10-Q 1 a20130930-10q.htm 10-Q 2013.09.30-10Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
 
 
 
FORM 10-Q

 
 
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2013
or
¨
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: 333-174226 
 
 
 
BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC
(Exact name of registrant as specified in its charter) 
 
 
 
Texas
38-3769404
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
11451 Katy Freeway, Suite 500
Houston, Texas
77079
(Address of principal executive offices)
(Zip Code)
(281) 598-8600
Registrant’s telephone number, including area code
 
 
 
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  ý
(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.)
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  ý    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. (Check one):
Large accelerated filer
¨
Accelerated filer
¨
 
 
 
 
Non-accelerated filer
x  (Do not check if a smaller reporting company)
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  ý
As of November 12, 2013, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 104,988,929 Class E Units issued and outstanding.




BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2013
TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
 
 


(i)




PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
 
September 30,
2013
 
December 31,
2012
 
(Unaudited)
 
 
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
6,686

 
$
1,383

Restricted cash
694

 

Accounts receivable, net of allowance for doubtful accounts of $817 at September 30, 2013 and $509 at December 31, 2012
60,361

 
46,553

Accounts receivable - insurance recovery
254

 
3,100

Due from affiliates
273

 
347

Prepaid expenses and other current assets
11,092

 
27,972

Current portion of escrow for abandonment costs
4,323

 

Derivative assets

 
2,408

TOTAL CURRENT ASSETS
83,683

 
81,763

OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $265,893 and $191,326 at September 30, 2013 and December 31, 2012, respectively
234,918

 
260,012

OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $4,792 and $1,717 at September 30, 2013 and December 31, 2012, respectively
5,334

 
1,968

OTHER ASSETS
 
 
 
Debt issue costs, net
1,889

 
3,230

Asset retirement obligation escrow receivable
20,348

 
20,348

Escrow for abandonment costs, net of current portion
234,334

 
215,263

Other assets
7,068

 
7,880

TOTAL OTHER ASSETS
263,639

 
246,721

TOTAL ASSETS
$
587,574

 
$
590,464

LIABILITIES AND MEMBERS’ DEFICIT
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable and accrued expenses
$
193,419

 
$
108,736

Derivative liabilities
7,523

 

Asset retirement obligations
32,124

 
41,572

Current portion of debt and notes payable
243

 
3,552

TOTAL CURRENT LIABILITIES
233,309

 
153,860

LONG-TERM LIABILITIES
 
 
 
Gas imbalance payable
2,147

 
2,521

Dividends payable

 
12,408

Derivative liabilities
1,149

 
5,091

Asset retirement obligations, net of current portion
270,762

 
303,933

Debt, net of current portion, net of unamortized discount of $686 and $882 at September 30, 2013 and December 31, 2012, respectively
184,367

 
201,118

TOTAL LONG-TERM LIABILITIES
458,425

 
525,071

TOTAL LIABILITIES
691,734

 
678,931

CLASS E AND CLASS D PREFERRED UNITS
104,989

 
30,000

COMMITMENTS AND CONTINGENCIES

 

MEMBERS’ DEFICIT
(209,149
)
 
(118,467
)
TOTAL LIABILITIES AND MEMBERS’ DEFICIT
$
587,574

 
$
590,464

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


1



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,
 
2013
 
2012
 
2013
 
2012
REVENUES:
 
 
 
 
 
 
 
Oil sales
$
50,479

 
$
50,721

 
$
136,415

 
$
165,441

Natural gas sales
12,600

 
13,289

 
40,046

 
36,754

Plant product sales
1,457

 
2,876

 
5,831

 
11,079

Realized (loss) gain on derivative financial instruments
(2,725
)
 
3,284

 
(2,573
)
 
11,189

Unrealized (loss) gain on derivative financial instruments
(5,143
)
 
(16,129
)
 
(5,989
)
 
7,375

Other revenues
7,089

 
3,084

 
16,389

 
8,062

TOTAL REVENUES
63,757

 
57,125

 
190,119

 
239,900

OPERATING EXPENSES:
 
 
 
 
 
 
 
Lease operating
50,995

 
43,840

 
141,168

 
131,055

Production taxes
173

 
192

 
489

 
744

Workover
1,028

 
4,395

 
7,312

 
10,485

Exploration

 
311

 

 
1,249

Depreciation, depletion and amortization
10,027

 
12,302

 
32,727

 
36,546

Impairment of oil and gas properties
402

 
3,681

 
55,779

 
6,992

General and administrative
9,621

 
8,301

 
28,250

 
20,668

Gain on involuntary conversion of asset
(7,194
)
 

 
(17,827
)
 

Accretion of asset retirement obligations
4,458

 
9,256

 
19,551

 
27,228

Loss (gain) on sale of assets
424

 

 
(35,367
)
 
120

Other operating expenses
2,704

 

 
5,117

 

TOTAL OPERATING EXPENSES
72,638

 
82,278

 
237,199

 
235,087

(LOSS) INCOME FROM OPERATIONS
(8,881
)
 
(25,153
)
 
(47,080
)
 
4,813

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest income
30

 
11

 
81

 
305

Miscellaneous expense
(2,674
)
 
(919
)
 
(7,620
)
 
(2,408
)
Interest expense
(6,890
)
 
(6,514
)
 
(19,526
)
 
(19,422
)
TOTAL OTHER EXPENSE, NET
(9,534
)
 
(7,422
)
 
(27,065
)
 
(21,525
)
NET LOSS
(18,415
)
 
(32,575
)
 
(74,145
)
 
(16,712
)
LESS: PREFERRED UNIT DIVIDENDS
4,755

 
2,232

 
12,581

 
5,976

NET LOSS ATTRIBUTABLE TO COMMON UNIT HOLDERS
$
(23,170
)
 
$
(34,807
)
 
$
(86,726
)
 
$
(22,688
)
The accompanying notes are an integral part of these consolidated financial statements.


2



BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
 
Nine Months Ended September 30,
 
2013
 
2012
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net loss
$
(74,145
)
 
$
(16,712
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
32,727

 
36,546

Impairment of oil and gas properties
55,779

 
6,992

Accretion of asset retirement obligations
19,551

 
27,228

Amortization of debt issue costs
4,595

 
3,455

Accretion of debt discount
195

 
171

Unrealized loss (gain) on derivative financial instruments
5,989

 
(7,375
)
(Gain) loss on sale of assets
(35,367
)
 
120

Provision on doubtful accounts
308

 

Gain on involuntary conversion of assets
(17,827
)
 

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(13,086
)
 
10,514

Due from affiliates, net
74

 
(1
)
Prepaid expenses and other assets
16,440

 
(6,920
)
Other assets
464

 

Accounts payable and accrued liabilities
74,560

 
2,737

Gas imbalance
(16
)
 
896

Settlement of asset retirement obligations
(41,512
)
 
(13,623
)
NET CASH PROVIDED BY OPERATING ACTIVITIES
28,729

 
44,028

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Additions to oil and gas properties
(112,719
)
 
(18,153
)
Acquisition of oil and gas properties
(3,250
)
 
(3,454
)
Sale of oil and gas properties
65,741

 
(120
)
Additions to property and equipment
(683
)
 
(252
)
Cash assumed in consolidation of Freedom Well Services, LLC
473

 

Proceeds received from insurance recovery
23,837

 

Deposits
(9
)
 
(272
)
Restricted cash
(694
)
 

Escrow payments, net
(23,394
)
 
(38,878
)
NET CASH USED IN INVESTING ACTIVITIES
(50,698
)
 
(61,129
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds on short term notes
348

 
17,644

Payments on short term notes
(3,827
)
 
(12,940
)
Borrowing on bank debt
23,168

 
145,000

Payments on bank debt
(40,168
)
 
(112,500
)
Debt issuance costs
(2,249
)
 
(3,022
)
Contributions from members
50,000

 

Distributions to members

 
(16,694
)
NET CASH PROVIDED BY FINANCING ACTIVITIES
27,272

 
17,488

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
5,303

 
387

CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD
1,383

 
17,260

CASH AND CASH EQUIVALENTS - END OF PERIOD
$
6,686

 
$
17,647

SUPPLEMENTAL CASH FLOW INFORMATION:
 
 
 
Cash paid for interest
$
11,773

 
$
12,603

NONCASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
Asset retirement obligations relieved due to sale of properties
$
(22,999
)
 
$

Increase in asset retirement due to revaluation
$
2,341

 
$

Paid-in-kind dividends on preferred equity and accrued distributions to members
$
12,581

