 195%. This increase reflected the net borrowings of approximately $18.4 million in 2013 as compared to net payments of approximately $19.3 million in 2012.

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 directly related to capital projects, which we are permitted to capitalize 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.

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During the six months ended June 30, 2013, we spent approximately $18.2 million on capital expenditures excluding capitalized general and administrative expenses, before divestitures, to support our business plan. Of this amount, we spent approximately $11.0 million to successfully drill thirteen gross wells and complete eleven of these wells. We also completed two carryover wells that were drilled in 2012. We drilled nine gross (nine net) and completed seven gross (seven net) operated well in the Texas Gulf Coast area, drilled and completed two gross (0.19 net) non-operated wells in our South Texas area and drilled and completed two gross (0.36 net) non-operated wells in our Midcontinent area. We spent approximately $4.6 million on workovers and recompletions primarily in our Texas Gulf Coast and South Texas areas. We spent approximately $1.1 million of capital expenditures to continue leasing. The remaining approximately $1.5 million of capital expenditures were primarily related to facilities, seismic and plugging and abandonment costs.

We contemplate spending up to an additional approximately $15.2 million for the remainder of 2013 to support our business plan. We are planning to complete two carryover operated wells and drill or participate in up to six additional wells during the remainder of 2013, including two non-operated exploratory wells in our South Texas area; one non-operated development well in our Mid-Continent area: one non-operated development well in our Southeast area; two operated development wells in our Southeast area and one operated exploratory well in our Texas Gulf Coast area; as well as planning on workover and recompletion projects of existing wells.  In light of price volatility, 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 June 30, 2013 and December 31, 2012, we had approximately $13.6 million and $2.2 million of cash and cash equivalents, respectively.

First Lien Credit. As part of the 2011 Refinancing, we entered into the $300 million Amended and Restated First Lien Credit Facility (the “2011 Credit Facility”) that matures in November 2014. A borrowing base redetermination was conducted in May of 2013 and no change was made to the existing $135 million borrowing base. As of June 30, 2013 the borrowing base remained at $135 million. Amounts outstanding, under the 2011 Credit Facility bear interest at specified margins over the LIBOR of between 2.75% and 3.75% for Eurodollar loans or at specified margins over ABR of between 1.75% and 2.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the 2011 Credit Facility are secured by all of our oil, NGL and natural gas properties. The lenders’ commitments to extend credit will expire, and amounts drawn under the 2011 Credit Facility will mature, in November 2014.

The 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 1.22 as of June 30, 2013), minimum interest coverage ratio, as defined, of not less than 2.50 to 1.0 (which was 2.36 as of June 30, 2013), maximum leverage ratio, as defined, of debt balances as compared to EBITDA of not greater than 4.00 to 1.0 (which was 4.93 as of June 30, 2013) 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 1.75 as of June 30, 2013). We are currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio and minimum interest ratio. Alternatives that were considered include using cash flow from operations or issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.  As another alternative, we have launched a private exchange offering to exchange a portion of the Notes (as defined in Note 8) for equity, cash and/or new notes, which has been extended to August 30, 2013.  If the conditions to the Exchange Offer are not achieved, we will be unable to consummate the restructuring.  As a result, the lenders under the 2011 Credit Facility may accelerate their debt, which would also cause a default and acceleration of the debt under the Notes, all of which will have a material adverse effect on our liquidity, business and financial condition and may result in our bankruptcy or the bankruptcy of our subsidiaries. Any actual or potential bankruptcy or liquidity crisis may materially harm our relationships with our customers, affiliates and suppliers and otherwise result in significant permanent harm to our ability to operate our business. If the Exchange Offer is not consummated and, as a result, the possible early maturity of the 2011 Credit Facility is not resolved, our customers, affiliates and suppliers may determine that we are likely to face a potential bankruptcy or liquidity crisis and the harm to these relationships, our market share and other aspects of our business may occur immediately.  

We are in breach of our financial covenants as of June 30, 2013.  The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of this covenant breach, we have classified approximately $133.4 million of borrowings under the Credit Facility and approximately $245.9 million of the Notes as current liabilities.  At June 30, 2013, this results in current liabilities exceeding current assets by approximately $375.9 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent us from borrowing additional funds under the 2011 Credit Facility.  See “Outlook” for further discussion.

