Black Elk Energy Offshore Operations 8-K Black Elk Energy Offshore Operations, LLC Reports 2012

Exhibit 99.1

Black Elk Energy Offshore Operations, LLC Reports 2012

Financial and Operational Results

Houston, April 25, 2013

Black Elk Energy Offshore Operations, LLC today announces financial and operational results for the year ended 2012. Some of the highlights include:

• For the year ended December 31, 2012, oil, natural gas and plant products production averaged 14,429 barrels of oil equivalent per day (“Boepd”), or 86,574 million cubic feet equivalent per day (“Mcfepd”), compared to 14,559 Boepd, or 87,354 Mcfepd, for the year ended December 31, 2011. The decrease in production is attributable to the relinquishment of uneconomic leases and several fields being shut-in. Production volumes were 44% oil and natural gas liquids (“NGLs”) and 56% natural gas in 2012.

• For the year ended December 31, 2012, our average realized sales price for oil was $106.60 per barrel before the effects of hedging and $110.18 per barrel after hedging. Average realized sales price for natural gas was $2.82 per million cubic feet (“Mcf”) before the effects of hedging and $3.73 per Mcf after hedging.

• Total revenues for the twelve months ending 2012 decreased from the same period in 2011 by $35.5 million, or 10%, due to lower unrealized gains on derivative financial instruments, decreased oil and gas production and lower oil, gas and plant product prices.

• For the year ended 2012, we realized a net loss of $64.0 million compared to net income of $15.0 million for the same period of 2011.

• Adjusted EBITDA for the year 2012 was $79.0 million compared to $110.7 million in 2011.

Financial Results

Oil and natural gas production.During the year ended December 31, 2012, total oil, natural gas and plant product production was 5,281 MBoe, a 33 MBoe decrease, or 1%, compared to the year ended December 31, 2011. The decrease in production during 2012 was due to lower production in the third quarter of 2012 (196 MBoe), primarily as a result of downtime for Hurricane Isaac, and lower production in the fourth quarter of 2012 (414 MBoe) as a result of downtime in fields requiring hot work, which was delayed due to the Bureau of Safety and Environmental Enforcement (“BSEE”) requirement for approval after the West Delta 32 Incident, partially offset by a full year of production from the properties acquired from Merit Energy Corp. (the “Merit Acquisition”) (872 MBoe).

Total revenues.Total revenues for the year ended December 31, 2012 were $304.5 million, a $35.5 million decrease, or 10%, compared to the year ended December 31, 2011. The decrease in revenues during 2012 resulted primarily from lower oil, natural gas and plant product prices. Total revenues were also lower due to a $4.8 million unrealized loss on derivative financial instruments for the year ended December 31, 2012 compared to a $17.6 million unrealized gain for the prior year. The decrease in revenues was partially offset by the $15.3 million increase in realized gain on derivative financial instruments.

We entered into certain oil and natural gas commodity derivative contracts in 2012 and 2011. We realized gains on these derivative contracts in the amounts of $23.4 million and $8.1 million for the years ended December 31, 2012 and 2011, respectively. We recognized an unrealized loss of $4.8 million and a gain of $17.6 million for the years ended December 31, 2012 and 2011, respectively. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $28.4 million for the year ended December 31, 2012 compared to year ended December 31, 2011 as a result of lower oil and natural gas production from uneconomic leases, several fields being shut-in and lower oil, natural gas and plant product prices.

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Excluding hedges, we realized average oil prices of $106.60 per barrel and gas prices of $2.82 per Mcf for the year ended December 31, 2012. For the year ended December 31, 2011, excluding hedges, we realized average oil prices of $108.09 per barrel and gas prices of $4.18 per Mcf. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2011, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.

Operating Expenses

Lease operating costs.Our lease operating costs for the year ended December 31, 2012 increased to $180.7 million, or $34.22 per Boe, compared to $158.5 million, or $29.83 per Boe, for the year ended December 31, 2011. The increase in lease operating costs during 2012 was directly related to the additional properties acquired from Maritech Resources Incorporation and in the Merit Acquisition, including non-recurring safety and regulatory costs on these acquired properties, as well as expenses incurred related to the West Delta 32 Incident. The increase in cost per Boe during 2012 was also primarily attributable to an increase in the number of properties, decrease in production due to Hurricane Isaac and downtime in the fields requiring hot work, which was delayed due to the BSEE requirement for approval after the West Delta 32 Incident.

Workover costs.Our workover costs decreased $5.4 million to $18.0 million for the year ended December 31, 2012 compared to $23.4 million for the year ended December 31, 2011. For the year ended December 31, 2012, West Cameron 20/45, Eugene Island 156/South Marsh 22, South Pass 86/87/89, West Delta 31/32, Vermilion 119/120/124 and Eugene Island 331 were the primary workover expense projects.