 
$
5,976

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

3



BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Unaudited)
NOTE 1—BASIS OF PRESENTATION
Nature of Operations: Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries (collectively, “Black Elk”, "BEEOO", “we”, “our” or “us”) is a Houston-based oil and natural gas company engaged in the exploration, development, production and exploitation of oil and natural gas properties. We were formed on November 20, 2007 for the purpose of acquiring oil and natural gas producing properties within the Outer Continental Shelf of the United States in the Gulf of Mexico.
Basis of Presentation: The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation of our interim and prior period results have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for any other interim period or for the entire fiscal year. For further information, refer to the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Form 10-K”).
Reclassifications: Certain reclassifications have been made to conform 2012 balances to our 2013 presentation. Such reclassifications had no effect on net loss or cash flow.
Principles of Consolidation: The consolidated financial statements include the accounts of Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries, Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. Effective January 1, 2013, in accordance with accounting guidelines for consolidation of variable interest entities, we consolidated Freedom Well Services, LLC (“FWS”), as we determined that we are the primary beneficiary of FWS and will have the power to direct the activities of FWS. All material intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates in Preparation of Financial Statements: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. We analyze our estimates based on historical experience, current factors and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates.
Recent Accounting Pronouncements: In December 2011, the FASB issued accounting guidance which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (“IFRS”) related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. The adoption of this amendment did not have a material impact on our consolidated financial statements.
NOTE 2—LIQUIDITY RISKS AND UNCERTAINTIES
As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $(149.6) million at September 30, 2013. The combination of restricted credit availability, lower production since the fourth quarter of 2012, our drilling program, settlement of our plugging and abandonment ("P&A") liabilities and additional collateral requirements related to the surety bonds that secure our P&A obligations led to significant reductions in our working capital in the fourth quarter of 2012 and the first nine months of 2013. To increase liquidity, we stretched accounts payable, aggressively pursued accounts receivable and sold assets. We continue to optimize our production portfolio and recommenced our drilling program in the fourth quarter of 2012, which is substantially complete for 2013. We have completed six operated wells and two non-operated wells in 2013. We expect to drill or complete two non-operated wells during the fourth quarter of 2013. To fund our drilling programs and operations, we expect to continue to raise additional capital over the next several years. To improve our access to funding, on August 30, 2013, we consented to the assignment by Capital One Bank, N.A. and the other lenders of all of their rights and obligations under our Credit Agreement, dated as of December 24, 2010 (the “Credit Facility”), to White Elk LLC, as Administrative Agent and Lender, and Resource Value Group LLC, as Lender. Resource Value Group LLC is affiliated with our majority owner, Platinum Partners Value Arbitrage Fund L.P. Also, we are evaluating additional potential asset sales of core and non-core assets to optimize our portfolio and normalize the age of our accounts payable. On March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC ("Renaissance") for approximately $52.5 million subject to

4



normal adjustments. A portion of the proceeds from the sale were used to reduce the amount borrowed under the Credit Facility by $36 million and the remainder was used for general corporate purposes. Cash collateral securing surety bonds of approximately $9.0 million related to the sold properties were released and received in the third quarter of 2013. The remainder of the cash collateral securing surety bonds for the sold properties was used to increase the collateral with the surety companies relating to bonds that had previously been issued to satisfy the bonding and security requirements of the Bureau of Ocean Energy Management (“BOEM”). We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal adjustments.
Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties, settlement of our P&A as well as providing collateral to secure our P&A obligations. As we plug and abandon certain fields and meet the various criteria related to the corresponding escrow accounts, we expect to release funds from the escrow accounts. Also, our letters of credit with Capital One are backed entirely by cash. We use letters of credit to back a portion of our surety bonds for P&A obligations.

On August 30, 2013, we entered into a Limited Waiver and Eleventh Amendment to our Credit Facility to (1) obtain waivers related to our financial covenants for the third and fourth quarters of 2013, (2) extend the maturity date under the credit facility to January 1, 2015, (3) increase the Applicable Margin under the Credit Facility by one percent (for a total increase of two percent when combined with the one percent increase pursuant to the Eighth Amendment), (4) maintain the borrowing base at $25 million, subject to the right of Resource Value Group LLC to require the Administrative Agent to increase the borrowing base up to a maximum of $50 million, and (5) waive our right and the right of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014. The borrowing base under the Credit Facility was increased to $35 million on September 30, 2013 and as of that date we had $35 million outstanding. Subsequently, the borrowing base was increased to $47 million on October 15, 2013. As of November 14, 2013, we had $45 million drawn on the Credit Facility.
As of September 30, 2013, we were in compliance with all covenants under the Indenture. We believe anticipated capital expenditures in 2013 will exceed the amount provided for in a covenant regarding maximum capital expenditures. However, the Indenture also provides that we may use proceeds from the sale of assets for capital expenditures that we believe is not limited by the previously referenced capital expenditure covenant. In the event our interpretation of the Indenture is not upheld or if our cash proceeds from the sale of assets are not sufficient to reduce our capital expenditures to a level that makes us compliant with the maximum capital expenditure covenant, we have the option under the Indenture to redeem the 13.75% Senior Secured Notes due 2015 (the "Notes"), beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes; however, there can be no assurance that we will have sufficient funds to do so. We also have the option to solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our credit facility.
We are currently evaluating new sources of liquidity including, but not limited to, accessing the debt capital markets and potential asset sales of non-core and core properties to optimize our portfolio. The accompanying financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amount and classifications of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due. For additional information, please see “Risk Factors” under Item 1A of this Form 10-Q.
Our capital budget may be adjusted in the future as business conditions warrant and the ultimate amount of capital we expend may fluctuate materially based on market conditions and the success of our drilling program as the year progresses. The amount, timing and allocation of capital expenditures are largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Our planned operations for the remainder of 2013 reflect our expectations for production based on actual production history and new production expected to be brought online, the continuation of commodity prices near current levels and the higher cost of servicing our additional financing and other obligations.
Our cash flow projections are highly dependent upon numerous assumptions including the timing and rates of production from our wells, the sales prices we realize for our oil and natural gas, the cost to develop and produce our reserves, our ability to monetize our properties and future production through asset sales and financial derivatives, and a number of other factors, some of which are beyond our control. Our inability to increase near-term production levels and generate sufficient liquidity through the actions noted above could result in our inability to meet our obligations as they come due which would have a

5



material adverse effect on our financial position, results of operation and cash flows. In the event we do not achieve the projected production and cash flow increases, we will attempt to fund any short-term liquidity needs through other financing sources; however, there is no assurance that we will be able to do so in the future if required to meet any short-term liquidity needs.
Our estimates of proved oil and natural gas reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimation process requires significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise and the quality and reliability of this data can vary. Estimates of our oil and natural gas reserves and the costs and timing associated with developing these reserves are subject to change, and may differ materially from our actual results. A substantial portion of our total proved reserves are undeveloped and recognition of such reserves requires us to expect that capital will be available to fund their development. The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year and we intend to continue to develop these reserves, but there is no assurance we will be successful. Development of these reserves may not yield the expected results, or the development may be delayed or the costs may exceed our estimates, any of which may materially affect our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet the requirements of our financing obligations.
Our current production is concentrated in the Gulf of Mexico, which is characterized by production declines more rapid than those of conventional onshore properties. As a result, we are particularly vulnerable to a near-term severe impact resulting from unanticipated complications in the development of, or production from, any single material well or infrastructure installation, including lack of sufficient capital, delays in receiving necessary drilling and operating permits, increased regulation, reduced access to equipment and services, mechanical or operational failures, and severe weather. Any unanticipated significant disruption to, or decline in, our current production levels or prolonged negative changes in commodity prices or operating cost levels could have a material adverse effect on our financial position, results of operations, cash flows, the quantity of proved reserves that we report, and our ability to meet our commitments as they come due.
Oil and natural gas development and production in the Gulf of Mexico are regulated by the BOEM and the Bureau of Safety and Environmental Enforcement ("BSEE") of the Department of the Interior (“DOI”). We cannot predict future changes in laws and regulations governing oil and gas operations in the Gulf of Mexico. New regulations issued since the Deepwater Horizon incident in 2010 have changed the way we conduct our business and increased our costs of developing and commissioning new assets. Should there be additional significant future regulations or additional statutory limitations, they could require further changes in the way we conduct our business, further increase our costs of doing business or ultimately prohibit us from drilling for or producing hydrocarbons in the Gulf of Mexico.
As an oil and gas company, our revenue, profitability, cash flows, proved reserves and future rate of growth are substantially dependent on prevailing prices for oil and natural gas. Historically, the energy markets have been very volatile, and we expect such price volatility to continue. Any extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of oil and gas reserves that we can economically produce, and may restrict our ability to obtain additional financing or to meet the contractual requirements of our debt and other obligations.
NOTE 3—OIL AND GAS PROPERTIES
The following table reflects capitalized costs related to our oil and gas properties:
 
September 30,
2013
 
December 31, 2012
 
(Unaudited)
 
 
 
(in thousands)
Proved properties
$
500,811

 
$
451,338

Accumulated depreciation, depletion, amortization and impairment
(265,893
)
 
(191,326
)
Oil and gas properties, net
$
234,918

 
$
260,012


6



The following table describes the changes to our asset retirement obligations (unaudited):
 
(in thousands)
Balance at December 31, 2012
$
345,505

Revaluation of liability
2,341

Liabilities relieved due to sale of properties
(22,999
)
Liabilities settled
(41,512
)
Accretion expense
19,551

Balance at September 30, 2013
$
302,886

Less: current portion
(32,124
)
Total Long-Term Asset Retirement Obligations
$
270,762

NOTE 4—ACQUISITIONS AND DIVESTITURES
On March 26, 2013, we completed the sale of four fields to Renaissance for approximately $52.5 million subject to normal adjustments. Funds were used to reduce the amount borrowed under the Credit Facility by $36 million and for general corporate purposes. We sold an additional interest in one field to Renaissance on July 31, 2013 for $10.5 million subject to normal adjustments. Funds were used for general corporate purposes.
NOTE 5—DERIVATIVE INSTRUMENTS
We enter into hedging transactions with major financial institutions to reduce exposure to fluctuations in the price of oil and natural gas. We use financially settled crude oil and natural gas swaps. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. We elected not to designate any of our derivative contracts as qualifying hedges for financial reporting purposes, therefore all of the derivative instruments are categorized as standalone derivatives and are being marked-to-market with “Unrealized (loss) gain on derivative financial instruments” recorded in the consolidated statements of operations.