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Effective June 14, 2013, the Company and the lenders under the 2011 Credit Facility entered into a Forbearance and Consent Agreement. Under the terms of the Forbearance and Consent Agreement, the lenders agreed to forbear, until July 15, 2013 from exercising their rights and remedies, under the 2011 Credit Facility. This forbearance expired on July 15, 2013 and the lenders have taken no further action.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about our ability to continue as a going concern.  Our condensed consolidated financial statements for the quarter ended June 30, 2013 have been prepared assuming we will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

Senior Secured Second Lien Notes. As part of the 2011 Refinancing, we issued Senior Secured Second Lien Notes due May 11, 2016 (the “Notes”) with a face value of $250 million, at a discount of $7.0 million. The Notes carry a face interest rate of 10.500% and interest is payable semi-annually each May 15 and November 15. The Notes are secured by a second priority lien on all of the collateral securing the 2011 Credit Facility, and effectively rank junior to any existing and future first lien secured indebtedness, which includes The 2011 Credit Facility. The balance is presented net of unamortized discount of $245.9 million at June 30, 2013.

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

Outlook

Since the beginning of the year, natural gas prices have been increasing with the first six months showing a low of $3.113 and a high of $4.408. In this environment, we have started gas recompletions but have still excluded operated natural gas drilling opportunities in our 2013 capital budget and continue to believe this is the prudent course of action. While natural gas prices have recovered somewhat from the lows experienced in the quarter ended December 31, 2012, we continue to focus all of our exploration and development drilling efforts on developing additional oil weighted opportunities in our existing portfolio. We are also continuing to perform workovers and recompletions of existing wells. Since approximately 52% of our current daily production is natural gas, and is subject to typical Gulf Coast annual declines of 20%, we believe there is a likelihood of reduced annual production from our existing portfolio, as compared to our prior year performance. We will continue to monitor the gas price improvement to determine if drilling gas prospects are justified economically with assumed hedging to protect the return on investment.

Our intent for the remainder of 2013 is to manage our operational and capital spending within the available free cash flow generated by our assets. 

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

During the six months ended June 30, 2013, we spent approximately $18.2 million on capital expenditures excluding capitalized general and administrative, before divestitures, to support our business plan. Of this amount, we spent approximately $11.0 million to successfully drill thirteen gross wells and complete eleven of these wells. We also completed two carryover wells that were drilled in 2012. We drilled nine gross (nine net) and completed seven gross (seven net) operated well in the Texas Gulf Coast area, drilled and completed two gross (0.19 net) non-operated wells in our South Texas area and drilled and completed two gross (0.36 net) non-operated wells in our Midcontinent area. We spent approximately $4.6 million on workovers and recompletions primarily in our Texas Gulf Coast and South Texas areas. We spent approximately $1.1 million of capital expenditures to continue leasing. The remaining approximately $1.5 million of capital expenditures were primarily related to facilities, seismic and plugging and abandonment costs.

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We contemplate spending up to an additional approximately $15.2 million for the remainder of 2013 to support our business plan. We are planning to complete two carryover operated wells and drill or participate in up to six additional wells during the remainder of 2013, including two non-operated exploratory wells in our South Texas area; two operated development wells in our Southeast area and one operated exploratory well in our Texas Gulf Coast area; as well as planning on workover and recompletion projects of existing wells.  In light of price volatility, we are constantly evaluating the deployment of our capital. See “-Liquidity and Capital Resources” for more on our capital expenditures.

We are currently exploring a range of alternatives to reduce indebtedness to the extent necessary to be in compliance with the maximum leverage ratio and minimum interest ratio. Alternatives that were considered include using cash flow from operations or issuances of equity and debt securities, reimbursements of prior leasing and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties.  As another alternative, we have launched the Exchange Offer to exchange a portion of the Notes (as defined above under “-Liquidity and Capital Resources”) for equity, cash and/or new notes, which has been extended to August 30, 2013.  If the conditions to the Exchange Offer are not achieved, we will be unable to consummate the restructuring.  As a result, the lenders under the 2011 Credit Facility may accelerate their debt, which would also cause a default and acceleration of the debt under the Notes, all of which will have a material adverse effect on our liquidity, business and financial condition and may result in our bankruptcy or the bankruptcy of our subsidiaries. Any actual or potential bankruptcy or liquidity crisis may materially harm our relationships with our customers, affiliates and suppliers and otherwise result in significant permanent harm to our ability to operate our business. If the Exchange Offer is not consummated and, as a result, the possible early maturity of the 2011 Credit Facility is not resolved, our customers, affiliates and suppliers may determine that we are likely to face a potential bankruptcy or liquidity crisis and the harm to these relationships, our market share and other aspects of our business may occur immediately.  

