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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012
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 no. 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. x Yes ¨ No
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 x No
(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 Website, 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). x Yes ¨ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ¨ | Accelerated filer | ¨ | |||
Non-accelerated filer | 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 Act). ¨ Yes x No
As of June 29, 2012, the registrant’s membership interests are currently not listed on an exchange and, therefore, the aggregate market value of the registrant’s membership interests held by non-affiliates on such date cannot be reasonably determined.
As of April 10, 2013, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 95,550,693.34 Class E Units issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None.
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC’S
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2012
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this “Form 10-K”) 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-K, 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-K, 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 acquisitions. 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 those described in “Item 1A. Risk Factors.”
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this Form 10-K. 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 this 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.
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All forward-looking statements, expressed or implied, included in this Form 10-K 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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Except as otherwise indicated or required by the context, references in this Form 10-K to: (1) “we,” “us,” “our,” “Parent” or “Black Elk” refer to the combined business of Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries.
Item 1. | Business |
Overview
We are an oil and natural gas company headquartered in Houston, Texas with substantially all of our producing assets located offshore in U.S. federal and Louisiana and Texas state waters in the Gulf of Mexico. We were formed in November 2007 as a limited liability company to acquire, exploit and develop oil and natural gas properties in our area of focus from oil and gas companies that have determined that such assets are noncore for their purposes and desire to remove them from their producing property portfolio or deemphasize their offshore operations. In addition to our acquisition strategy, we continue to grow organically through the exploitation and development of our existing field inventory by the use of drilling, workover, recompletion and other lower-risk development projects to increase reserves and production.
As of December 31, 2012, our leasehold position encompassed approximately 542,500 gross (270,600 net) acres, 1,109 gross (569 net) wells and 233 production platforms. As of December 31, 2012, we had estimated total proved oil, natural gas and NGL reserves of 40.3 MMBoe (48% oil) with a PV-10 value of $1,058 million based on the reserve report as of December 31, 2012 (“NSAI Report”) of Netherland, Sewell & Associates, Inc., independent petroleum engineers (“NSAI”), using U.S. Securities and Exchange Commission (“SEC”) pricing based on the average price as of the first day of each of the twelve months ended December 31, 2012. For 2012, our net daily production averaged approximately 14,429 Boepd.
On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana (the “West Delta 32 Incident”). At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform. Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. For additional information, please see “Risk Factors” under Item 1A of this Form 10-K and “Legal Proceedings” under Item 3 of this Form 10-K.
Our Acquisition History
In 2008, we acquired our first field, the South Timbalier 8, located in Louisiana state waters in the Gulf of Mexico. This acquisition was followed by an additional field acquisition in U.S. federal waters in the Gulf of Mexico, the West Cameron 66.
On October 29, 2009, we purchased interests in approximately 35 fields and 350 wells primarily located in U.S. federal waters of the outer continental shelf of the Gulf of Mexico (the “Outer Continental Shelf” or “OCS”) encompassing approximately 195,000 gross (71,000 net) acres (the “W&T Properties”) from W&T Offshore, Inc. (“W&T”). The W&T Properties also included related leases, platforms, equipment and other associated assets. The purchase price was $30 million plus the assumption of approximately $73.3 million of undiscounted asset retirement obligations related to plugging and abandonment (“P&A”) obligations associated with the W&T Properties, subject to customary effective-date adjustments and closing adjustments. As of December 31, 2012, the W&T Properties had a PV-10 value of $234.3 million and estimated proved reserves of 9.8 MMBoe, which accounted for approximately 22% of our total PV-10 value and approximately 24% of our total proved reserves at such time.
During the first quarter of 2010, we acquired six fields and added interests in an additional 40 wells spanning approximately 13,900 gross (6,400 net) acres, primarily located within Texas state waters in the Gulf of Mexico from Chroma Oil and Gas, LP. On September 30, 2010, we acquired interests in 27 properties across approximately 195,944 gross (103,130 net) acres (the “Nippon Properties”) in the Gulf of Mexico from Nippon Oil Exploration U.S.A. (“Nippon”). The Nippon Properties included interests in 90 producing wells, 223 wellbores, 41 platforms and 19 producing fields. The purchase price was $5 million plus the assumption of approximately $95.6 million of undiscounted asset retirement obligations related to P&A obligations associated with the Nippon Properties, subject to customary effective-date adjustments and closing adjustments. As of December 31, 2012, the Nippon Properties had a PV-10 value of $190.0 million and estimated proved reserves of 9.9 MMBoe, which accounted for approximately 18% of our total PV-10 value and approximately 24% of our total proved reserves at such time.
In February 2011, we acquired additional properties (the “Maritech Properties”) in the Gulf of Mexico, strategically located among our existing assets in federal waters, from Maritech Resources Incorporated (“Maritech”). The Maritech Properties consisted of eight fields and interests in 105 gross (43 net) wells and approximately 45,500 gross (22,200 net) acres.
On May 31, 2011, we acquired certain interests in various properties across approximately 250,126 gross (127,894 net) acres (the “Merit Properties”) in the Gulf of Mexico in Texas and federal waters from Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P. (the “Merit Entities”). In
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connection with the acquired Merit Properties, we entered into a contribution agreement with Platinum Partners Value Arbitrage Fund L.P., and/or certain of its affiliates (collectively “Platinum”), whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Preferred Units (the “Class D Units”). As of December 31, 2012, the Merit Properties had a PV-10 value of $337.0 million and estimated proved reserves of 15.6 MMBoe, which accounted for approximately 32% of our total PV-10 value and approximately 39% of our total proved reserves at such time.
We have financed our acquisitions to date through a combination of cash flows provided by operating activities, borrowings under lines of credit and 13.75% Senior Secured Notes due 2015 (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-operating property interests at what we believe to be attractive rates of return either because they provided footholds 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.