7


At September 30, 2013, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss) (unaudited)):
 
 
Crude Oil
 
Natural Gas
 
Total
Period
 
Monthly Volume
(Bbls)
 
Contract
Price
($/Bbl)
 
Asset
(Liability)
 
Fair  Value
Gain
(Loss)
 
Monthly Volume
(MMBtu)
 
Contract
Price
($/MMBtu)
 
Asset
(Liability)
 
Fair  Value
Gain
(Loss)
 
Asset
(Liability)
 
Fair  Value
Gain
(Loss)
Swaps:
 
 
 
 
 
(in thousands)
 
 
 
 
 
(in thousands)
 
(in thousands)
10/13 - 10/13
 
27,750

 
$
96.90

 
$
(140
)
 
$
(140
)
 
104,000

 
$
4.60

 
$
114

 
$
114

 
$
(26
)
 
$
(26
)
11/13 - 11/13
 
26,800

 
96.90

 
(121
)
 
(121
)
 
104,000

 
4.60

 
$
106

 
106

 
(15
)
 
(15
)
12/13 - 12/13
 
27,750

 
96.90

 
(101
)
 
(101
)
 
104,000

 
4.60

 
88

 
88

 
(13
)
 
(13
)
1/14 - 2/14
 
19,000

 
96.90

 
(84
)
 
(84
)
 
82,000

 
4.60

 
120

 
120

 
36

 
36

10/13 - 10/13
 
3,259

 
100.80

 
(4
)
 
(4
)
 
91,166

 
4.94

 
132

 
132

 
128

 
128

11/13 - 11/13
 

 

 

 

 
64,926

 
4.94

 
88

 
88

 
88

 
88

12/13 - 12/13
 
10,042

 
100.80

 
1

 
1

 
119,462

 
4.94

 
141

 
141

 
142

 
142

1/14 - 5/14
 
10,083

 
100.80

 
139

 
139

 
129,960

 
4.94

 
694

 
694

 
833

 
833

6/14 - 6/14
 

 

 

 

 
129,960

 
4.94

 
133

 
133

 
133

 
133

10/13 - 12/13
 
19,750

 
85.90

 
(905
)
 
(905
)
 
47,000

 
5.00

 
196

 
196

 
(709
)
 
(709
)
1/14 - 12/14
 
15,000

 
65.00

 
(4,947
)
 
(4,947
)
 

 

 

 

 
(4,947
)
 
(4,947
)
10/13 - 10/13
 
28,006

 
88.80

 
(368
)
 
(368
)
 
34,551

 
4.09

 
20

 
20

 
(348
)
 
(348
)
11/13 - 11/13
 
31,605

 
88.80

 
(395
)
 
(395
)
 
28,939

 
4.09

 
15

 
15

 
(380
)
 
(380
)
12/13 - 12/13
 
38,743

 
88.80

 
(448
)
 
(448
)
 
37,906

 
4.09

 
13

 
13

 
(435
)
 
(435
)
1/14 - 1/14
 
4,723

 
88.80

 
(49
)
 
(49
)
 
43,347

 
4.09

 
11

 
11

 
(38
)
 
(38
)
2/14 - 2/14
 
13,313

 
88.80

 
(126
)
 
(126
)
 
32,636

 
4.09

 
8

 
8

 
(118
)
 
(118
)
3/14 - 3/14
 
8,413

 
88.80

 
(71
)
 
(71
)
 
46,764

 
4.09

 
12

 
12

 
(59
)
 
(59
)
4/14 - 4/14
 
12,473

 
88.80

 
(95
)
 
(95
)
 
41,253

 
4.09

 
13

 
13

 
(82
)
 
(82
)
5/14 - 5/14
 
11,793

 
88.80

 
(79
)
 
(79
)
 
40,391

 
4.09

 
11

 
11

 
(68
)
 
(68
)
6/14 - 6/14
 
15,546

 
88.80

 
(92
)
 
(92
)
 
20,112

 
4.09

 
5

 
5

 
(87
)
 
(87
)
7/14 - 7/14
 
11,845

 
88.80

 
(62
)
 
(62
)
 
39,283

 
4.09

 
9

 
9

 
(53
)
 
(53
)
8/14 - 8/14
 
13,165

 
88.80

 
(61
)
 
(61
)
 
34,246

 
4.09

 
7

 
7

 
(54
)
 
(54
)
9/14 - 9/14
 
16,235

 
88.80

 
(66
)
 
(66
)
 
29,753

 
4.09

 
6

 
6

 
(60
)
 
(60
)
10/14 - 10/14
 
15,605

 
88.80

 
(55
)
 
(55
)
 
28,635

 
4.09

 
5

 
5

 
(50
)
 
(50
)
11/14 - 11/14
 
18,525

 
88.80

 
(57
)
 
(57
)
 
27,081

 
4.09

 
3

 
3

 
(54
)
 
(54
)
12/14 - 12/14
 
22,526

 
88.80

 
(56
)
 
(56
)
 
34,114

 
4.09

 
(1
)
 
(1
)
 
(57
)
 
(57
)
10/13 - 10/13
 
4,000

 
87.85

 
(56
)
 
(56
)
 

 

 

 

 
(56
)
 
(56
)
11/13 - 11/13
 
250

 
87.85

 
(3
)
 
(3
)
 

 

 

 

 
(3
)
 
(3
)
12/13 - 12/13
 
2,500

 
87.85

 
(31
)
 
(31
)
 

 

 

 

 
(31
)
 
(31
)
1/14 - 1/14
 
46,000

 
87.85

 
(523
)
 
(523
)
 

 

 

 

 
(523
)
 
(523
)
2/14 - 2/14
 
25,000

 
87.85

 
(259
)
 
(259
)
 

 

 

 

 
(259
)
 
(259
)
3/14 - 3/14
 
56,000

 
87.85

 
(524
)
 
(524
)
 

 

 

 

 
(524
)
 
(524
)
4/14 - 4/14
 
45,000

 
87.85

 
(382
)
 
(382
)
 

 

 

 

 
(382
)
 
(382
)
5/14 - 5/14
 
46,000

 
87.85

 
(349
)
 
(349
)
 

 

 

 

 
(349
)
 
(349
)
6/14 - 6/14
 
48,000

 
87.85

 
(326
)
 
(326
)
 
40,391

 
4.19

 
14

 
14

 
(312
)
 
(312
)
7/14 - 7/14
 
36,000

 
87.85

 
(219
)
 
(219
)
 
20,112

 
4.19

 
6

 
6

 
(213
)
 
(213
)
8/14 - 8/14
 
34,000

 
87.85

 
(186
)
 
(186
)
 
39,283

 
4.19

 
11

 
11

 
(175
)
 
(175
)
9/14 - 9/14
 
26,000

 
87.85

 
(128
)
 
(128
)
 
34,246

 
4.19

 
10

 
10

 
(118
)
 
(118
)
10/14 - 10/14
 
27,000

 
87.85

 
(118
)
 
(118
)
 
29,753

 
4.19

 
8

 
8

 
(110
)
 
(110
)
11/14 - 11/14
 
20,000

 
87.85

 
(78
)
 
(78
)
 
28,635

 
4.19

 
6

 
6

 
(72
)
 
(72
)
12/14 - 12/14
 
31,000

 
87.85

 
(101
)
 
(101
)
 
27,081

 
4.19

 
2

 
2

 
(99
)
 
(99
)
1/15 - 1/15
 

 

 

 

 
34,114

 
4.19

 

 

 

 

2/15 - 2/15
 

 

 

 

 
27,838

 
4.19

 

 

 

 

3/15 - 3/15
 

 

 

 