Because we are not in compliance with our financial covenants at June 30, 2013, we are in breach of our financial covenants. The indenture governing the Notes provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  As a result of this covenant breach, we have classified approximately $133.4 million of borrowings under the Credit Facility and approximately $245.9 million of the Notes as current liabilities.  At June 30, 2013, this results in current liabilities exceeding current assets by approximately $375.9 million.  In addition, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions, and prevent us from borrowing additional funds under the 2011 Credit Facility.

Effective June 14, 2013, the Company and the lenders under the 2011 Credit Facility entered into a Forbearance and Consent Agreement. Under the terms of the Forbearance and Consent Agreement, the lenders agreed to forbear, until July 15, 2013 from exercising their rights and remedies, under the 2011 Credit Facility. This forbearance expired on July 15, 2013 and the lenders have taken no further action.

All of the conditions discussed above create a deficiency in short term and long term liquidity and raise substantial doubt about our ability to continue as a going concern.  Our condensed consolidated financial statements for the quarter ended June 30, 2013 have been prepared assuming we will continue as a going concern and no adjustments to the financial statements have been made to account for this uncertainty.

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

For the six months ended June 30, 2013, we realized approximately $0.4 million in losses under our commodity derivative agreements. Based on the NYMEX strip pricing for oil, NGL and natural gas as of June 30, 2013, we expect to realize approximately $0.1 million of commodity derivative gains during the last six months of 2013. 

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	2013 Budget(a)		Amount Spent Through June 30, 2013		Amount Remaining(b)
	(In millions)
Drilling	$	21.7	$	11.0	$	10.7
Workovers and recompletions		6.7		4.6		2.1
Geological, geophysical, leasing and seismic		1.5		1.3		0.2
Plugging and abandonment		1.5		0.5		1.0
Facilities, vehicles and other		2.0		0.8		1.2
Total operations capital budget	$	33.4	$	18.2	$	15.2

(a)	2013 capital budget presented to our Board of Directors.
(b)	Calculated based upon the 2013 capital budget less amounts spent through June 30, 2013.

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

• available capital;

• changes in commodity prices;

• possible early maturity of the 2011 Credit Facility;

• 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

A summary of critical accounting policies is disclosed in Note 4 to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012. 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 critical accounting policies since such date.

Recently Issued Accounting Pronouncements

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 adopted this standard effective January 1, 2013, See Note 7 to our condensed consolidated financial statements herein.

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The FASB recently issued ASU 2013-01 which clarifies which instruments and transactions are subject to the offsetting disclosure requirements2 established by ASU 2011-11.3 The new ASU addresses preparer concerns that the scope of the disclosure requirements under ASU 2011-11 was overly broad and imposed unintended costs that were not commensurate with estimated benefits to financial statement users. In choosing to narrow the scope of the offsetting disclosures, the FASB determined that it could make them more operable and cost effective for preparers while still giving financial statement users sufficient information to analyze the most significant presentation differences between financial statements prepared in accordance with U.S. GAAP and those prepared under IFRS.

Like ASU 2011-11, ASU 2013-01 is effective for all entities (public and nonpublic) for fiscal years beginning on or after January 1, 2013, and interim periods therein. Therefore, calendar year-end public filers needed to include the disclosures in their first-quarter Form 10-Q filings for 2013. Retrospective application is required for any period presented that begins before the entity’s initial application of the new requirements.  See Note 7 to our condensed consolidated financial statements herein.

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 June 30, 2013, a 1% increase in interest rates would increase interest expense by approximately $1.3 million per year, based on our approximately $133.4 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 2013 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 six months of 2013 was $3.49 per Mcf, which was 53% higher than the price of $2.28 per Mcf that we received in the first six months of 2012. Natural gas prices in the first six months of 2013 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 2013 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.                    