Our Business Strategies
Our goal is to increase unit holder value by increasing our reserves production and cash flow at an attractive return on invested capital. We seek to achieve this goal through the following strategies:
• | Conduct all operations safely using industry best practices, be good stewards of the environment and strive towards being compliant with all regulations. We intend to continue to use experts to ensure all work and operations are continuously conducted in a compliant manner as dictated by our policies and procedures and all applicable regulations. Our safety and environmental management system (“SEMS”) will have continuous learning at its core and seek to be highly effective in every aspect of our work. |
• | Continue to pursue strategic acquisitions. We intend to continue to selectively acquire properties in areas that meet certain investment criteria without unintended environmental impact. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce with additional attention and capital resources. We believe that our strategy provides assets to develop and produce with minimal risk, cost or time of traditional exploration. We stringently assess technical information to protect against potential risks as part of our acquisition strategy. Our approach extends the economic life of fields and delivers a greater volume of reserves. We believe strategic opportunities will continue to be available and will generate attractive returns. |
• | Enhance returns by focusing on operational and cost efficiencies. 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. 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. |
• | Focus primarily on the Gulf of Mexico. Our experience in the Gulf of Mexico has led us to focus our efforts in that particular region where we are familiar with the regulatory, geological and operational characteristics of this environment. This geographic focus enables us to minimize logistical costs and required staff. |
• | Expand geographic focus to create a balanced portfolio of onshore and offshore reserves. Our management team has a wide experience base. We intend to leverage that experience and expertise to enhance our reserve and cash flow base while extending reserves to a production ratio above six by continuing to acquire under-capitalized Gulf of Mexico assets and making an accretive acquisition in a conventional under-capitalized onshore basin. |
• | Manage our exposure to commodity price risk. We intend to continue to manage our exposure to commodity price risk in the near term while remaining opportunistic over the long term. As part of our risk management program, we hedge a portion of our anticipated oil and natural gas production to reduce our exposure to fluctuations in oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decisions on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. |
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Our Competitive Strengths
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
• | Acquisition execution capabilities. We have a proven track record of identifying, evaluating and executing the purchase of oil and natural gas assets. Since we began operations in 2008, we have completed seven acquisitions which have created significant value relative to the capital employed. We believe that our expertise related to the legal, financial and regulatory aspects of acquisitions allows us to quickly and successfully close transactions. |
• | Experienced management team. 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 operations. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of resource conversion opportunities. In the past year, we have developed a drilling team that provides a significant competitive advantage through its experience and knowledge of the Gulf of Mexico. |
• | Efficient management of our P&A activities. We consider the evaluation and execution of P&A activities to be one of our core competencies. We have an experienced internal team with a dedicated focus on managing our P&A activities and estimating P&A costs associated with acquisition opportunities. Our ongoing effort to manage our P&A liabilities by proactively removing inactive structures, wellbores and pipelines meaningfully reduces our operating expenses, maintenance expenses, insurance premiums and overall risk exposure. We also have an affiliation with a well service and P&A company, which should provide us access to reliable equipment and workers on our decks. |
• | Large inventory of opportunities. We have a large inventory of behind pipe, proved developed non-producing reserves as well as low-risk drilling locations classified as proved undeveloped (“PUD”) reserves. Probable and possible reserve classes also hold the potential to increase our opportunity set once technically fully evaluated. |
• | Large acreage position. We hold interest in 542,500 gross (270,600 net) acres in the Gulf of Mexico, which will allow us to pursue the deep and ultra-deep potential that exists under current producing horizons. |
• | Expand the successfully new application of horizontal wells. Our producing leases are held by production, which allows for study and application of the successful horizontal well technology. This well design in highly permeable Gulf sands has the potential to enhance our production rates on newly drilled wells. Our vast lease position, well control and seismic studies will optimally allow us to leverage this technology and design to further enhance deliverability of our drilling capital. |
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Our Operations
Estimated Proved Reserves
The following table sets forth our estimated net proved reserves and the present value of such future cash flows as of December 31, 2012, 2011 and 2010. The Standardized Measure and PV-10 values shown in the table below are not intended to represent the current market value of the estimated oil and natural gas reserves we own.
At December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Reserve Data(1): | ||||||||||||
Estimated net proved reserves: | ||||||||||||
Oil (MBbls) | 19,268 | 18,089 | 10,257 | |||||||||
Natural gas (MMcf) | 113,093 | 150,393 | 68,598 | |||||||||
NGL (MBbls) | 2,222 | 2,034 | — | |||||||||
Total estimated net proved reserves (MBoe) | 40,339 | 45,189 | 21,690 | |||||||||
Estimated net proved developed reserves: | ||||||||||||
Oil (MBbls) | 10,610 | 10,538 | 7,897 | |||||||||
Natural gas (MMcf) | 73,001 | 83,324 | 55,008 | |||||||||
NGL (MBbls) | 1,651 | 1,291 | — | |||||||||
Total estimated net proved developed reserves (MBoe) | 24,428 | 25,716 | 17,065 | |||||||||
Percent developed | 61 | % | 57 | % | 79 | % | ||||||
Estimated net proved undeveloped reserves: | ||||||||||||
Oil (MBbls) | 8,658 | 7,551 | 2,360 | |||||||||
Natural gas (MMcf) | 40,092 | 67,069 | 13,590 | |||||||||
NGL (MBbls) | 571 | 743 | — | |||||||||
Total estimated net proved undeveloped reserves (MBoe) | 15,911 | 19,472 | 4,625 | |||||||||
PV-10 (in thousands) (2) | $ | 1,057,793 | $ | 1,061,408 | $ | 392,189 | ||||||
Standardized measure (in thousands) (2) | 1,057,793 | 1,061,408 | 392,189 |
(1) | Our estimated net proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $91.21 per Bbl for oil volumes and $2.76 per Mcf for gas volumes for the year ended December 31, 2012 and $92.71 per Bbl for oil volumes and $4.12 per Mcf for gas volumes for the year ended December 31, 2011. The unweighted arithmetic average first-day-of-the-month price of oil for the 12 months ended December 31, 2010 was $75.96 per Bbl. Gas prices for the year ended December 31, 2010 were based on average adjusted product prices weighted by production for the proved reserves. The range of gas prices for 2010 was $4.24 to $4.38 per Mcf. For oil volumes, the average West Texas Intermediate price is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the average regional spot prices are adjusted by field for energy content, transportation fees and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $107.44 per Bbl of oil, $3.405 per Mcf of gas and $43.68 per Bbl of NGL. |
(2) | PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future revenues. However, our PV-10 and our Standardized Measure are equivalent because we are classified as a limited liability company not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our equity holders. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. |
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The following table sets forth the estimated future net cash flows, excluding derivatives contracts, from estimated proved reserves, PV-10 values and the expected benchmark prices used in projecting net cash flows at December 31, 2012, 2011 and 2010 (in thousands, except for the per Bbl and Mcf data).