 
24,461

 
4.19

 
1

 
1

 
1

 
1

1/15 - 1/15
 

 

 

 

 
27,838

 
4.09

 
(3
)
 
(3
)
 
(3
)
 
(3
)
2/15 - 2/15
 

 

 

 

 
24,461

 
4.09

 
(2
)
 
(2
)
 
(2
)
 
(2
)
3/15 - 3/15
 

 

 

 

 
26,443

 
4.09

 
(1
)
 
(1
)
 
(1
)
 
(1
)
10/13 - 10/13
 
67,513

 
108.44

 
181

 
181

 

 

 

 

 
181

 
181

11/13 - 11/13
 
64,159

 
108.44

 
184

 
184

 

 

 

 

 
184

 
184

12/13 - 12/13
 
45,392

 
108.44

 
162

 
162

 

 

 

 

 
162

 
162

1/14 - 1/14
 
46,006

 
100.72

 
(142
)
 
(142
)
 

 

 

 

 
(142
)
 
(142
)
2/14 - 2/14
 
39,159

 
100.72

 
(88
)
 
(88
)
 

 

 

 

 
(88
)
 
(88
)
3/14 - 3/14
 
36,822

 
100.72

 
(55
)
 
(55
)
 

 

 

 

 
(55
)
 
(55
)
4/14 - 4/14
 
34,069

 
100.72

 
(25
)
 
(25
)
 

 

 

 

 
(25
)
 
(25
)
5/14 - 5/14
 
35,200

 
100.72

 
1

 
1

 

 

 

 

 
1

 
1

6/14 - 6/14
 
31,668

 
100.72

 
23

 
23

 

 

 

 

 
23

 
23

7/14 - 7/14
 
48,509

 
100.72

 
64

 
64

 

 

 

 

 
64

 
64

8/14 - 8/14
 
46,473

 
100.72

 
87

 
87

 

 

 

 

 
87

 
87

9/14 - 9/14
 
45,830

 
100.72

 
110

 
110

 

 

 

 

 
110

 
110

10/14 - 10/14
 
44,282

 
100.72

 
125

 
125

 

 

 

 

 
125

 
125

11/14 - 11/14
 
40,874

 
100.72

 
130

 
130

 

 

 

 

 
130

 
130

12/14 - 12/14
 
26,424

 
100.72

 
95

 
95

 

 

 

 

 
95

 
95

 
 
 
 
 
 
$
(10,673
)
 
$
(10,673
)
 
 
 
 
 
$
2,001

 
$
2,001

 
$
(8,672
)
 
$
(8,672
)

8


The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands) (unaudited):
 
 
Asset Derivatives
 
Liability Derivatives
 
Asset (Liability) Derivatives Total
Derivatives Not  Designated as Hedging Instruments under Accounting Guidance
 
Balance Sheet
Location
 
Fair Value at
September 30,
2013
 
Balance Sheet
Location
 
Fair Value at
September 30,
2013
 
Balance Sheet
Location
 
Fair Value at
September 30,
2013
Commodity Contracts
 
Derivative  financial
instruments
 
 
 
Derivative  financial
instruments
 
 
 
Derivative  financial
instruments
 
 
 
 
Current
 
$
2,934

 
Current
 
$
(10,457
)
 
Current
 
$
(7,523
)
 
 
Non-current
 
376

 
Non-current
 
(1,525
)
 
Non-current
 
(1,149
)
Total derivative instruments
 
 
 
$
3,310

 
 
 
$
(11,982
)
 
 
 
$
(8,672
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Derivatives
 
Liability Derivatives
 
Asset (Liability) Derivatives Total
Derivatives Not  Designated as Hedging
Instruments under Accounting Guidance
 
Balance Sheet
Location
 
Fair Value at
December 31,
2012
 
Balance Sheet
Location
 
Fair Value at
December 31,
2012
 
Balance Sheet
Location
 
Fair Value at
December 31,
2012
Commodity Contracts
 
Derivative financial
instruments
 
 
 
Derivative financial
instruments
 
 
 
Derivative financial
instruments
 
 
 
 
Current
 
$
6,808

 
Current
 
$
(4,400
)
 
Current
 
$
2,408

 
 
Non-current
 
1,235

 
Non-current
 
(6,326
)
 
Non-current
 
(5,091
)
Total derivative instruments
 
 
 
$
8,043

 
 
 
$
(10,726
)
 
 
 
$
(2,683
)
We have a netting agreement with our financial institution that permits net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and we routinely exercise our contractual right to offset realized gains against realized losses when settling with our derivative counterparty.
The effect of derivate instruments on our consolidated statements of operations was as follows (in thousands) (unaudited):
Derivatives Not Designated as Hedging Instruments under Accounting Guidance
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
Statements of Operations Location
 
2013
 
2012
 
2013
 
2012
Commodity Contracts
 
Realized (loss) gain on derivative financial instruments
 
$
(2,725
)
 
$
3,284

 
$
(2,573
)
 
$
11,189

Commodity Contracts
 
Unrealized (loss) gain on derivative financial instruments
 
(5,143
)
 
(16,129
)
 
(5,989
)
 
7,375

Total derivative instruments
 
 
 
$
(7,868
)
 
$
(12,845
)
 
$
(8,562
)
 
$
18,564

NOTE 6—FAIR VALUE MEASUREMENTS
Accounting guidance for fair value measurements clarifies the definition of fair value, prescribes methods for measuring fair value, establishes a fair value hierarchy based on the inputs used to measure fair value, and expands disclosures about fair value measurements. The three-tier fair value hierarchy, which prioritizes the inputs used in the valuation methodologies, is:
Level 1—Valuations based on quoted prices for identical assets and liabilities in active markets.
Level 2—Valuations based on observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data.
Level 3—Valuations based on unobservable inputs reflecting our own assumptions, consistent with reasonably available assumptions made by other market participants. These valuations require significant judgment.
As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular

9


input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following tables present information about our assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands) (unaudited):
 
Fair Value Measurements
at September 30, 2013
Using Fair Value Hierarchy
 
Fair Value as of
September 30, 2013
 
Level 1
 
Level 2
 
Level 3
Assets
 
 
 
 
 
 
 
Oil and Natural Gas Derivatives
$
3,310

 
$

 
$
3,310

 
$

 
$
3,310

 
$

 
$
3,310

 
$

Liabilities
 
 
 
 
 
 
 
Oil and Natural Gas Derivatives
$
(11,982
)
 
$

 
$
(11,982
)
 
$

 
$
(11,982
)
 
$

 
$
(11,982
)
 
$

 
 
 
 
 
 
 
 
 
Fair Value Measurements
at December 31, 2012
Using Fair Value Hierarchy
 
Fair Value as of
December 31, 2012
 
Level 1
 
Level 2
 
Level 3
Assets
 
 
 
 
 
 
 
Oil and Natural Gas Derivatives
$
8,043

 
$

 
$
8,043

 
$

 
$
8,043

 
$

 
$
8,043

 
$

Liabilities
 
 
 
 
 
 
 
Oil and Natural Gas Derivatives
$
(10,726
)
 
$

 
$
(10,726
)
 
$

 
$
(10,726
)
 
$

 
$
(10,726
)
 
$

At September 30, 2013 and December 31, 2012, management estimates that the derivative contracts had a fair value of $(8.7) million and $(2.7) million, respectively. We estimated the fair value of derivative instruments using internally-developed models that use as their basis readily observable market parameters.
The determination of the fair values above incorporates various factors required under accounting guidance for fair value measurements. These factors include not only the impact of our nonperformance risk but also the credit standing of the counterparties involved in our derivative contracts.
As of September 30, 2013, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximated their carrying value due to their short-term nature. The estimated fair value of our debt was primarily based on quoted market prices as well as prices for similar debt based on recent market transactions. The fair value of debt at September 30, 2013 was $182.7 million.
Fair Value on a Non-Recurring Basis
Oil and gas properties with a carrying value of $290.7 million were written down to their fair value of $234.9 million, resulting in an impairment charge of $0.4 million and $55.8 million for the three and nine months ended September 30, 2013, respectively, which is recognized under “Impairments of oil and gas properties” in the consolidated statements of operations. As of September 30, 2012, oil and gas properties with a carrying value of $224.4 million were written down to their fair value of $217.4 million, resulting in an impairment charge of $3.7 million and $7.0 million for the three and nine months ended September 30, 2012, respectively. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.
The revaluation to asset retirement obligations resulted from revised estimations. Fair values for the asset retirement obligations are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $2.3 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2013.