Exploration.Exploration expense was $1.7 million and $1.0 million for the years ended December 31, 2012 and 2011, respectively. We elected to participate in the drilling of the South Pelto Block 13 No. STK BP2 with a 10.33% working interest. The well was designed to test the CP 12B sand. The operator encountered mechanical problems and commenced bypass operations which were unsuccessful. The operator opted to abandon the drilling and the well was deemed non-commercial.

Depreciation, depletion, amortization and impairment.DD&A expense was $47.3 million, or $8.96 per Boe, and $47.2 million, or $8.88 per Boe, for the years ended December 31, 2012 and 2011, respectively. In 2012, the DD&A expense was relatively flat compared to 2011 as a result of an increase in the DD&A rate partially offset by lower production due to uneconomic leases and several fields being shut-in. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $31.0 million and $13.0 million in impairments for the years ended December 31, 2012 and 2011, respectively, as the estimated undiscounted cash flows of oil and gas properties were less than its carrying value on certain properties.

General and administrative expenses.G&A expense was $26.5 million, or $5.02 per Boe, and $22.0 million, or $4.15 per Boe, for the years ended December 31, 2012 and 2011, respectively. The increase in G&A expense was primarily due to higher costs for additional staff and bonding insurance attributable to our 2011 acquisitions. Our legal fees were also higher in 2012 as a result of the West Delta 32 Incident, recapitalization efforts and litigation expense.

Gain due to involuntary conversion of asset.On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the BSEE advised us to plug and abandon the well. We filed an insurance claim and costs were reimbursed by our insurance company. We recorded a gain of $3.1 million, after a deductible of $0.5 million.

Accretion expense.We recognized accretion expense of $36.4 million and $27.4 million for the years ended December 31, 2012 and 2011, respectively. The increase in accretion expense in 2012 was attributable to assumed asset retirement obligations related to our acquisitions in 2011.

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Miscellaneous expense.Miscellaneous expense decreased $2.7 million to $3.5 million for the year ended December 31, 2012 compared to $6.3 million for the same period in 2011. The higher expense in 2011 was a result of the consent solicitation fee paid under the First Supplemental Indenture.

About Black Elk Energy Offshore

We are an oil and gas company engaged in the acquisition, exploitation, development and production of oil and natural gas properties. We seek to acquire and exploit properties with proved developed reserves, proved developed non-producing reserves and proved undeveloped reserves. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce given additional attention and capital resources. We are engaged in continual efforts to monitor and reduce operating expenses by finding opportunities to safely increase efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage plugging and abandonment costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.

We seek to acquire assets in our areas of focus from oil and gas companies that have determined that such assets are noncore and desire to remove them from their producing property portfolio or have made strategic decisions to deemphasize their offshore operations. Prior to an acquisition, we perform stringent structural engineering tests to determine whether the reservoirs possess potential upside. Each opportunity is presented, catalogued and graded by our management and risked appropriately for the overall impact to our company.

Conference Call Information. Black Elk will hold a conference call to discuss financial and operational results on Friday, April 26, 2013 at 10:00 a.m. Central Time. To participate, dial (800) 268-5851 at least ten minutes before the call begins.

Safe Harbor Statement

This press release may contain certain “forward-looking statements” relating to the business of Black Elk Energy Offshore Operations, LLC and its subsidiary companies. All statements, other than statements of historical fact included herein are “forward-looking statements.” These forward-looking statements are often identified by the use of forward-looking terminology such as “believes,” “expects” or similar expressions, and involve known and unknown risks and uncertainties. Although Black Elk believes that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. Investors should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Black Elk’s actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in Black Elk’s periodic reports that are filed with the Securities and Exchange Commission and available on its website at www.sec.gov. All forward-looking statements attributable to Black Elk or persons acting on its behalf are expressly qualified in their entirety by these factors. Other than as required under the securities laws, Black Elk does not assume a duty to update these forward-looking statements.

Contact

Bruce Koch

IR@blackelk.com

11451 Katy Freeway, Suite 500

Houston, Texas 77079

(281) 598-8600

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,383		$	17,260
Accounts receivable, net of allowance for doubtful accounts of $509 at December 31, 2012		49,653			52,299
Due from affiliates		347			163
Prepaid expenses and other		28,381			26,637
Derivative assets		2,408			4,216
TOTAL CURRENT ASSETS		82,172			100,575
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $191,326 and $114,056 at December 31, 2012 and 2011, respectively		260,012			238,702
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $1,717 and $870 at December 31, 2012 and 2011, respectively		1,968			2,245
OTHER ASSETS
Debt issue costs, net		6,972			8,726
Asset retirement obligation escrow receivable		20,348			20,348
Escrow for abandonment costs		215,263			172,153
Other assets		3,729			3,257
TOTAL OTHER ASSETS		246,312			204,484
TOTAL ASSETS	$	590,464		$	546,006
LIABILITIES AND MEMBERS’ DEFICIT
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	108,736		$	72,309
Asset retirement obligations		41,572			15,238
Current portion of debt and notes payable		3,552			4,154
TOTAL CURRENT LIABILITIES		153,860			91,701
LONG-TERM LIABILITIES
Gas imbalance payable		2,521			1,362
Dividends payable		12,408			4,200
Derivative liabilities		5,091			2,116
Asset retirement obligations, net of current portion		303,933			273,448
Debt, net of current portion, net of unamortized discount of $882 and $1,113 at December 31, 2012 and 2011, respectively		201,118			172,887
TOTAL LONG-TERM LIABILITIES		525,071			454,013
TOTAL LIABILITIES		678,931			545,714
CLASS D CUMULATIVE CONVERTIBLE PARTICIPATING PREFERRED UNITS		30,000			30,000
COMMITMENTS AND CONTINGENCIES
MEMBERS’ DEFICIT		(118,467	)		(29,708	)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT	$	590,464		$	546,006