At December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Estimated future net cash flows | $ | 1,360,339 | $ | 1,383,192 | $ | 495,211 | ||||||
Present value of future net revenues (1): | ||||||||||||
PV-10 | $ | 1,057,793 | $ | 1,061,408 | $ | 392,189 | ||||||
Standardized measure | 1,057,793 | 1,061,408 | 392,189 | |||||||||
Benchmark oil price ($/Bbl) | 91.21 | 92.71 | 75.96 |
(1) | The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $2.76/Mcf and $4.12/Mcf for gas volumes for the years ended December 31, 2012 and 2011, respectively. Gas prices for the year ended December 31, 2010 were based on average adjusted product prices weighted by production for the proved reserves. The range of gas prices for 2010 was $4.24 to $4.38 per Mcf. |
Estimated future net cash flows represent projected revenues for the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations are based on a 12 month unweighted arithmetic average of the first-day-of-the-month price for the period January through December of such year, without giving effect to derivative transactions, and are held constant throughout the life of the properties. There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.
Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. A revision of 3,678 MBoe during 2010 was mainly due to comprehensive field studies, reactivation program and improved performance of active wells, a revision of 1,770 MBoe during 2011 was primarily due to continued field studies, reactivation of inactive wells and improved performance of active wells, and a revision of (5,221) MBoe during 2012 was mainly due to dropped and revised cases as well as pricing adjustments.
Extensions, discoveries and other additions. These are additions to proved reserves that result from exploratory drilling and the acquisition of new data, including production data, 3-D seismic data and well test data.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process. NSAI, our independent petroleum engineers estimated, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC, 100% of our proved reserve information as of December 31, 2012, 2011 and 2010 included in this Form 10-K. Our internal technical persons and those at NSAI primarily responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. During the fourth quarter of each fiscal year, our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAI’s preparation of the year end reserves estimates. All field and reserve technical information, which is updated annually, is assessed for validity when NSAI holds technical meetings with our internal staff of petroleum engineers, operations and land personnel to discuss field performance and to validate future development plans. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the NSAI reserve reports are reviewed with representatives of NSAI and our internal technical staff before dissemination of the information.
Our Chief Technical Officer, Mr. Arthur Garza, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has a B.S./M.E. in Petroleum Engineering from Texas A&M University and a M.B.A. from University of Oklahoma. Mr. Garza has over 24 years of industry experience with positions of increasing responsibility. His focus has been on the exploitation of mature oil and natural gas fields, and he also has extensive waterflood and polymer flood experience. Reserves estimates are reviewed and approved by our engineering staff with final approval by our Chief Technical Officer.
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Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI employed technologies consistent with the standards established by the Society of Petroleum Engineers. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data and well test data.
Estimated Proved Undeveloped Reserves.Our proved undeveloped reserves at December 31, 2012 were 15.9 MMBoe, consisting of 9.2 MBbls of oil and NGLs and 40.1 Bcf of natural gas. At December 31, 2011, our proved undeveloped reserves were 19.5 MMBoe, consisting of 8.3 MBbls of oil and NGLs and 67.1 Bcf of natural gas. Decreases in proved undeveloped reserves in the past year were primarily due to the reclassification of several PUDs that had reached the five year period and a lower pricing environment. We incurred capital expenditure costs of $8.0 million in 2012 to develop PUDs. During the first quarter of 2012, we successfully completed the A7 well located on Grand Island 116 block and reclassified 0.31 million barrels of oil equivalent (“MMBoe”) from proved developed non-producing reserves. In 2012, we initiated the Garden Banks 602 #A-2 PUD conversion. The project is expected to be completed during the second quarter of 2013. In 2013, we expect to drill and complete eight operated wells and seven non-operated wells. All proved undeveloped reserves are scheduled to be drilled by 2017 excluding the twelve drills waiting on wellbore availability.
Developed and Undeveloped Acreage
The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2012:
Developed Acres | Undeveloped Acres | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Offshore (1) | 541,752 | 270,282 | 720 | 360 | 542,472 | 270,642 | ||||||||||||||||||
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Total | 541,752 | 270,282 | 720 | 360 | 542,472 | 270,642 | ||||||||||||||||||
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(1) | Our core areas of production in U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Vermilion 408, Eugene Island 331, South Pass 89/86, High Island A-571 and South Marsh Island 39 fields. |
The gross and net undeveloped acres as of December 31, 2012 will expire April 2016 unless production is established within the spacing units covering the acreage prior to the applicable lease expiration dates.
Drilling Activity
During the three years ended December 31, 2012, 2011 and 2010, we drilled development and exploratory wells as set forth in the table below. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.
2012 | 2011 | 2010 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Development wells: | ||||||||||||||||||||||||
Productive oil | 1 | 0.15 | — | — | 1 | 0.21 | ||||||||||||||||||
Productive natural gas | 1 | 0.13 | — | — | 2 | 0.75 | ||||||||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||||||||
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Total | 2 | 0.28 | — | — | 3 | 0.96 | ||||||||||||||||||
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2012 | 2011 | 2010 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory wells: | ||||||||||||||||||||||||
Productive oil | — | — | — | — | — | — | ||||||||||||||||||
Productive natural gas | — | — | — | — | — | — | ||||||||||||||||||
Dry | — | — | 1 | 0.10 | — | — | ||||||||||||||||||
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Total | — | — | 1 | 0.10 | — | — | ||||||||||||||||||
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At December 31, 2012, we had one well where we serve as the operator that we were in the process of making platform modifications and skidding the well from HI 443 A-2l to HI 443 A-5. Our non-operated properties had one drill well completed in 2012 and another drill well started in December 2012, which is still currently drilling. In 2013 to date, we have two drilling rigs performing sidetrack operations on our operated properties and two currently drilling on non-operated properties with another mobilizing to location. We recompleted 32 wells during 2012, 15 of which are currently producing. We plan to actively drill during 2013. Our rig activity during the remainder of 2013 will be dependent on oil and natural gas prices and, accordingly, our rig count may increase or decrease from year-end levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost.
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Capital Expenditure Budget
We have a total capital expenditure budget of $127.2 million for 2013, excluding expenditures directly related to acquisitions, which is a 175% increase over the approximately $46.3 million of capital expenditures invested during 2012. Our 2013 capital expenditure budget will be used for various projects including recompletions, development and drilling. To date, our 2013 capital budget has been funded from cash flow from operations, capital contributions and a $3.1 million partial payment of insurance reimbursement for P&A costs on the High Island 443 A-2 well (after a deductible of $0.5 million). We are currently evaluating new sources of liquidity including, but not limited to, (i) renegotiating our current revolving credit facility (ii) entering into a new revolving credit facility and (iii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. We continue to review our escrow accounts to determine if there are opportunities to replace our letters of credit, which are 100% cash-backed, with surety bonds. We believe the cash flow from operations, $50 million in capital contributions, insurance reimbursement on the P&A costs on the High Island 443 A-2 well and drilling of the replacement well, High Island 443 A-5 ST, along with new sources of liquidity described above, should be sufficient to fund our 2013 capital expenditure budget.