10



NOTE 7—DEBT AND NOTES PAYABLE
Our debt and notes payable are summarized as follows:
 
September 30,
2013
 
December 31, 2012
 
(in thousands)
 
(unaudited)
 
 
Senior Secured Revolving Credit Facility
$
35,000

 
$
52,000

13.75% Senior Secured Notes, net of discount
149,314

 
149,118

AFCO Credit Corporation-insurance note payable

 
3,552

Other debt
296

 

Total debt
184,610

 
204,670

Less: current portion
(243
)
 
(3,552
)
Total long-term debt
$
184,367

 
$
201,118

Senior Secured Revolving Credit Facility
On December 24, 2010, we entered into a Credit Facility comprised of a senior secured revolving credit facility of up to $35 million and a $75 million secured letter of credit facility to be used exclusively for the issuance of letters of credit in support of our future P&A liabilities relating to our oil and natural gas properties (the “Letter of Credit Facility”). The Credit Facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 4.75% to 5.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 3.25% to 4.00%. The applicable margin is computed based on the borrowing based utilization percentage in effect from time to time. On August 30, 2013, we consented to the assignment by Capital One Bank, N.A. and the other lenders of all of their rights and obligations under the Credit Facility to White Elk LLC, as Administrative Agent and Lender, and Resource Value Group LLC, as Lender. Resource Value Group LLC is affiliated with our majority owner, Platinum Partners Value Arbitrage Fund L.P.
We have entered into various amendments to the Credit Facility and the Letter of Credit Facility. These amendments have, among other things, (1) changed our amount available for borrowing under the Credit Facility from $35 million to a current borrowing base of $47 million, (2) adjusted the commitments under the Letter of Credit Facility to a current level of approximately $66.6 million, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by a total of 2%, (4) amended certain provisions governing our swap agreements, (5) updated the fees on the letters of credit to 2% on a go-forward basis, (6) updated the “change in control” definition, (7) amended the definition of debt included in the calculation of the covenants, (8) changed the maturity date from December 24, 2013 to January 1, 2015 on the Credit Facility and to June 22, 2014 on the Letter of Credit Facility, (9) added affirmative covenants to be furnished on a weekly basis including updated cash flow projections, updated accounts payable and accounts receivable schedules, and daily production reports for the week, (10) added an affirmative covenant that we would receive certain specified capital contributions from Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE during the first quarter of 2013, (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants and (12) restricted returns of capital to our unit holders or distributions of our property to our equity interest holders.
On August 30, 2013, we entered into a Limited Waiver and Eleventh Amendment to our Credit Facility (the "Eleventh Amendment") to (1) obtain waivers related to our financial covenants for the third and fourth quarters of 2013, (2) extend the maturity date under the credit facility to January 1, 2015, (3) increase the Applicable Margin under the Credit Facility by one percent (for a total increase of two percent when combined with the one percent increase pursuant to the Eighth Amendment), (4) maintain the borrowing base at $25 million, subject to the right of Resource Value Group LLC to require the Administrative Agent to increase the borrowing base up to a maximum of $50 million and (5) waive our right and the right of the Lenders to request or obtain a borrowing base redetermination prior to the first scheduled redetermination date in 2014. The borrowing base under the Credit Facility was increased to $35 million on September 30, 2013 and as of that date we had $35 million outstanding. Subsequently, the borrowing base was increased to $47 million on October 15, 2013. As of November 14, 2013, we had $45 million drawn on the Credit Facility.
As of September 30, 2013, letters of credit in the aggregate amount of $96.6 million were outstanding under the Letter of Credit Facility. We had $35.0 million in borrowings under the Credit Facility. As of November 14, 2013, we had $2.0 million available for additional borrowings under the Credit Facility.
A commitment fee of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For each of the three and nine months ended September 30, 2013, we recognized $4,125 in commitment fees, which have been included in

11



“Interest expense” on the consolidated statements of operations. A letter of credit fee is computed based on the same applicable margin used to determine the interest rate to Eurodollar loans times the stated face amount of each letter of credit.
The Credit Facility is secured by mortgages on at least 80% of the total value of our proved oil and gas reserves. The borrowing base is re-determined semi-annually on or around April 1st and October 1st of each year.
The Credit Facility requires us and our subsidiaries to maintain certain financial covenants. Specifically, we may not permit, in each case as calculated as of the end of each fiscal quarter, our total leverage ratio to be more than 2.5 to 1.0, our interest coverage ratio to be less than 3.0 to 1.0, or our payables restriction covenant, which does not allow accounts payable greater than 90 days old to exceed $6.0 million in the aggregate, excluding certain vendors (in each case as defined in our revolving Credit Facility). In addition, we and our subsidiaries are subject to various covenants, including, but not limited to, restrictions on our and our subsidiaries’ ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to their security interests, pay dividends, make acquisitions, loans, advances or investments, sell or otherwise transfer assets, enter into transactions with affiliates or change our line of business. As of September 30, 2013, we were not in compliance with the total leverage ratio covenant, the hedging requirement covenant and the interest coverage ratio covenant. Our total leverage ratio was calculated to be 6.0 to 1.0, which was higher than the required maximum of 2.5 to 1.0. Our hedging requirement of our notional volumes exceeded 60% for the months of October and November 2013 by 21% and 13%, respectively, of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. Our interest coverage ratio covenant was calculated to be 1.2 to 1.0, which was lower than the minimum 3.0 to 1.0. Our payables restriction covenant was calculated to be $27.2 million which was higher than the maximum of $6.0 million. We received a limited waiver relating to such covenants in the Eleventh Amendment for only the fiscal quarters ended September 30, 2013 and December 31, 2013 as well as a limited waiver and amendment on our Letter of Credit Facility in the Limited Waiver, Tenth Amendment to Letter of Credit Facility Agreement (the "Waiver and Tenth Amendment") for the fiscal quarter ended September 30, 2013.
13.75% Senior Secured Notes
On November 23, 2010, we issued $150 million face value of 13.75% Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our prior revolving credit facility, to fund BOEM collateral requirements, and to prefund our escrow accounts. We pay interest on the Notes semi-annually in arrears, on June 1 and December 1 of each year, which commenced on June 1, 2011. The Notes will mature on December 1, 2015, at which time all principal then outstanding will be due. As of September 30, 2013, the recorded value of the Notes was $149.3 million, which includes the unamortized discount of $0.7 million. We incurred underwriting and debt issue costs of $7.2 million, which have been capitalized and are being amortized over the life of the Notes.
The Notes are secured by a security interest in our and the guarantors’ assets (excluding the W&T Escrow Accounts (as defined below)) to the extent they constitute collateral under our existing unused Credit Facility and derivative contract obligations. The liens securing the Notes will be subordinated and junior to any first lien indebtedness, including our derivative contracts obligations and Credit Facility.
We have the right to redeem the Notes under various circumstances. If we experience a change of control, the holders of the Notes may require us to repurchase the Notes at 101% of the principal amount thereof, plus accrued unpaid interest. We also have an optional redemption in which we may redeem up to 35% of the aggregate principal amount of the Notes at a price equal to 110.0% of the principal amount, plus accrued interest and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings until December 1, 2013. From December 1, 2013 until December 1, 2014, we may redeem some or all of the Notes at an initial redemption price equal to par value plus one-half the coupon which equals 106.875% plus accrued and unpaid interest to the date of the redemption. On or after December 1, 2014, we may redeem some or all of the Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption.
On May 23, 2011, we commenced a Consent Solicitation that resulted in our entry into the First Supplemental Indenture. We paid a consent solicitation fee of $4.5 million. The First Supplemental Indenture amended the Indenture, among other things, to: (1) increase the amount of capital expenditures permitted to be made by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder by way of a $30 million investment in Sponsor Preferred Stock, which can be repaid over time, and (3) obligate us to make an offer to repurchase the Notes semi-annually at an offer price equal to 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest to the extent we meet certain defined financial tests and as permitted by our credit facilities.
The Notes require us to maintain certain financial covenants. Specifically, we may not permit our SEC PV-10 to consolidated leverage to be less than 1.4 to 1.0 as of the last day of each fiscal year. In addition, we and our subsidiaries are subject to various covenants, including restricted payments, incurrence of indebtedness and issuance of preferred stock, liens, dividends and other payments, merger, consolidation or sale of assets, transactions with affiliates, designation of restricted and

12



unrestricted subsidiaries, and a maximum limit for capital expenditures. Our limitation on capital expenditures was amended in conjunction with the Consent Solicitation on May 31, 2011 to 30% of consolidated earnings before interest expense, income taxes, DD&A, impairment of oil and gas properties, and exploration expense for any year thereafter. As of September 30, 2013, we were in compliance with all covenants under the Indenture. We believe anticipated capital expenditures in 2013 will exceed the amount provided for in a covenant regarding maximum capital expenditures. However, the Indenture also provides that we may use proceeds from the sale of assets for capital expenditures that we believe is not limited by the previously referenced capital expenditure covenant. In the event our interpretation of the Indenture is not upheld or if our cash proceeds from the sale of assets are not sufficient to reduce our capital expenditures to a level that makes us compliant with the maximum capital expenditure covenant, we have the option under the Indenture to redeem the Notes, beginning December 1, 2013, at a redemption price of 106.875% of par plus accrued interest and may seek to redeem the Notes; however, there can be no assurance that we will have sufficient funds to do so. We also have the option to solicit a waiver from the holders of the Notes. In these circumstances, absent a waiver and following notice to us of the default and lapse of the 30-day grace period as provided in the Indenture, the Indenture trustee or the holders of at least 25% in aggregate principal amount of the Notes would have the right to declare all the Notes to be due and payable immediately. A default under the Indenture covenant could also result in a cross-default under our credit facility.
The amounts of required principal payments based on our outstanding debt amounts as of September 30, 2013, were as follows:
Period Ending September 30,
(in thousands)
2014
$
243