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2012			2011			2010
REVENUES:
Oil sales	$	210,720		$	215,204		$	68,654
Natural gas sales		50,470			75,994			34,999
Plant product sales and other revenue		24,707			23,091			8,913
Realized gain on derivative financial instruments		23,364			8,099			9,271
Unrealized (loss) gain on derivative financial instruments		(4,783	)		17,556			(12,700	)
TOTAL REVENUES		304,478			339,944			109,137
OPERATING EXPENSES:
Lease operating		180,691			158,545			54,627
Production taxes		745			859			640
Workover		17,986			23,385			4,288
Exploration		1,682			1,004			14
Depreciation, depletion and amortization		47,314			47,214			29,795
Impairment		31,033			12,967			6,407
General and administrative		26,486			22,029			14,588
Gain due to involuntary conversion of asset		(3,100	)		—			—
Accretion		36,421			27,410			9,175
Loss (gain) on sale of asset		38			(142	)		—
TOTAL OPERATING EXPENSES		339,296			293,271			119,534
(LOSS) INCOME FROM OPERATIONS		(34,818	)		46,673			(10,397	)
OTHER INCOME (EXPENSE):
Interest income		319			373			129
Miscellaneous expense		(3,504	)		(6,253	)		(757	)
Interest expense		(25,965	)		(25,752	)		(12,872	)
TOTAL OTHER EXPENSE		(29,150	)		(31,632	)		(13,500	)
NET (LOSS) INCOME		(63,968	)		15,041			(23,897	)
PREFERRED UNIT DIVIDENDS		8,208			4,200			—
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	(72,176	)	$	10,841		$	(23,897	)

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How We Evaluate Our Operations:

We use a variety of financial and operational measures to assess our overall performance. Among those measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) Adjusted EBITDA (as defined in the following table).

The following table contains certain financial and operational data for each of the years ended December 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011		2010
Average daily sales:
Oil (Boepd)		5,401			5,455		2,348
Natural gas (Mcfpd)		48,865			49,829		21,911
Plant products (Galpd)		37,125			33,580		14,802
Oil equivalents (Boepd)		14,429			14,559		6,353
Average realized prices (1):
Oil ($/Bbl)	$	110.18		$	105.17	$	80.97
Natural gas ($/Mcf)		3.73			4.94		5.44
Plant products ($/Gallon)		1.02			1.29		1.10
Oil equivalents ($/Boe)		56.50			59.30		51.27
Costs and Expenses:
Lease operating expense ($/Boe)		34.22			29.83		23.56
Production tax expense ($/Boe)		0.14			0.16		0.28
General and administrative expense ($/Boe)		5.02			4.15		6.29
Net (loss) income (in thousands)		(63,968	)		15,041		(23,897	)
Adjusted EBITDA (2) (in thousands)		78,995			110,686		47,052

(1) Average realized prices presented give effect to our hedging.

(2) Adjusted EBITDA is defined as net (loss) income before interest expense, unrealized loss/gain on derivative instruments, accretion, depreciation, depletion, amortization and impairment, gain on involuntary conversion of assets, provision for doubtful accounts and loss/gain on the sale of an asset. Adjusted EBITDA is not a measure of net (loss) income or cash flows as determined by GAAP, and should not be considered as an alternative to net (loss) income, operating income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. Our presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or nonrecurring items. A reconciliation table is provided below to illustrate how we derive Adjusted EBITDA.

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	Year Ended December 31,
	2012			2011			2010
Net (loss) income	$	(63,968	)	$	15,041		$	(23,897	)
Adjusted EBITDA	$	78,995		$	110,686		$	47,052
Reconciliation of Net income (loss) to Adjusted EBITDA:
Net (loss) income	$	(63,968	)	$	15,041		$	(23,897	)
Interest expense		25,965			25,752			12,872
Unrealized loss (gain) on derivatives instruments		4,783			(17,556	)		12,700
Accretion		36,421			27,410			9,175
Depreciation, depletion, amortization and impairment		78,347			60,181			36,202
Gain on involuntary conversion of assets		(3,100	)		—			—
Provision for doubtful accounts		509			—			—
Loss (gain) on sale of asset		38			(142	)		—
Adjusted EBITDA	$	78,995		$	110,686		$	47,052

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