Black Elk Energy Offshore Operations 8-K Black Elk Energy Offshore Operations, LLC Reports Third Quarter 2011 Financial Results

Exhibit 99.1

Black Elk Energy Offshore Operations, LLC Reports Third Quarter 2011 Financial Results

and Year-to-Date Operational Results

Houston, November 30, 2011

Black Elk Energy Offshore Operations, LLC today announced financial results for its third quarter 2011 and year-to-date operational results. Some of the highlights include:

• Oil sales increased 260% or 398,000 barrels to 551,000 barrels, natural gas sales volumes increased 228% or 3.6 Bcf to 5.2 Bcf and plant products increased 193% or 1,763,000 gallons, each when comparing the third quarter of 2011 to the third quarter of 2010.

• After taking into effect the realized commodity hedging transactions during the third quarter of 2011, average realized oil prices increased $26.57 per barrel to $107.64 per barrel and plant products increased $0.37 per gallon to $1.40 per gallon compared to the third quarter of 2010. Average realized natural gas prices were $5.03 per Mcf in the third quarter of 2011 compared to $5.34 per Mcf in the third quarter of 2010.

• Adjusted EBITDA increased 418% or $26.1 million to $32.3 million from the third quarter of 2010 to the third quarter of 2011. Sequentially, adjusted EBITDA increased 7% or $2.2 million from the second quarter of 2011.⁽¹⁾

• Net income for the third quarter of 2011 increased 946% or $57.2 million to $51.1 million compared to the same period of 2010.

• Total revenues of $141.3 million for the quarter ended September 30, 2011 increased 580% or $120.6 million from $20.8 million in the corresponding period of 2010. The increase in revenues is a result of increased production related to the properties acquired in the latter part of 2010 and the properties acquired in the first and second quarters of 2011. Additionally, we recognized an unrealized gain on derivative financial instruments of $50.2 million in the third quarter of 2011 and an unrealized loss of $1.6 million in the third quarter of 2010.

• On August 19, 2011, we successfully completed our exchange offer with all of the outstanding 13.75% Senior Secured Notes being tendered.

• During the third quarter of 2011, we conducted operations on approximately 35 operated and five non-operated wells. The range of operations covered compliance issues, attempts at returning shut-in wells to production, optimization of existing rates and recompletions.

Financial Results

Oil and natural gas production.Total oil, natural gas and plant product production of 1,487 MBoe increased 1,046 MBoe, or 237% during the three months ended September 30, 2011 compared to the same period in 2010. The increase in production during 2011 was primarily a result of properties acquired in the Nippon Acquisition in September 2010, the Maritech Acquisition in February 2011, and the Merit Acquisition in May 2011.

Total revenues.Total revenues for the three months ended September 30, 2011 of $141.3 million increased $120.6 million, or 580%, over the comparable period in 2010. The increase in revenues during 2011 was a result of

⁽¹⁾  For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA of net income, please see page 7 of this release.

increased production related to the properties acquired in the Nippon Acquisition, the Maritech Acquisition, and the Merit Acquisition as well as higher oil prices. Total revenues were also higher for the three months ended September 30, 2011 as compared to 2010 due to a $50.2 million unrealized gain on derivative financial instruments.

We entered into certain oil and natural gas commodity derivative contracts in 2011 and 2010. We realized gains on these derivative contracts in the amounts of $6.7 million for the three months ended September 30, 2011. For the three months ended September 30, 2010, we realized gains of $2.3 million. We recognized an unrealized gain of $50.2 million for the three months ended September 30, 2011. For the three months ended September 30, 2010, we recognized an unrealized loss of $1.6 million. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $64.3 million for the three months ended September 30, 2011 compared to the same period in 2010 as a result of increased oil, natural gas and plant products production from the acquisitions and higher oil prices.

Excluding hedges, we realized average oil prices of $102.56 per barrel and $76.36 per barrel and gas prices of $4.28 per Mcf and $4.37 per Mcf for the three months ended September 30, 2011 and 2010, respectively. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2010, 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 three months ended September 30, 2011 increased to $47.1 million, or $31.69 per Boe. For the three months ended September 30, 2010, our lease operating costs were $11.6 million, or $26.36 per Boe. The increase in lease operating costs during 2011 is directly related to the increase in properties from the Nippon Acquisition, the Maritech Acquisition and the Merit Acquisition. The increase in cost per Boe during 2011 is primarily attributable to a mix of increased properties and the related workover activities.

Workover costs.Our workover costs for the three months ended September 30, 2011 increased $5.1 million compared to the same period in 2010. For the three months ended September 30, 2011, High Island 571, High Island 370 and East Cameron 148/160 were the primary workover expense projects.