2015
35,030

2016
150,023

 
185,296

Unamortized discount on 13.75% Senior Secured Notes
(686
)
Total debt
$
184,610

NOTE 8-PREFERRED UNITS AND MEMBERS' DEFICIT
In the first quarter of 2013, we entered into contribution agreements with PPVA (Equity) and Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued 50.0 million additional Class E Preferred Units (the “Class E Units”) and 3.8 million additional Class B Units to the Platinum Group for an aggregate offering price of $50.0 million. The Class E Units are recorded under "Preferred Units" and the Class B Units are included in "Members Deficit" in the consolidated balance sheets. In addition, we also agreed to issue an additional 43 million Class E Units in exchange for $30.0 million of outstanding Class D Preferred Units and $13.0 million of paid-in-kind dividends. The Class D Preferred Units were recorded under "Preferred Units" in the consolidated balance sheets. The Class E Units will receive a preferred return of 20% per annum, which will increase from and after March 25, 2014 to 36% per annum (such date as determined by our Fifth Amendment to Second Amended and Restated Limited Liability Operating Agreement). For the nine months ended September 30, 2013, we issued an additional amount of Class E Units of approximately 12.0 million as paid-in-kind dividends to the holders of Class E Units.
On February 12, 2013, we entered into an agreement with Platinum under which we agreed to issue Class B Units to Platinum in exchange for financial consulting services, including (1) analysis and assessment of our business and financial condition and compliance with financial covenants in our Credit Facility, (2) discussion with us and senior bank lenders regarding capital contributions and divestitures of non-core assets, and (3) coordination with our attorneys, accountants, and other professionals. On February 12, 2013, we issued 1,131,458.5 Class B Units to PPVA Black Elk (Equity) LLC, an affiliate of Platinum, pursuant to such agreement.
On February 12, 2013, we entered into the Fourth Amendment to the Second Amended and Restated Limited Liability Operating Agreement of the Company (the “Fourth Amendment”). The Fourth Amendment amended the Company’s operating agreement to effectuate a 10,000 to 1 unit split for each of the Class A Units, Class B Units and Class C Units.
NOTE 9—COMMITMENTS AND CONTINGENCIES
General
Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessment of the property would be necessary to adequately determine remediation costs, if any. Management does not consider the amounts that would result from any environmental site assessments to be significant to the

13



consolidated financial position or results of our operations. Accordingly, no provision for potential remediation costs is reflected in the accompanying consolidated financial statements.
We are subject to claims and lawsuits that arise primarily in the ordinary course of business. It is the opinion of management that the disposition or ultimate resolution of such claims and lawsuits will not have a material adverse effect on our consolidated financial position or results of operations.
For each of the following proceedings, we are currently evaluating the plaintiff’s claims and determining appropriate courses of response with the aid of outside legal counsel and insurance defense counsel. These proceedings are at a preliminary stage; accordingly, we currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the proceedings. Some or all of the costs of defense and liability (if any) may be covered under our Commercial General Liability insurance policy. We intend to vigorously defend ourselves in these proceedings. We are currently in the early stages of litigation for each proceeding and are therefore unable to determine whether these proceedings would have a material adverse effect on our financial position, results of operations or cash flows.
West Delta 32
On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform (the “West Delta 32 Incident”). The investigation in regards to the West Delta 32 Incident has been concluded by BSEE. On November 4, 2013, BSEE issued its investigation report (the “BSEE Panel Report 2013-002”) on the West Delta 32 Incident. The report recommends that contractors Wood Group Production Service Network, Grand Isle Shipyard, and Compass Engineering Consultants, as well as Black Elk Energy be issued the following types of Incidents of Non-Compliance: G-110, G-112, G-116, G-303, G-310, G-311, G-312 and E-100. The report also recommends that contractor Wood Group Production Service Network and Black Elk Energy be issued the additional following types of Incidents of Non-Compliance: G-309 and G-317. The report states that BSEE will issue Incidents of Non-Compliance based upon evidence contained in the report and/or other relevant evidence. No Incidents of Non-Compliance have been issued yet, and Black Elk Energy has and will continue to fully cooperate with BSEE. Black Elk Energy will be carefully reviewing the BSEE Panel Report 2013-002 over the coming weeks.
At BSEE’s direction, we engaged an independent third-party auditor to audit our SEMS program. BSEE participated in the audit and after reviewing the results, it issued a letter to BEEOO stating that “BEEOO’s SEMS meets the intent of BSEE regulations and policies, provided that the Corrective Action Plan (“CAP”) is implemented in accordance with BEEOO’s SEMS Audit Report. We are currently providing regular updates on our CAP progress.
In August 2013, ABSG Consulting (“ABSG”), a third party investigator, concluded that on the day of the West Delta 32 Incident contractors were welding a flange on open piping leading to an oil tank that contained flammable vapors. The piping had not been isolated and made safe for welding activities as required by Black Elk Energy safe work practices. The ABSG report further found that flammable vapors in the piping ignited, and within seconds reached the three oil tanks. The welding work was performed under contract by Grand Isle Shipyard. At the time of the incident, the platform production was shut in and no oil was flowing to or through the platform.
On October 15, 2013, the Department of Justice, U.S. Attorney’s Office issued a subpoena pertaining to all physical evidence collected and maintained by BEEOO and ABSG Consulting as part of the investigation of the West Delta Incident.
As of November 12, 2013, several civil lawsuits have been filed as a result of the West Delta 32 Incident. The courts held a status conference ordering procedural matters to be filed on the court’s docket. All civil cases filed both in Texas and Louisiana as a result of the West Delta 32 Incident are being defended by insurance defense counsel. We believe we have strong defenses and cross-claims and intend to defend ourselves vigorously.
On January 8, 2013, five investors in Black Elk Energy, LLC (“BEE”) filed a purported derivative action on behalf of BEE in the 164th Judicial District of Harris County, Texas against our President and CEO, John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. The lawsuit originally alleged that the defendants improperly diluted BEE’s percentage ownership in our company and that the defendants’ alleged gross mismanagement harmed BEE by allegedly causing a credit rating downgrade and a prospective buyer to reduce an alleged offer price for our company. The plaintiffs seek an unspecified amount of damages on behalf of BEE in connection with these claims. On July 26, 2013, in response to a motion to dismiss by PPVA Black Elk (Equity) LLC and its affiliated entities, the court dismissed all claims against all defendants. The claims were dismissed with prejudice to re-filing in Texas.
In the previously reported investor plaintiff civil matter, the same plaintiffs filed a Temporary Restraining Order and Preliminary Injunction in the Supreme Court of the State of New York, County of New York, restraining BEEOO from dispersing any proceeds from the sale of 43 oil and gas offshore fields being marketed at an oil and gas clearing house until

14



27.01% of the sale proceeds are placed in an escrow account during the pendency of the litigation. The Judge dismissed the Temporary Restraining Order and set a hearing for the Motion for the Injunction. The court heard oral arguments on the preliminary injunction motion on October 31, 2013 and reserved decision; a ruling is expected later this month. The Company intends to file a motion to dismiss the complaint in its entirety for failure to state a cause of action and based on documentary evidence that refutes the claims.
On April 29, 2013, Grand Isle Shipyards, Inc. (“GIS”) sued BEEOO, Enviro Tech Systems, LLC, Wood Group USA, Inc., and Compass Engineering & Consultants, LLC in the United States District Court for the Eastern District of Louisiana for damages it alleged incurred in connection with the West Delta 32 Incident. GIS specifically sought damages for loss of property and equipment, expenses in the form of indemnity and medical benefits paid to or on behalf of its employees, and for unpaid invoices in connection with the work it performed at West Delta 32. Upon motion by BEEOO, however, the court dismissed GIS’ lawsuit and ordered GIS and BEEOO to first attempt to resolve their claims through mediation, and if that is unsuccessful, then through binding arbitration, pursuant to and in accordance with the MSA. The mediation is scheduled on November 12, 2013. If that is unsuccessful, then the arbitration process will proceed.
Operating Leases
We lease office space and certain equipment under non-cancelable operating lease agreements that expire on various dates through 2020.
During 2012, we entered into two drilling unit contracts. One of the contracts was amended in June 2013 and was extended an additional 180 days to begin in January 2014. The second contract was for the duration of one drill well and was extended to include one additional drill well, which has now been completed. Additionally, we purchased leasehold in South Texas and drilled and completed one well in the third quarter of 2013.
Approximate future minimum lease payments for operating leases at September 30, 2013 were as follows:
Period Ending September 30,
(in thousands)
2014
$
31,860

