UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 12b-25

NOTIFICATION OF LATE FILING

SEC FILE NUMBER: 000-21574

(Check One)	x  Form 10-K     ¨  Form 20-F     ¨  Form 11-K     ¨  Form 10-Q ¨  Form 10-D     ¨  Form N-SAR     ¨  Form N-CSR
	For Period Ended: December 31, 2012
	¨  Transition Report on Form 10-K
	¨  Transition Report on Form 20-F
	¨  Transition Report on Form 11-K
	¨  Transition Report on Form 10-Q
	¨  Transition Report on Form N-SAR
	For the Transition Period Ended:

Read Instruction (on back page) Before Preparing Form. Please Print or Type.

Nothing in this form shall be construed to imply that the Commission has verified any information contained herein.

If the notification relates to a portion of the filing checked above, identify the Item(s) to which the notification relates:

PART I — REGISTRANT INFORMATION

Black Elk Energy Offshore Operations, LLC

Full Name of Registrant

N/A

Former Name if Applicable

11451 Katy Freeway, Suite 500

Address of Principal Executive Office (Street and Number)

Houston, Texas 77079

City, State and Zip Code

PART II — RULES 12b-25(b) AND (c)

If the subject report could not be filed without unreasonable effort or expense and the registrant seeks relief pursuant to Rule 12b-25(b), the following should be completed. (Check box if appropriate)

x	(a)	The reasons described in reasonable detail in Part III of this form could not be eliminated without unreasonable effort or expense;
	(b)	The subject annual report, semi-annual report, transition report on Form 10-K, Form 20-F, Form 11-K, Form N-SAR or Form N-CSR, or portion thereof, will be filed on or before the fifteenth calendar day following the prescribed due date; or the subject quarterly report or transition report on Form 10-Q or subject distribution report on Form 10-D, or portion thereof, will be filed on or before the fifth calendar day following the prescribed due date; and
	(c)	The accountant’s statement or other exhibit required by Rule 12b-25(c) has been attached if applicable.

PART III — NARRATIVE

State below in reasonable detail why Forms 10-K, 20-F, 11-K, 10-Q, 10-D, N-SAR, N-CSR, or the transition report or portion thereof, could not be filed within the prescribed time period.

The Company is presently seeking an amendment and/or waiver of certain covenants in its credit facility, the result of which could have a significant impact on its financial position and disclosure. The Company currently anticipates obtaining such amendment and/or waiver on or before April 10, 2013. Therefore, the Company was unable to file its Annual Report on Form 10-K (including its financial statements) in a timely manner without unreasonable effort and expense.

PART IV — OTHER INFORMATION

(1) Name and telephone number of person to contact in regard to this notification

Gary Barton	(281)	598-8600
(Name)	(Area Code)	(Telephone Number)

(2) Have all other periodic reports required under Section 13 or 15(d) of the Securities Exchange Act of 1934 or Section 30 of the Investment Company Act of 1940 during the preceding 12 months or for such shorter period that the registrant was required to file such report(s) been filed? If answer is no, identify report(s).    Yes  ¨    No  x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Exchange Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

(3) Is it anticipated that any significant change in results of operations from the corresponding period for the last fiscal year will be reflected by the earnings statements to be included in the subject report or portion thereof?    Yes  x    No  ¨

If so, attach an explanation of the anticipated change, both narratively and quantitatively, and, if appropriate, state the reasons why a reasonable estimate of the results cannot be made.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

	Year Ended December 31,
	2012			2011			Change			% Change
PRODUCTION:
Oil (MBbl)		1,977			1,991			(14	)		-1	%
Natural gas (MMcf)		17,884			18,188			(304	)		-2	%
Plant products (MGal)		13,588			12,257			1,331			11	%
Total (MBoe)		5,281			5,314			(33	)		-1	%
REVENUES
Oil sales	$	210,720		$	215,204		$	(4,484	)		-2	%
Natural gas sales		50,470			75,994			(25,524	)		-34	%
Plant product sales and other income		24,707			23,091			1,616			7	%
Realized gain on derivative financial instruments		23,364			8,099			15,265			188	%
Unrealized (loss) gain on derivative financial instruments		(4,783	)		17,556			(22,339	)		127	%
		304,478			339,944			(35,466	)		-10	%
OPERATING EXPENSES
Lease operating		180,691			158,545			22,146			14	%
Production taxes		745			859			(114	)		-13	%
Workover		17,986			23,385			(5,399	)		-23	%
Exploration		1,682			1,004			678			68	%
Depreciation, depletion and amortization		46,366			47,214			(848	)		-2	%
Impairment		18,727			12,967			5,760			44	%
General and administrative		26,486			22,029			4,457			20	%
Gain due to involuntary conversion of asset		(3,100	)		—			(3,100	)		100	%
Accretion		36,421			27,410			9,011			33	%
Gain on sale of asset		38			(142	)		180			-127	%
TOTAL OPERATING EXPENSES		326,042			293,271			32,771			11	%
(LOSS) INCOME FROM OPERATIONS		(21,564	)		46,673			(68,237	)		146	%
OTHER INCOME (EXPENSE)
Interest income		319			373			(54	)		-14	%
Miscellaneous (expense) income		(3,504	)		(6,253	)		2,749			-44	%
Interest expense		(25,965	)		(25,752	)		(213	)		1	%
TOTAL OTHER INCOME (EXPENSE)		(29,150	)		(31,632	)		2,482			-8	%
NET (LOSS) INCOME	$	(50,714	)	$	15,041		$	(65,755	)		437	%

Production

Oil and natural gas production. Total oil, natural gas and plant product production of 5,281 MBoe decreased 33 MBoe, or 1%, during the year ended December 31, 2012, compared to the same period in 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 BSEE requirement for approval after the West Delta 32 Incident, partially offset by a full year of production of the properties acquired in the Merit Acquisition (872 MBoe).

Revenues

Total revenues. Total revenues for the year ended December 31, 2012 of $304.5 million decreased $35.5 million, or 10%, over the comparable period in 2011. The decrease in revenues during 2012 was a result of 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 the same period in 2011 as a result of lower oil and natural gas production from uneconomic leases and several fields being shut-in and lower oil, natural gas and plant product prices.

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. Excluding hedges, for the year ended December 31, 2011, 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 same period of 2011. The increase in lease operating costs during 2012 was directly related to the additional properties acquired in the Maritech Acquisition and 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 a mix of increased properties and lower 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 same period in 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 $46.4 million, or $8.78 per Boe, and $47.2 million, or $8.88 per Boe, for the years ended December 31, 2012 and 2011, respectively. In 2012, the decrease in DD&A expense was the result of 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 $18.7 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.

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.

Black Elk Energy Offshore Operations, LLC

(Name of Registrant as Specified in Charter)

has caused this notification to be signed on its behalf by the undersigned hereunto duly authorized.

Date April 1, 2013	By	/s/ Gary Barton
		Gary Barton
		Interim Chief Financial Officer

ATTENTION

Intentional misstatements or omissions of fact constitute Federal Criminal Violations (See 18 U.S.C. 1001)