Our capital budget may be adjusted as business conditions warrant and the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results 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.
We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Natural Gas Hedging” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
We review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all. Additionally, the indenture (together with the amendments and supplements thereto, the “Indenture”) governing our Notes restricts the amount of capital expenditures that we may make each year to 30% of Consolidated EBITDAX (as defined in the Indenture). In addition, aggregate capital expenditures may not exceed $210.0 million.
Our Significant Oil and Natural Gas Properties
We have a geographically diverse asset portfolio in the Gulf of Mexico. Our interests are located offshore in U.S. federal and Louisiana and Texas state waters, with depths ranging from less than ten feet up to 7,036 feet. As of December 31, 2012, our leasehold position encompassed approximately 542,500 gross (270,600 net) acres, 1,109 gross (569 net) wells and 233 production platforms. As of December 31, 2012, we operated approximately 52% of the fields and 49% of the wells in our asset portfolio.
The following describes our significant properties and interests as of December 31, 2012, which at such time accounted for approximately 55% of our total PV-10 value based on the NSAI Report, and approximately 44% of our total proved reserves, totaling 17.6 MMBoe.
• | South Pass 65. We acquired the South Pass 65 field, which is located in approximately 300 feet of water in U.S. federal waters, in the Nippon Acquisition. We have a 50% net average working interest in this field and Apache Corporation serves as the operator. This field currently contains 38 producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 3.3 MMBoe. |
• | South Timbalier 317. We acquired the South Timbalier 317 field, which is located in approximately 457 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 100% net average working interest in this field and serve as the operator. This field currently contains two producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 1.8 MMBoe. |
• | Ship Shoal 176. We acquired the Ship Shoal 176 field, which is located in approximately 100 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 98% net average working interest in this field and serve as the operator. This field currently contains eleven producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 3.5 MMBoe. |
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• | Vermilion 408. We acquired the Vermilion 408 field, which is located in approximately 400 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 100% net average working interest in this field and serve as the operator. This field currently contains three producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 1.3 MMBoe. |
• | Eugene Island 331. We acquired the Eugene Island 331 field, which is located in approximately 248 feet of water in U.S. federal waters, in the Merit Acquisition. We have a 84% net average working interest in this field and serve as the operator. This field currently contains fourteen producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 2.0 MMBoe. |
• | South Pass 89/86. We acquired the South Pass 89/86 field, which is located in approximately 388 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 64% net average working interest in this field and are the operator of record. This field currently contains four producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 1.3 MMBoe. |
• | High Island A-571. We acquired the High Island A-571 field, which is located in approximately 300 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 81% net average working interest in this field and are the operator of record. This field currently contains four producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 3.2 MMBoe. |
• | South Marsh Island 39. We acquired the South Marsh Island 39 field, which is located in approximately 97 feet of water in U.S. federal waters, in the W&T Acquisition. We have a 50% net average working interest in this field and Hunt Oil serves as the operator. This field currently contains three producing wells and, as of December 31, 2012, had estimated total proved oil and natural gas reserves of 1.0 MMBoe. |
Production, Price and Cost History
Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically during this decade. However, the current economic slowdown reduced this demand during the second half of 2010 and through 2012. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. See Item 1A. “Risk Factors—If oil and natural gas prices decline, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.”
Although we are not currently experiencing any significant voluntary curtailment of our oil and natural gas production, market, economic, transportation and regulatory factors may in the future materially affect our ability to market our oil or natural gas production. See Item 1A. “Risk Factors—Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay production.”
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The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2012, 2011 and 2010. For additional information on price calculations, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations.” We do not have any fields that contain 15% or more of our total estimated proved reserves.
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Net sales volumes: | ||||||||||||
Oil (MBbl) | 1,977 | 1,991 | 857 | |||||||||
Natural gas (MMcf) | 17,884 | 18,188 | 7,997 | |||||||||
Plant products (MGal) | 13,588 | 12,257 | 5,403 | |||||||||
Oil equivalents (MBoe) | 5,281 | 5,314 | 2,319 | |||||||||
Average sales price per unit: (1) | ||||||||||||
Oil (Bbl) | $ | 110.18 | $ | 105.17 | $ | 80.97 | ||||||
Natural gas (Mcf) | $ | 3.73 | $ | 4.94 | $ | 5.44 | ||||||
Oil equivalents (Boe) | $ | 56.50 | $ | 59.30 | $ | 51.27 | ||||||
Costs and expenses per Boe: | ||||||||||||
Lease operating expenses | $ | 34.22 | $ | 29.83 | $ | 23.56 | ||||||
Depreciation, depletion, amortization, and impairment | $ | 14.84 | $ | 11.32 | $ | 15.61 | ||||||
General and administrative expenses | $ | 5.02 | $ | 4.15 | $ | 6.29 |
(1) | Average prices presented give effect to our hedging. Please see Item 7. “Management’s Discussion and Analysis of Financial Conditions and Results of Operations”—Oil and Natural Gas Hedging” for a discussion of our hedging activities. |
Net production volumes for the year ended December 31, 2012 were 5,281 MBoe, a 1% decrease from net production volumes of 5,314 MBoe for 2011. Our net production volumes decreased 33 MBoe over 2011 net production volumes mainly due to lower production in the third quarter of 2012 (196 MBoe) primarily a result of downtime for Hurricane Isaac, and lower production in the fourth quarter of 2012 (414 MBoe) as a result of downtime in fields requiring hot work, which were delayed due to the Bureau of Safety and Environmental Enforcement (“BSEE”) requirement for approval after the West Delta 32 Incident, partially offset by a full year of production of the properties acquired in the Merit Acquisition (872 MBoe). Our average oil sales prices, without the effect of realized derivatives, decreased $1.49 per Bbl to $106.60 per Bbl for the year ended December 31, 2012 from $108.09 per Bbl for the year ended December 31, 2011. Giving effect to our derivative transactions in both periods, our oil prices increased $5.01 per Bbl to $110.18 per Bbl for the year ended December 31, 2012 from $105.17 per Bbl for the year ended December 31, 2011. Our lease operating expenses increased $4.39 per Boe, or 15%, to $34.22 per Boe for the year ended December 31, 2012 from $29.83 per Boe for the year ended December 31, 2011 mainly due to a mix of increased properties and certain non-recurring costs on the newly acquired properties and expenses incurred at West Delta 32.