2015
2,201

2016
2,029

2017
1,740

2018
1,577

Thereafter
3,476

 
$
42,883

Escrow Accounts
Pursuant to the purchase agreement from W&T Offshore, Inc. (the “W&T Acquisition”), we are required to fund two escrow accounts (the “W&T Escrow Accounts”), relating to the operating and non-operating properties that were acquired in maximum aggregate amount of $63.8 million ($32.6 million operated and $31.2 million non-operated) for future P&A costs that may be incurred on such properties. As of November 2010, we fully funded the operating escrow account in the amount of $32.6 million and the payment schedule for the Non-Operated Properties Escrow Account was amended and commenced on December 2011. As of September 30, 2013, we have funded $16.4 million into the non-operating escrow account, leaving $14.8 million to be funded through May 1, 2017.
The obligations under the W&T Escrow Accounts are fully guaranteed by an affiliate of Platinum. W&T Offshore Inc. (“W&T”) has a first lien on the entirety of the W&T Escrow Accounts, and BP Corporation North America Inc. and Platinum are pari passu second lien holders. Once P&A obligations with respect to the interest in properties acquired from the W&T Acquisition have been fully satisfied, the lien on the W&T Escrow Accounts will be automatically extinguished. W&T also has a second priority lien with respect to the interest in properties acquired from the W&T Acquisition (with Platinum and BNP Paribas sharing a first priority lien), which lien will be released once the W&T Escrow Accounts have been fully funded. On December 19, 2012, we entered into a Third Amendment to Purchase and Sale Agreement (the “Third Amendment”) with W&T. Pursuant to the Third Amendment, we caused performance bonds (the “ARGO Bonds”) in an aggregate amount of $32.6 million to be issued by Argonaut Insurance Company to W&T to guaranty our performance of certain plugging and abandonment obligations. Upon receipt of the ARGO Bonds, W&T (i) released its rights to any money held in an escrow account established to secure our performance of certain plugging and abandonment obligations with respect to the Operated Properties Escrow Account, (ii) released the security interest and deposit account control agreement formerly securing its rights in the Operated Properties Escrow Account and (iii) authorized the escrow agent to release such funds from the Operated Properties Escrow Account to or at our direction. In addition, we and W&T agreed that until the funding of an escrow account

15



established to our performance of certain plugging and abandonment obligations with respect to certain non-operated properties is complete, we may not obtain reductions of the ARGO Bonds under any circumstances without W&T’s consent.
Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the properties that were acquired, of $13.1 million to be used for future P&A costs that may be incurred on such properties. As of September 30, 2013, we have funded $11.3 million, leaving $1.8 million to be funded through February 2014.
In regards to the Merit Acquisition, we are required to establish an escrow account to secure the performance of our P&A obligations and other indemnity obligations with respect to P&A and/or decommissioning of the acquired wells and facilities. We paid $33 million in surety bonds at closing and are required to, over time, deposit in the escrow account an amount equal to $60 million, which is to be paid in 30 equal monthly installments payable on the first day of each month commencing on June 1, 2011. As of September 30, 2013, we have funded $56.0 million, leaving $4.0 million to be funded through November 2013.
NOTE 10—GAIN ON INVOLUNTARY CONVERSION
High Island 443 A-2
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, BSEE advised us to plug and abandon the well. We have well control insurance and pursued reimbursement for this incident. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drilling are also insurance recoverable.
The claim was approved and paid by insurance underwriters. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of September 30, 2013, we recorded a receivable of $0.3 million for additional reimbursement and received these final funds in October 2013. The claim has been finalized. We received a total of approximately $24.1 million, net of the deductible, in cash for the claim during 2013.
NOTE 11—RELATED PARTY TRANSACTIONS
We pay for certain operating and general and administration expenses on behalf of Black Elk Energy, LLC. At both September 30, 2013 and December 31, 2012, we had receivables from Black Elk Energy, LLC in the amount of $23,430.
On August 30, 2013, we consented to the assignment by Capital One Bank, N.A. and the other lenders of all of their rights and obligations under our Credit Facility to White Elk LLC, as Administrative Agent and Lender, and Resource Value Group LLC, as Lender. Resource Value Group LLC is affiliated with Platinum. As part of this transaction, we paid a required $0.3 million purchase fee on behalf of Platinum pursuant to the Loan Purchase Agreement.
During 2011, we entered into a contribution agreement with Platinum. We also entered into additional contributions with (PPVA (Equity)) and the Platinum Group in 2013. See Note 8.
On May 28, 2013, FWS entered into an equipment lease agreement with Pea and Eigh Company, LLC (“Pea and Eigh”), a related party of Platinum. The lease began on July 1, 2013 and is payable in monthly installments of approximately $35,000, maturing on December 31, 2013, with an option to purchase the equipment for $1.5 million. As of September 30, 2013, we have not purchased all of the equipment. We currently have restricted cash of $0.6 million for the additional equipment to be purchased as well as advances due to Pea and Eigh, which is included in “Accounts payable and accrued expenses”.
In October 2010, Freedom Logistics LLC (“Freedom”) was formed by Platinum, our majority equity holder, and Freedom HHC Management, LLC, the members of which are Messrs. John Hoffman (our President and Chief Executive Officer) and David Cantu (a former employee), for the purpose of holding certain aircraft equipment, including two helicopters. On October 8, 2010, we guaranteed the loan that Freedom used to purchase two helicopters in the aggregate principal amount of $3.2 million. The loan was paid off in December 2012 in connection with the sale of Freedom. Before the sale, Freedom provided us with aircraft services, which were prepaid on a monthly basis. As of December 31, 2012, we had a receivable of $0.3 million from Freedom. The receivable was paid on February 26, 2013.

16



NOTE 12—SUBSEQUENT EVENTS
Option to Purchase Golden Gate Oil. On November 14, 2013, we entered into a Purchase Option Agreement with the owners of Golden Gate Oil LLC pursuant to which we have the option to purchase 100% of the equity of Golden Gate for an aggregate purchase price equal to $60 million plus the amount of any advances made to Golden Gate by its members after October 29, 2013 plus the principal, interest and fees outstanding under certain debt of Golden Gate. Golden Gate and its principal owner are affiliated with Platinum. 
The Golden Gate Oil Project is located in the Santa Maria Oil Basin, Santa Barbara, California. The Project is an in-fill horizontal opportunity, targeting the highly fractured Monterrey Shale oil reservoir.
Letter of Credit Facility Amendment. On November 14, 2013, we entered into the Waiver and Tenth Amendment on our Letter of Credit Facility to (1) obtain waivers related to our financial covenants for the third quarter of 2013, (2) cap the outstanding principal balance under the Letter of Credit Facility at approximately $66.6 million, (3) no longer issue or renew existing Letters of Credit and (4) remove the financial covenant requirements and the restriction of asset sales.



17



CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this “Form 10-Q”) contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements may include statements that relate to, among other things, our:
Financial data, including production, costs, revenues and operating income;
Future financial and operating performance and results;
Business strategy and budgets;
Market prices;
Expected plugging and abandonment obligations and other expected asset retirement obligations;
Technology;
Financial strategy;
Amount, nature and timing of capital expenditures;
Drilling of wells and the anticipated results thereof;
Oil and natural gas reserves;
Timing and amount of future production of oil and natural gas;
Competition and government regulations;
Operating costs and other expenses;
Cash flow and anticipated liquidity;
Prospect development;
Property acquisitions and sales; and
Plans, forecasts, objectives, expectations and intentions.
These forward-looking statements are based on our current expectations and assumptions about future events and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisition. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are described in “Item 1A. Risk Factors” in this Form 10-Q and our 2012 Form 10-K.
These factors include risks 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;
Ability to post additional collateral as required by surety companies;
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;