Depreciation, depletion, amortization (DD&A) and impairment.DD&A expense was $14.4 million, or $9.69 per Boe, for the three months ended September 30, 2011 and $6.6 million, or $15.01 per Boe, for the three months ended September 30, 2010. In 2011, the increase in DD&A was the result of increased production associated with the properties acquired in 2011 and 2010. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $1.1 million in impairments for the three months ended September 30, 2011 as the estimated fair value of oil and gas properties were less than its carrying value. We did not recognize an impairment in 2010 for the three months ended September 30, 2010.

General and administrative (G&A) expenses.G&A expense was $5.0 million, or $3.36 per Boe, for the three months ended September 30, 2011 compared to $2.7 million, or $6.01 per Boe, for the three months ended September 30, 2010. The increase in G&A expense in 2011 resulted principally from costs associated with the increase in staff and related administrative costs attributable to our growth in 2011 and 2010.

Accretion expense.We recognized accretion expense of $9.1 million for the three months ended September 30, 2011, compared to $1.8 million for the three months ended September 30, 2010. The increase in accretion expense in 2011 was attributable to assumed asset retirement obligations in 2011 and 2010.

Interest expense.Interest expense increased $4.6 million for the three months ended September 30, 2011 compared to the same period in 2010. The increase of interest expense in 2011 compared to 2010 was a result of borrowing on

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the Credit Facility to fund the Merit P&A obligation, the issuance of the Notes in November 2010, the proceeds of which were used to fund the Nippon Acquisition and associated escrow deposits for future P&A costs, and amortization of credit debt issuance costs as a result of the repayment of loans with proceeds from the Notes, which was partially offset by lower fixed interest rates.

Capital expenditures. For the nine months ended September 30, 2011, capital expenditures for oil and gas properties were $20.1 million and $23.5 million was spent on acquisitions of properties.

Well Work Updates

• We brought wells back on production at Mustang Island A31 and Galveston 190 during the third quarter of 2011.

• During the three months ended September 30, 2011, we performed workovers in the following areas: High Island 571, High Island 370 and East Cameron 148.

• During the three months ended September 30, 2011, we participated in the drilling of a non-operated well at Galveston 116 (the Hickory well). The well spud in the third quarter.

For additional information regarding our financial results, please refer to our Form 10-Q for the three and nine months ended September 30, 2011, which was filed with the Securities and Exchange Commission on November 10, 2011.

Conference Call Information. Black Elk will hold a conference call to discuss financial and operational results on Thursday, December 1, 2011 at 2:00 p.m. Central Time. To participate, dial (888) 223-4580 and ask for the Black Elk Energy call at least ten minutes before the call begins.

About Black Elk Energy Offshore

We are a privately held 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 economically maximize properties that are currently producing or have the potential to produce given the needed attention and capital resources.

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

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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, but not limited to, those summarized below:

• Low and/or declining prices for oil and natural gas;

• Oil and natural gas price volatility;

• Risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

• Ability to raise additional capital to fund future capital expenditures;

• Cash flow and liquidity;

• Ability to find, acquire, market, develop and produce new oil and natural gas properties;

• Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

• Geological concentration of our reserves;

• Discovery, acquisition, development and replacement of oil and natural gas reserves;

• Operating hazards attendant to the oil and natural gas business;

• Down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

• Potential mechanical failure or underperformance of significant wells or pipeline mishaps;

• Potential increases in plugging and abandonment and other asset retirement costs as a result of new regulations;

• Weather conditions;

• Availability and cost of material and equipment;

• Delays in anticipated start-up dates;

• Actions or inactions of third-party operators of our properties;

• Ability to find and retain skilled personnel;

• Strength and financial resources of competitors;

• Potential defects in title to our properties;

• Federal and state regulatory developments and approvals, including the adoption of new regulatory requirements;

• Losses possible from future litigation;

• Environmental risks;

• Changes in interest rates;

• Developments in oil and natural gas-producing countries;

• Events similar to those of September 11, 2001, Hurricanes Katrina, Rita, Gustav and Ike and the Deepwater Horizon explosion; and

• Worldwide political and economic conditions.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see our filings with SEC, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.