Net production volumes for the year ended December 31, 2011 were 5,314 MBoe, a 129% increase from net production of 2,319 MBoe for 2010. Our net production volumes increased 2,995 MBoe over 2010 net production volumes mainly due to a full year of production of the properties acquired in the Nippon Acquisition and seven months production of the properties acquired in the Merit Acquisition as well as ten months production of the properties acquired in the Maritech Acquisition. Our average oil sales prices, without the effect of realized derivatives, increased $28.00 per Bbl to $108.09 per Bbl for the year ended December 31, 2011 from $80.09 per Bbl for the year ended December 31, 2010. Giving effect to our derivative transactions in both periods, our oil prices increased $24.20 per Bbl to $105.17 per Bbl for the year ended December 31, 2011 from $80.97 per Bbl for the year ended December 31, 2010. Our lease operating expenses increased $6.27 per Boe, or 27%, to $29.83 per Boe for the year ended December 31, 2011 from $23.56 per Boe for the year ended December 31, 2010 mainly due to new offshore production.
The following table sets forth information regarding our average net daily production for the years ended December 31, 2012 and 2011:
Average Net Daily Production for the Year Ended December 31, 2012 | Average Net��Daily Production for the Year Ended December 31, 2011 | |||||||||||||||||||||||
Bbls | Mcf | Boe | Bbls | Mcf | Boe | |||||||||||||||||||
Offshore (1) | 6,286 | 48,864 | 14,429 | 6,254 | 49,831 | 14,559 |
(1) | Our core areas of production in U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Eugene Island 331, Vermilion 408, South Pass 89/86, High Island A-571 and South Marsh Island 39 fields. |
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Productive Wells
The following table presents the total gross and net productive wells by project area and by oil or gas completion as of December 31, 2012:
Oil Wells | Natural Gas Wells | Total Wells | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Offshore (1) | 172 | 62 | 154 | 72 | 326 | 134 |
(1) | Our core areas of production in the U.S. federal waters in the Gulf of Mexico are the South Pass 65, South Timbalier 317, Ship Shoal 176, Eugene Island 331, Vermilion 408, South Pass 89/86, High Island A-571 and South Marsh Island 39 fields. |
Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.
Marketing and Customers
We generally sell our natural gas and oil at the wellhead to marketing companies. All of our offshore and shallow water production is connected to a pipeline.
We have been selling to our customers set forth below since our inception and believe that we receive market rates for our natural gas and oil production from such customers. We obtain letters of credit from our customers and discuss the credit worthiness of our customers’ purchasers on an ongoing basis.
The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:
Year Ended December 31, | ||||||||||||
Customer | 2012 | 2011 | 2010 | |||||||||
Conoco Phillips Company | 3 | % | 7 | % | 14 | % | ||||||
Shell Trading (US) Company | 18 | % | 51 | % | 52 | % | ||||||
JP Morgan Ventures Energy Corporation | 41 | % | 8 | % | 0 | % |
Please read Item 1A. “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Sales to a small number of customers represent a substantial portion of our revenues. The loss of any of our major customers could significantly harm our financial condition.”
Delivery Commitments
Substantially all of our production is sold pursuant to month-to-month marketing contracts that can be terminated by either party at any time and do not contain specific volume or pricing on other than a market basis.
Competition
The oil and gas industry is highly competitive. We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of these competitors are large, well-established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, please read Item 1A, Risk Factors—Competition for oil and natural gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.”
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil
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Index to Financial Statements
and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens to secure our P&A obligations, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.
Seasonality
In the past, the demand for and price of natural gas increased during the winter months and decreased during the summer months. However, these seasonal fluctuations were somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. With the development of the shale plays, seasonality is less a factor. Oil was also impacted by generally higher prices during winter months but has more recently been affected by geopolitical events and the global recession. Seasonal weather changes have also affected our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which may require us to evacuate personnel and shut-in production until these storms subside. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying sales of our oil and natural gas.
Insurance
We maintain insurance programs to provide coverage for a high percentage of our assets in the event of physical damage and well control events. While we may not obtain insurance for some risks if we believe the cost of available insurance is excessive relative to the risks presented, we intend to continue to pursue a strong risk mitigation program by maintaining comprehensive insurance coverage related to our exposure to operational and weather related risks.
Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
Drilling and Production
Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:
• | the location of wells; |
• | the method of drilling and casing wells; |
• | the surface use and restoration of properties upon which wells are drilled; and |
• | the plugging and abandoning of wells. |
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
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In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.
If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain onsite security regulations and other appropriate permits issued by the Bureau of Land Management (the “BOEMRE”) or other appropriate federal or state agencies.
Transportation and Sales of Oil
Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act (“ICA”). The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC. Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 2.65%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows for us.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a nondiscriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. As a result, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or for new shippers. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. Nonetheless, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Transportation and Sales of Natural Gas
The transportation and sale for resale of natural gas in interstate commerce is regulated by the FERC under the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”), and regulations issued under those statutes.
The FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
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Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. To the extent that the FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by the FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.
With regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission (the “CFTC”). See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding physical natural gas transactions for each calendar year and to indicate whether they report prices. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”
The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
State Natural Gas Regulation
Various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Certain states also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations in which we can drill.
Other Federal Laws and Regulations Affecting Our Industry
Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (the “EPAct 2005”). EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction
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of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.
FERC Market Transparency Rules. On December 26, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order No. 704”). Under Order No. 704, wholesale buyers and sellers of more than 2.2 MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Federal Trade Commission (FTC) and Commodity Futures Trading Commission (CFTC) Regulations. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the CFTC to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to liquids swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to liquids purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation.
Environmental and Occupational Health and Safety Regulation
Our exploitation, development and production operations in the U.S. Gulf of Mexico are subject to various federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require us to acquire permits to conduct exploitation, drilling and production operations; restrict the amounts and types of substances that we may release into the environment or the manner in which we handle or dispose of our wastes in connection with oil and natural gas drilling and production; cause us to incur significant capital expenditures to install pollution control or safety-related equipment at our operating facilities; limit or prohibit our construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose on us specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; impose obligations on us to reclaim and abandon well sites, and expose us to substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly operational requirements or waste handling, disposal, cleanup and remediation requirements for the oil and natural gas industry could have a significant impact on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, we cannot provide any assurance that we will be able to remain in compliance in the future with respect to existing or new laws and regulations or the terms and conditions of required permits or that such future compliance will not have a material adverse effect on our business and operating results.
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The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, amended from time to time, to which our business operations are subject to and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Releases of Oil
The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening U.S. waters, including the Outer Continental Shelf or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill.
OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. The OPA also currently limits the liability of a responsible party for an offshore facility to economic damages, excluding all oil spill response costs, to $75 million, although this limit does not apply if a federal safety, construction or operating regulation was violated. Congress has, from time to time, considered adopting revisions to the OPA to make it more stringent. In the aftermath of the Deepwater Horizon incident in the U.S. Gulf of Mexico, Congress considered a variety of amendments to the OPA, including an increase in the minimum level of financial responsibility to $300 million, an elimination of all liability limitations on damages, and enhancements to safety and spill-response requirements. While the legislation failed to pass, it is possible that similar legislation could be introduced and adopted by Congress in the future. Additional state regulation in these areas is also possible.
If OPA was amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the Outer Continental Shelf or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. Any adoption of more stringent financial responsibility, safety or spill response requirements or the elimination of liability limitations under OPA would likely increase the cost of operations for our offshore activities, including insurance costs, and expose us to increased liability, which could have an adverse effect on our results of operations. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be held strictly liable for costs and damages, which could be material to our results of operations and financial position.
Water Discharges
The Federal Clean Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (“EPA”) or an analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The federal Outer Continental Shelf Lands Act, as amended (“OCSLA”), authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Included among these regulations are requirements mandating the preparation of spill contingency plans and the establishment of air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms and structures. Violations of lease conditions or regulations related to the environment issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
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Hazardous Substances and Wastes
The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as “hazardous substances.” These classes of persons, referred to as potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at onshore disposal sites owned and operated by others.
The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage and disposal of solid and hazardous waste and can require cleanup of hazardous waste disposal sites. While there exists an exclusion under RCRA from the definition of hazardous wastes for certain materials generated in the exploration, development or production of oil and natural gas, these wastes may be regulated by the EPA and state environmental agencies as non-hazardous solid wastes. Other wastes handled at exploration, development and production sites may not fall within this regulatory exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. In September 2010, a non-governmental organization filed a petition with the EPA, requesting them to reconsider the RCRA exemption for exploration, production and development wastes. To date, the EPA has not taken any action on the petition. If legislation is enacted or regulatory changes adopted that remove this RCRA exemption, it could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the U.S. Department of Interior (“DOI”), to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits or other approvals that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
Air Emissions
The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues.
Climate Change Legislation and Regulatory Initiatives
In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic changes, the EPA published its finding in December 2009 that emissions of GHGs presented an endangerment to public health and the environment. Based on these findings, the EPA has adopted rules under existing provisions of the Clean Air Act requiring a reduction in emissions of GHGs from motor vehicles and requiring certain construction and operating permit reviews for GHG emissions from certain stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG emission sources in the United States including, among others, certain onshore and offshore oil and natural gas production facilities on an annual basis.
In addition, Congress has, from time to time, actively considered legislation and almost one-half of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced
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each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.
Employee Health and Safety
Our operations are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, the OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes require that we organize and maintain information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with these applicable requirements.
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our compliance with existing requirements has not had a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2012, 2011 and 2010. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2013 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that future compliance with existing environmental laws and regulation or that the passage of new, more stringent environmental laws and regulations in the future will not have a materially adverse effect on our business activities, financial condition or results of operations.
Employees
As of December 31, 2012, we had 152 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.
Offices
We currently lease approximately 23,000 square feet of office space in Houston, Texas at 11451 Katy Freeway, Suite 500, where our principal offices are located. This lease expires on December 31, 2020. We believe that our facilities are adequate for our current operations and that additional lease space can be obtained if needed.
Available Information
We are required to file annual, quarterly and current reports and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F. Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.
We also make available on our website at www.blackelkenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website, other than the documents listed below, is not incorporated by reference into this Form 10-K.
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Item 1A. | Risk Factors |
Risks Related to the Oil and Natural Gas Industry and Our Business
We may be subject to claims and liability as a result of our ownership of the West Delta 32-E Platform, which suffered an explosion and fire in November 2012, resulting in loss of life and other injuries.
On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana. At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform. Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. An investigation by the BSEE, in coordination with the U.S. Coast Guard, is ongoing. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance, assess penalties, enjoin Black Elk from operating part or all of West Delta 32, or take other enforcement action. The United States Chemical Safety and Hazard Investigation Board has also made inquiry regarding the incident, but has not yet formally opened an investigation. Additionally, civil lawsuits relating to the explosion have been filed and are pending in both state and federal courts.
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 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 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 to BSEE our progress on those required improvements.
As more facts become known, it is possible that we may be required to recognize a liability related to the West Delta 32 Incident, and that liability could be material to our financial position, results of operations or cash flows, including, without limitation, our ability to obtain debt, equity or other financing on acceptable terms, or at all. In addition, our credit agreement contains covenants limiting our ability to incur additional debt or pledge additional assets, subject to exceptions. These limitations could adversely affect our ability to obtain additional financing for any future liabilities that may arise in connection with the West 32 Platform Incident.
We have been named as a defendant in various litigation matters as a result of the West Delta 32 Incident. The outcome of existing and future claims could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.
As of April 10, 2013, four civil lawsuits have been filed by certain investors and by or on behalf of certain injured or deceased workers against the Company, entities affiliated with PPVA Black Elk (Equity) LLC, the Company’s majority unit holder, and Iron Island Technologies. The lawsuits assert, among other things, gross mismanagement of the Company, safety violations and personal injuries and wrongful death. Generally, the plaintiffs are seeking actual damages, punitive damages, declaratory judgment and/or injunctive relief. For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal counsel.
Additional proceedings related to the West Delta 32 Incident may be filed against us. These proceedings may involve civil claims for damages or governmental investigative, regulatory or enforcement actions. The adverse resolution of any proceedings related to the West Delta 32 Incident could subject us to significant monetary damages, fines and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.
The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
We are engaged in exploration and development drilling activities, which by their nature carry a high degree of risk. These activities may be unsuccessful for many reasons. Our drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the U.S. Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.