18



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 drilling 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 current litigation matters as a result of the explosion and fire on the West Delta 32-E Platform and other 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;
Possible referral to the Bureau of Ocean Energy Management to revoke our status as an operator on all of our existing facilities pursuant to a letter received from BSEE on November 21, 2012; and
Worldwide political and economic conditions.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this Form 10-Q. We undertake no responsibility to publicly release the results of any revisions of our forward-looking statements after the date they are made.
Should one or more of the risks or uncertainties described in “Item 1A. Risk Factors” in this Form 10-Q and our 2012 Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statement.
All forward-looking statements, express or implied, included in this Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as required by law, we undertake no obligations to update, revise or release any revisions to any forward-looking statements to reflect events or circumstances occurring after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factors, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Form 10-Q. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in this Form 10-Q, particularly in “Item 1A. Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Overview
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 a continual effort 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. As of September 30, 2013, we held an aggregate net interest in approximately 490,370 gross (239,190 net) acres under lease and had an interest in 1,059 gross wells, 268 of which are producing.
We have financed our acquisitions to date through a combination of cash flows provided by operating activities, borrowings under lines of credit and the Notes, and capital contributions from our members. Our use of capital for acquisitions, exploitation and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, our willingness to acquire non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.
Black Elk Energy Offshore Operations, LLC and Black Elk Energy Land Operations, LLC were formed on November 20, 2007 as operating subsidiaries of Black Elk Energy, LLC. Black Elk Energy, LLC subsequently assigned its interests in Black Elk Energy Land Operations, LLC to Black Elk Energy Offshore Operations, LLC. Black Elk Energy Offshore Operations, LLC currently has three wholly owned domestic subsidiaries: (i) Black Elk Energy Land Operations, LLC, which is a guarantor under our Indenture, (ii) Black Elk Energy Finance Corp., which is the co-issuer of the Notes and (iii) Freedom Well Services, LLC. Neither Black Elk Energy Land Operations, LLC nor Black Elk Energy Finance Corp has any material assets or operations. Black Elk Energy, LLC owns a minority interest in Black Elk Energy Offshore Operations, LLC.
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.
We have historically grown our business through third-party acquisitions, including the acquisition of our first field, South Timbalier 8, in 2008, which was followed by an additional field acquisition, West Cameron 66, the W&T Acquisition in 2009, the Chroma and Nippon Acquisitions in 2010 and the Maritech and Merit Acquisitions in 2011.
Our revenue, profitability and future growth rate depend significantly on factors beyond our control, such as economic, political and regulatory developments, and environmental hazards, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil

20



or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since our inception, commodity prices have experienced significant fluctuations.
From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three and nine months ended September 30, 2013 and 2012 are shown in the table below.
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2013
 
2012
 
2013
 
2012
Oil:
 
 
 
 
 
 
 
Average price before effects of hedges ($/Bbl)(1)
$
110.41

 
$
102.92

 
$
108.24

 
$
107.93

Average price after effects of hedges ($/Bbl)
102.01

 
103.06

 
103.41

 
105.99

Average price differentials(2)
4.59

 
10.76

 
10.07

 
11.81

 
 
 
 
 
 
 
 
Gas:
 
 
 
 
 
 
 
Average price before effects of hedges ($/Mcf)(1)
$
3.74

 
$
3.06

 
$
3.85

 
$
2.63

Average price after effects of hedges ($/Mcf)
4.07

 
3.80

 
4.18

 
3.64

Average price differentials(2)
0.19

 
0.18

 
0.16

 
0.09

(1)
Realized oil and natural gas prices do not include the effect of realized derivative contract settlements.
(2)
Price differential compares realized oil and natural gas prices, without giving effect to realized derivative contract settlements, to West Texas Intermediate crude index prices and Henry Hub natural gas prices, respectively.
Oil and natural gas prices remain unstable and we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.
In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to continue entering into such transactions in the future to reduce the effect of oil and natural gas price volatility on our cash flows. Currently, our risk management program is designed to hedge a significant portion of our production to assure adequate cash flow to meet our obligations. If the global economic instability continues, commodity prices may be depressed for an extended period of time, which could alter our development plans and adversely affect our growth strategy and our ability to access additional funding in the capital markets.
The primary factors affecting our production levels are capital availability, the success of our drilling program and our portfolio of well work projects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves and enhancing our current asset base. Our future growth will depend on our ability to continue to add reserves in excess of production and to bring back to production or increase production on wellbores that are currently not productive or not being optimized. Our ability to add reserves through drilling and well work projects is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.
We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.
Recent Events
Potential Sale of Class B Units
On September 16, 2013, we entered into a Subscription Agreement with Asiasons Capital Limited (“Asiasons”) for the sale of 9,960,159 of our Class B Units for an aggregate purchase price of approximately US$50 million (based on a fixed price for Asiasons ordinary shares of 1.1948 Singapore Dollars and a fixed exchange rate of one U.S. Dollar to 1.27 Singapore

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Dollars). The Subscription Agreement provides that Asiasons will pay for the Class B Units by issuing 53,146,970 ordinary shares in Asiasons to us and will also issue an aggregate of 3,482,386 ordinary shares to Jett Capital Advisors LLC as a broker’s fee in connection with the transaction. The ordinary shares of Asiasons are listed on the Singapore Exchange Securities Trading Limited (SGX Symbol: 5ET).
The issuance of the Class B Units and the closing of the transaction are subject to customary closing conditions, including satisfactory completion by us and by Asiasons of financial, legal and operational due diligence on the other party, board approvals, accuracy of representations and warranties, and listing approval of the ordinary shares on the Singapore Exchange.
We have been informed that the Singapore Exchange has notified Asiasons that it does not have sufficient authority to issue the ordinary shares to us as contemplated by the Subscription Agreement. The Subscription Agreement has not been terminated, but the proposed sale of Class B Units on the terms set forth in the Subscription Agreement is unlikely to occur. We are engaged in discussions with Asiasons to determine whether the parties can reach agreement on the terms of a new investment.
Safety and Environmental Management Systems (“SEMS”) Audit
On January 17, 2013, we commenced a Bureau of Safety and Environmental Enforcement (“BSEE”) directed Independent Third Party SEMS Audit. The audit was conducted by M&H Energy Services (“M&H”) in three phases: documentation, implementation and offshore facilities. During the offshore phase, 19 platforms were audited for SEMS compliance. BSEE participated as observers in portions of each phase.
Phase I started with a request from M&H to provide SEMS Program Manual and all documents incorporated by reference. These documents were reviewed for compliance with the requirements of 30 CFR Part 250 Subpart S and API RP 75 (incorporated by reference). Phase 2 kicked off on February 13, 2013 with a review of preliminary findings from Phase 1 and an analysis of SEMS records and documentation to determine how effectively the SEMS was implemented. The Phase 3 Offshore Audit started on March 4, 2013 and covered 19 platforms across our Gulf of Mexico asset areas (East, Central, and West). The final audit phase was completed on March 13, 2013. The Audit Closeout Meeting occurred on March 25, 2013 on schedule with the plan submitted to BSEE. We submitted the Final Audit Report to BSEE on April 10, 2013. The Corrective Action Plan (“CAP”) was submitted to BSEE on April 11, 2013. We received a letter from BSEE on April 24, 2013 stating that the review was complete and that our SEMS meets the intent of the regulations and policies provided that the CAP is implemented in accordance with the SEMS Audit Report. On September 27, 2013 Black Elk advised BSEE that our SEMS CAP was complete.
Performance Improvement Plan (“PIP”)
On November 21, 2012, BSEE sent us a letter requiring us to take certain actions and to improve our performance. The letter made reference to, among other things, the explosion and fire that occurred on our West Delta 32-E platform on November 16, 2012, (the “November 16, 2012 Incident”). BSEE stated in the letter that if we did not improve our performance, we would be subject to additional enforcement action up to and including possible referral to the Bureau of Ocean Energy Management ("BOEM") to revoke our status as an operator on all of our existing facilities. We have undertaken the actions BSEE required of us in the November 21 letter and have been regularly reporting our progress on those required improvements to BSEE. We have submitted a PIP to BSEE that identifies corrective action items to improve safety performance in offshore operations. The primary components of the PIP address:
Independent Third-Party SEMS Audit
Enhanced oversight of work on our operated platforms
Hazard Recognition
Compliance
Reduction of Incidents of Non-Conformance (INCs)
Stop Work Authority

In a meeting held at the BSEE Regional Office on October 30, 2013, BEEOO shared with BSEE representatives that implementation of corrective actions (18 elements and 58 tasks) associated with the PIP has been 100% completed. Other essential work control processes such as our Project Execution Plans and Contractor Bridging Agreements have been improved to provide better guidelines and procedures for hazard assessment and work controls. Training in Hazard Recognition, National Pollutant Discharge Elimination System ("NPDES"), Job Safety Analysis ("JSA") and Stop Work Authority ("SWA") will be ongoing and has been incorporated into our training matrix.

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Based on the receipt of requested work and operation permits along with our interactions with BSEE and our corrective actions discussed above, we believe that we have improved our safety and compliance performance.
High Island 443 A-2
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 have well control insurance and pursued reimbursement for this incident and the claim was approved. Additionally, once the High Island 443 A-2 ST well was plugged, we started operations to sidetrack the High Island 443 A-5 well on the same platform. The costs associated with the High Island 443 A-5 drill are also insurance recoverable. We recorded a receivable of $3.1 million for reimbursement, after a deductible of $0.5 million, under our insurance policy at December 31, 2012 and received the funds during the first quarter of 2013. As of September 30, 2013, we recorded a receivable of $0.3 million for reimbursement and received these funds in October 2013. The claim has been finalized. We received a total of approximately $24.1 million, net of the deductible, in cash for the claim.
Capital Contributions