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	As of June 30, 2013
Oil collars and three way costless collars
Volumes (Bbls)		255,167
Average floor price (per Bbl)	$	87.79
Average ceiling price (per Bbl)	$	99.25
Loss upon settlement	$	(6,230	)
Oil swaps
Volumes (Bbls)		44,300
Average swap price (per Bbl)	$	85.23
Loss upon settlement	$	(401,169	)
Total oil loss upon settlement	$	(407,399	)
Natural gas collars and three way costless collars
Volumes (Mcf)		540,000
Average floor price (per Mcf)	$	3.50
Average ceiling price (per Mcf)	$	5.75
Gain upon settlement	$	36,450
Natural gas swaps
Volumes (Mcf)		2,127,180
Average swap price (per Mcf)	$	3.69
Gain upon settlement	$	(170,041	)
Total natural gas gain upon settlement	$	(133,591	)
NGL swaps
Volumes (Mcf)		85,868
Average swap price (per Mcf)	$	38.03
Gain upon settlement	$	117,335
Total NGL gain upon settlement	$	117,335
Total oil, NGL and natural gas gain upon settlement	$	(423,655	)

The following commodity derivative contracts were in place as of June 30, 2013:

Natural Gas	Type	Mmbtu/Mo or Avg Mmbtu/Mo		Price/Mmbtu
Apr-Jul 2013 – Dec 2013	Collar		90,000	$	3.50	-	5.75
Apr-Jul 2013 – Dec 2013	Swap		100,000				3.65
Apr-Jul 2013 – Dec 2013	Swap		90,000				4.22
Apr-Jul 2013 – Dec 2013	Swap		100,000				3.41
Apr-Jul 2013 – Dec 2013	Swap		55,265				3.45
Jan-Jan 2014 – Dec 2014	Swap		75,000				3.82
Jan-Jan 2014 – Dec 2014	Swap		100,000				3.93
Jan-Jan 2014 – Dec 2014	Swap		40,000				4.52
Jan-Jan 2014 – Dec 2014	Swap		100,000				3.92
Jan-Jan 2014 – Dec 2014	Swap		43,223				3.96
Jan-Jan 2015 – Dec 2015	Swap		88,000				4.14

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Oil	Type	Bbl/Mo or Avg Bbl /Mo		Price/Bbl
Apr-Jul 2013 – Dec 2013	Collar		8,000	$	92.00	-	102.95
Apr-Jul 2013 – Dec 2013	Collar		11,000		80.00	-	98.00
Apr-Jul 2013 – Dec 2013	Collar		9,146		90.00	-	97.65
Apr-Jul 2013 – Dec 2014	Collar		9,715		90.0	-	95.25
Apr-Jul 2013 – Dec 2013	Collar		5,874		90.00	-	103.75
Apr-Jul 2013 – Dec 2013	Swap		3,734				83.00
Apr-Jul 2013 – Dec 2014	Swap		1,000				91.00
Apr-Jul 2013 – Dec 2014	Swap		1,000				91.50
Jan-Jan 2014 – Dec 2014	Collar		19,000		80.00	-	96.75
Jan-Jan 2014 – Dec 2014	Collar		8,525		90.00	-	98.50

NGL	Type	Bbl/Mo or Avg Bbl/Mo		Price/Bbl
Apr-Jul 2013 – Dec 2013	Swap		8,500	$	38.90
Apr-Jul 2013 – Dec 2013	Swap		6,873		36.75
Jan-Jan 2014 – Dec 2014	Swap		7,100		38.24
Jan-Jan 2014 – Dec 2014	Swap		6,164		35.90

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 six months ended June 30, 2013, ten customers collectively accounted for 78% of our oil, NGL and natural gas revenues and during the six months ended June 30, 2012, ten customers collectively accounted for 77% 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 17% and Enterprise Crude Oil, LLC accounted for 28% of total sales during the six months ended June 30, 2013. During the six months ended June 30, 2012, Shell Trading (US) Company accounted for 21% and Enterprise Crude Oil, LLC accounted for 18% 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 Operating 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 Exchange Act of 1934, as amended and determined that our disclosure controls and procedures were not effective as of June 30, 2013. 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 partially mitigate these issues, our management has retained the services of additional third party accounting personnel as well as modified existing internal controls in a manner designed to ensure future compliance.