Our business involves a variety of inherent operating risks, including:
• | fires; |
• | explosions; |
• | blow-outs and surface cratering; |
• | uncontrollable flows of gas, oil and formation water; |
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• | natural disasters, such as hurricanes and other adverse weather conditions; |
• | pipe, cement, subsea well or pipeline failures; |
• | casing collapses; |
• | mechanical difficulties, such as lost or stuck oil field drilling and service tools; |
• | abnormally pressured formations; and |
• | environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures and discharges of toxic gases or well fluids. |
If we experience any of these problems, wellbores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:
• | injury or loss of life; |
• | severe damage to and destruction of property, natural resources and equipment; |
• | pollution and other environmental damage; |
• | clean-up responsibilities; |
• | regulatory investigations and penalties; |
• | suspension of our operations; and |
• | repairs to resume operations. |
Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
By conducting operations only along the Texas and Louisiana state waters in the U.S. Gulf of Mexico and adjacent waters on and beyond the Outer Continental Shelf, our lack of diversification may:
• | subject us to numerous economic, competitive and regulatory developments, any or all of which may have a substantial adverse impact upon the particular industry in which we operate; and |
• | result in our dependency upon a single or limited number of hydrocarbon basins. |
In addition, the geographic concentration of our properties means that some or all of our properties could be affected by the same event should the U.S. Gulf of Mexico experience:
• | severe weather, including tropical storms and hurricanes; |
• | delays or decreases in production, the availability of equipment, facilities or services; |
• | delays or decreases in the availability of capacity to transport, gather or process production; or |
• | changes in the regulatory environment. |
Because all our properties could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.
Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the U.S. Gulf of Mexico.
We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. As of December 31, 2012, our estimated total asset retirement obligations were $345.5 million.
Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations may be satisfied many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from severe weather.
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In addition to the “Notices to Lessees and Operators” (“NTLs”) discussed below, BOEMRE issued an NTL effective October 15, 2010 that established a more stringent regimen for the timely decommissioning of what is known as “idle iron”—wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease—in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the U.S. Gulf of Mexico delayed the plugging, abandoning or removal of such idle iron until they met the final decommissioning regulatory requirement, which had been established as being within one year after the lease expires or terminates, a time period that sometimes was years after use of the idle iron had been discontinued. The determination of productive lease termination dates was generally based on management’s estimate as to when it would become likely that production, including from future development activities, would cease on the lease. The issued NTL, however, set forth more stringent standards for decommissioning timing requirements. Under the new standard, any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations.
The development of any additional requirements imposing an accelerated schedule for the performance of plugging, abandoning and removal activities may materially increase our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. In addition, the potential increase in decommissioning activity in the U.S. Gulf of Mexico over the next few years as a result of the NTL could result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related asset retirement obligations. For additional information about our asset retirement obligations, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Asset Retirement Obligations.”
Oil and natural gas prices are volatile and a decline in oil and natural gas prices would affect our financial results and impede growth.
Our future revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:
• | domestic and foreign supplies of oil and natural gas; |
• | price and quantity of foreign imports of oil and natural gas; |
• | actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls; |
• | level of consumer product demand; |
• | level of global oil and natural gas exploration and production; |
• | domestic and foreign governmental regulations; |
• | level of global oil and natural gas inventories; |
• | political conditions in or affecting other oil-producing and natural gas-producing countries, particularly those in the Middle East, South America, Africa and Russia; |
• | weather conditions; |
• | technological advances affecting oil and natural gas consumption; |
• | overall U.S. and global economic conditions; and |
• | price and availability of alternative fuels. |
Any substantial or extended decline in oil and natural gas prices would render uneconomic a significant portion of our exploitation, development and exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil or natural gas prices or demand for oil or natural gas may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.
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If oil and natural gas prices decline, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.
There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings. We account for our natural gas and oil exploitation and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploitation and development costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings.
Write downs could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. It is likely that the cumulative effect of a write-down could also negatively impact the value of our securities.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.
We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that require us to record an impairment of the book values associated with oil and gas properties. For the years ended December 31, 2012 and 2011, we recorded impairments of $31.0 million and $13.0 million, respectively.
Our actual recovery of reserves may substantially differ from our proved reserve estimates.
This Form 10-K contains estimates of our oil and natural gas reserves. Estimating oil and natural gas reserves is complex and inherently imprecise and subjective. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary and the accuracy of any reserve estimates and related future production is a function of the quality and reliability of available data and engineering and geological interpretation and judgment. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, which are based on our subjective estimates at the time such assumptions are made. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and natural gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies or variances in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized herein. For example, future production estimated from the development of proved undeveloped reserves is dependent upon an assumed level of development capital expenditures, which may be reduced in the event of declines in oil and gas prices, constraints in capital availability or changes in capital spending priorities. Accordingly, actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary, perhaps significantly, from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploitation and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Consequently, the inclusion of these estimates in this Form 10-K should not be regarded as a representation by us, the placement agents or any other person that the estimates will actually be achieved. You are cautioned not to place undue reliance on the estimates.
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As of December 31, 2012, approximately 39% of our total proved reserves were undeveloped and there can be no assurance that all of those reserves will ultimately be developed or produced.
Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2012, approximately 39% of our total estimated proved reserves were classified as proved undeveloped. The future development of these undeveloped reserves into proved developed reserves is highly dependent upon our ability to fund estimated total capital development costs. We cannot be sure that these estimated costs are accurate or that we will have the ability to fund the capital expenditures. The lack of access to capital may cause us to write off PUDs as a result of the five year rule. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.
In addition, we have seven offshore federal leases located in the deep waters of the U.S. Gulf of Mexico. We are unsure what effect, if any, the BOEMRE’s regulation of the drilling of wells using BOPs or surface BOPs on a floating facility will have on these leases and our estimated proved reserves. We are also unsure what effect, if any, future amendments to the OPA will have on these leases and our other offshore operations. However, it is possible that due to changes in regulation we will be unable to develop any or all of our proved undeveloped reserves. For additional information, see “—BP PLC’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the U.S. Gulf of Mexico, some of which may be unforeseeable” below.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves (referred to elsewhere as the PV-10 value) is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we currently base the estimated discounted future net revenues from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
• | the volume, pricing and duration of our oil and natural gas hedging contracts; |
• | supply of and demand for oil and natural gas; |
• | actual prices we receive for oil and natural gas; |
• | our actual operating costs in producing oil and natural gas; |
• | the amount and timing of our capital expenditures and decommissioning costs; |
• | the amount and timing of actual production; and |
• | changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate.
We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.
We have included in this Form 10-K certain estimates of our proved reserves as of December 31, 2012 prepared in a manner consistent with our and our independent petroleum consultant’s interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped reserves.
Unless we replace oil and natural gas reserves, our future reserves and production will decline.
Our future oil and natural gas production will depend on our success in finding or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploitation and
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development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.
Relatively short production periods or reserve lives for U.S. Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.