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

James Hagemeier

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)

	September 30, 2011		December 31, 2010
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16,129	$	18,879
Accounts receivable, net		44,007		26,093
Due from affiliates		272		435
Prepaid expenses and other		31,639		13,123
Derivative assets		20,340		—
TOTAL CURRENT ASSETS		112,387		58,530
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $91,504 and $55,119 at September 30, 2011 and December 31, 2010, respectively		257,125		123,783
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $680 and $264 at September 30, 2011 and December 31, 2010, respectively		2,253		1,152
OTHER ASSETS
Debt issue costs, net		9,549		8,871
Derivative assets		7,211		—
Asset retirement obligation escrow receivable		20,348		—
Escrow for abandonment costs		160,986		114,168
Other assets		3,032		—
TOTAL OTHER ASSETS		201,126		123,039
TOTAL ASSETS	$	572,891	$	306,504
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	67,329	$	34,111
Derivative liabilities		—		3,754
Asset retirement obligations		16,514		1,023
Current portion of debt and notes payable		10,357		2,069
TOTAL CURRENT LIABILITIES		94,200		40,957
LONG-TERM LIABILITIES
Gas imbalance payable		1,087		4,552
Derivative liabilities		—		11,702
Asset retirement obligations, net of current portion		266,344		121,219
Debt, net of current portion, net of unamortized discount of $1,166 and $1,316 at September 30, 2011 and December 31, 2010, respectively		162,834		148,684
TOTAL LONG-TERM LIABILITIES		430,265		286,157
TOTAL LIABILITIES		524,465		327,114
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)		48,426		(20,610	)
TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	572,891	$	306,504

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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
REVENUES:
Oil sales	$	56,470		$	11,699		$	147,038		$	38,727
Natural gas sales		22,398			6,980			57,388			22,138
Plant product sales and other revenue		5,500			1,417			13,614			4,341
Realized gain on derivative financial instruments		6,746			2,272			3,664			6,312
Unrealized gain (loss) on derivative financial instruments		50,234			(1,578	)		43,006			5,796
TOTAL REVENUES		141,348			20,790			264,710			77,314
OPERATING EXPENSES:
Lease operating		47,125			11,634			100,000			28,909
Production taxes		231			77			439			464
Workover		6,053			961			11,599			2,004
Exploration		—			169			—			707
Depreciation, depletion and amortization		14,411			6,622			32,018			19,916
Impairment		1,096			—			5,419			—
General and administrative		4,991			2,651			16,862			7,025
Accretion		9,089			1,831			18,471			5,495
Gain on sale of asset		—			—			(142	)		—
TOTAL OPERATING EXPENSES		82,996			23,945			184,666			64,520
INCOME (LOSS) FROM OPERATIONS		58,352			(3,155	)		80,044			12,794
OTHER INCOME (EXPENSE):
Interest income		131			61			358			64
Miscellaneous expense		(496	)		(686	)		(6,086	)		(686	)
Interest expense		(6,873	)		(2,262	)		(19,275	)		(6,526	)
TOTAL OTHER EXPENSE		(7,238	)		(2,887	)		(25,003	)		(7,148	)
NET INCOME (LOSS)		51,114			(6,042	)		55,041			5,646
PREFERRED UNIT DIVIDENDS		1,800			—			2,400			—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON UNIT HOLDERS	$	49,314		$	(6,042	)	$	52,641		$	5,646

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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 three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Average daily sales:
Oil (Boepd)		5,985		1,665			5,108		1,857
Natural gas (Mcfpd)		56,917		17,366			47,451		17,638
Plant products (Gal/d)		29,090		9,926			28,393		8,172
Oil equivalents (Boepd)		16,164		4,796			13,693		4,991
Average realized prices(1)
Oil ($/Bbl)	$	107.64	$	81.07		$	102.51	$	79.20
Natural gas ($/Mcf)		5.03		5.34			5.03		5.61
Plant products ($/Gallon)		1.40		1.03			1.25		1.02
Oil equivalents ($/Boe)		60.09		49.61			58.26		50.97
Lease operating expense ($/Boe)		31.69		26.36			26.75		21.22
Production tax expense ($/Boe)		0.16		0.17			0.12		0.34
General and administrative expense ($/Boe)		3.36		6.01			4.51		5.16
Net income (loss) (in thousands)		51,114		(6,042	)		55,041		5,646
Adjusted EBITDA(2) (in thousands)		32,349		6,251			87,076		31,787

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

(2) Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes, depreciation and amortization, impairment, accretion, unrealized gain/loss on derivative instruments, and gain on sale of asset. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP, and should not be considered as an alternative to net income (loss), operating income (loss) 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.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Net income (loss)	$	51,114		$	(6,042	)	$	55,041		$	5,646
Adjusted EBITDA	$	32,349		$	6,251		$	87,076		$	31,787
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)	$	51,114		$	(6,042	)	$	55,041		$	5,646
Interest expense		6,873			2,262			19,275			6,526
Unrealized (gain) loss on derivative instruments		(50,234	)		1,578			(43,006	)		(5,796	)
Accretion		9,089			1,831			18,471			5,495
Depreciation, depletion, amortization and impairment		15,507			6,622			37,437			19,916
Gain on sale of asset		—			—			(142	)		—
Adjusted EBITDA	$	32,349		$	6,251		$	87,076		$	31,787

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