Changes in Internal Control Over Financial Reporting

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

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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.

Failure to consummate the Exchange Offer and the Restructuring would result in amounts outstanding under the 2011 Credit Facility being accelerated, which may result in a liquidity crisis or our bankruptcy.

We currently have indebtedness outstanding under the 2011 Credit Facility, which contains financial and other covenants, including a covenant that we maintain a maximum leverage ratio, as defined in the 2011 Credit Facility, of debt balances as compared to EBITDA of not greater than 4.0 to 1.0 and a minimum interest coverage ratio, as defined, of EBITDA to interest expense, of not less than 2.5 to 1.0.   As of June 30, 2013, our leverage ratio was 4.93 and our interest coverage ratio was 2.36.  Because we are not in compliance with our financial covenants, the lenders under the 2011 Credit Facility have the option to accelerate the debt and initiate collateral enforcement actions. The Notes Indenture provides that if a default occurs under the 2011 Credit Facility that results in the acceleration of such debt, the Notes would also be in default and subject to acceleration.  We explored a range of alternatives to resolve these issues and determined that the Exchange Offer was the best course of action. 

If a minimum principal amount of at least $237.5 million of the outstanding principal amount of the Notes are not tendered (excluding any such Notes validly withdrawn) in the Exchange Offer, the conditions to the Exchange Offer will not have been achieved and we will be unable to consummate the Restructuring. The Exchange Offer was scheduled to expire on June 17, 2013 but was extended through August 30, 2013. In addition, our forebearance under the 2011 Credit Facility expired on July 15, 2013. As a result, the lenders under the 2011 Credit Facility may accelerate their debt, which would also cause a default and acceleration of the debt under the Notes, all of which will have a material adverse effect on our liquidity, business and financial condition and may result in our bankruptcy or the bankruptcy of our subsidiaries. Any actual or potential bankruptcy or liquidity crisis may materially harm our relationships with our customers, affiliates and suppliers and otherwise result in significant permanent harm to our ability to operate our business. If the Exchange Offer is not consummated and, as a result, the possible early maturity of the 2011 Credit Facility is not resolved, our customers, affiliates and suppliers may determine that we are likely to face a potential bankruptcy or liquidity crisis and the harm to these relationships, our market share and other aspects of our business may occur immediately.

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

As of June 30, 2013, we had approximately $379.3 million in outstanding indebtedness. See Note 2 for further discussion of liquidity and our ability to continue as a going concern. 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.

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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 six months ended June 30, 2013 and the years ended December 31, 2012, 2011 and 2010 of $8.7 million and $33.4 million, $23.6 million and $70.6 million, respectively. We cannot assure you that our current level of operating results will continue or improve. Our activities could require additional equity or debt financing. Our future operating results may fluctuate significantly depending upon a number of factors, including industry conditions, prices of oil and natural gas, rates of production, timing of capital expenditures and drilling success. Negative changes in these variables could have a material adverse effect on our business, financial condition and results of operations.

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.

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Item 6.         Exhibits

10.1 Forbearance and Consent Agreement dated as of June 14, 2013 among Milagro Exploration, LLC and Milagro Producing, LLC, as borrowers, Milagro Oil & Gas, Inc., as guarantor, Wells Fargo Bank, N.A., as administrative agent, issuer and swing line lender, and the lenders from time to time parties thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 17, 2013.

10.2 Amendment to Consulting Agreement among Milagro Oil & Gas, Inc., Milagro Holdings, LLC and Sequitur energy management II, LLC dated July 10, 2013. **

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.DEF	XBRL Taxonomy Extension Definition 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.

** Filed herewith.

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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;

• our ability to complete our pending Exchange Offer;

• the possible early maturity of our 2011 Credit Facility;

• 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, 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.

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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: August 13, 2013	By:	/s/ Gary J. Mabie
			Gary J. Mabie
			President and Chief Operating Officer
Date: August 13, 2013
	By:	/s/ Robert D. LaRocque
			Robert D. LaRocque
			Chief Financial Officer and Treasurer