High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the U.S. Gulf of Mexico during the initial few years when compared to other regions in the United States. Typically, 50% of the reserves of properties in the U.S. Gulf of Mexico are depleted within three to four years. Due to high initial production rates, production of reserves from reservoirs in the U.S. Gulf of Mexico generally decline more rapidly than from other producing reservoirs. Our existing operations are in the U.S. Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.
We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Prospects that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.
Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In offshore operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms that we own or operate or that are owned and operated by others and, where facilities are owned and operated by others, the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut-in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a
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lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.
We are not the operator on all our current properties and we will not be the operator on all of our future properties and therefore will not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on certain of such properties.
As of December 31, 2012, we operated approximately 52% of the fields and 49% of the wells in our asset portfolio; however, as we carry out our planned drilling program, we will not serve as operator of all planned wells. We conduct and will conduct many of our operations through joint ventures in which we share control with other parties. We are not the well operator for several of our joint ventures. There is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with those of the project or us. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:
• | the timing and amount of capital expenditures; |
• | the availability of suitable drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel; |
• | the operator’s expertise and financial resources; |
• | approval of other participants in drilling wells; |
• | selection of technology; and |
• | the rate of production of the reserves. |
We are exposed to trade credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Over the past three years, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our vendors’, customers’ and counterparties’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors, customers and counterparties liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.
Our offshore operations involve special risks that could affect our operations adversely.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.
Our insurance may not protect us against all business and operating risks.
We do not maintain insurance for all of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially and, in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Therefore, we will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.
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As a result of a number of catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Katrina, Rita, Gustav and Ike, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005, insurance underwriters may no longer insure U.S. Gulf of Mexico assets against weather-related damage. Our business interruption insurance may not be economically available in the future, which could adversely impact business prospects in the U.S. Gulf of Mexico and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.
We may experience difficulty in achieving and managing future growth.
Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:
• | our ability to acquire 3-D seismic data; |
• | our ability to obtain leases or options on properties for which we have 3-D seismic data; |
• | our ability to identify and acquire new properties; |
• | our ability to develop existing prospects; |
• | our ability to continue to retain and attract skilled personnel; |
• | our ability to maintain or enter into new relationships with project partners and independent contractors; |
• | the results of our drilling program; |
• | hydrocarbon prices; and |
• | our access to capital. |
We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.
We are dependent on contractors and sub-contractors for our daily operational and service needs on individual fields and platforms. If these parties fail to satisfy their obligations to us or if we are unable to maintain these relationships, our revenue, profitability and growth prospects could be adversely affected.
We depend on a limited number of contractors and subcontractors in conducting our business. If one or more of these subcontractors experience financial or operational difficulties, we could experience an interruption in our operations. There is a risk that we may have disputes with our subcontractors arising from, among other things, the quality and timeliness of work performed by the subcontractors. Although we believe alternative subcontractors are available, our operating results could temporarily suffer until we engage one or more of those alternative subcontractors. Moreover, in engaging alternative subcontractors in exigent circumstances, our production costs could increase markedly.
Sales to a small number of customers represent a substantial portion of our revenues. The loss of any of our major customers could significantly harm our financial condition.
We derive a substantial portion of our revenues from a relatively small number of customers. For the year ended December 31, 2012, JP Morgan Ventures Energy Corporation was our largest purchaser of oil and natural gas, accounting for approximately 41% of our revenues, with Shell Trading (US) Company as the next largest purchaser, accounting for approximately 18% of our revenues. It is likely that a small number of customers will continue to account for a substantial portion of our revenues in the future. If we were to lose one of our major customers or experience a deterioration in our relationships with any of these customers, our financial condition could be significantly harmed. Additionally, if any of our top customers were to suffer financial difficulties, whether as a result of downturns in the markets, loss of market share in which they operate or otherwise, our financial condition could be significantly harmed.
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Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.
Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff, including John Hoffman, our President and Chief Executive Officer. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. If a significant number of key personnel and members of our management team resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.
Risks Related to Our Risk Management Activities
Our hedging activities could result in financial losses or could reduce our net income.
To achieve more predictable cash flows and to reduce the impact of oil and natural gas price volatility on our operations, we have and may continue to enter into hedging arrangements for a significant portion of our oil and natural gas production.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:
• | a counterparty may not perform its obligation under the applicable derivative instrument; |
• | production is less than expected; |
• | there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and |
• | the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures. |
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Natural Gas Hedging” for additional information on our oil and natural gas hedges.
Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of falling commodity prices, such as in late 2008, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
If we are unable to effectively manage the commodity price risk of our production if energy prices fall, our anticipated cash flows will be negatively impacted.
Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.
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Risks Related to Our Acquisition Strategy
We plan to pursue acquisitions as part of our growth strategy and there are inherent risks in connection with the acquisition of oil and natural gas properties, including that the acquisition may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Our growth has been attributable in large part to acquisitions of producing properties and undeveloped leasehold interests. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. The terms of the Indenture governing the Notes and our credit facility contain restrictive covenants that limit our ability to finance acquisitions and other investments and to engage in other activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our debts. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.
Successful acquisitions of oil and natural gas properties require an assessment of numerous factors that are inherently inexact and may be inaccurate, including, without limitation, those relating to:
• | acceptable prices for available properties; |
• | amounts of recoverable reserves; |
• | estimates of future oil and natural gas prices; |
• | estimates of future exploratory, development and operating costs; |
• | estimates of the costs and timing of plugging and abandonment; and |
• | estimates of potential environmental and other liabilities. |
In connection with such a potential acquisition, we perform a review of the subject properties that we believe is generally consistent with industry practices. However, such assessments are inexact and their accuracy is inherently uncertain and such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made. We are generally not able to obtain contractual indemnification for pre-closing liabilities, including environmental liabilities, and we normally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are primarily located in the U.S. Gulf of Mexico, we may pursue acquisitions or properties located in other geographic areas.
Our acquisition strategy may be stretching our existing resources.
Since our inception, we have made three major acquisitions, the W&T Acquisition, the Nippon Acquisition, and the Merit Acquisition, among other smaller acquisitions. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely exacerbate these risks.
Competition for oil and natural gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors are major or independent oil and natural gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than us. We actively compete with other companies when acquiring new leases or oil and natural gas properties. For example, new offshore leases may be acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully for acquisitions, our future revenues and growth may be diminished or restricted.
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Risks Related to Our Indebtedness and Access to Capital and Financing
Our level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.
As of December 31, 2012, letters of credit in the aggregate amount of $137.4 million were outstanding under the Letter of Credit Facility. We had $52.0 million in borrowings under the Revolving Credit Facility of which $18.0 million was available for additional borrowings. We also have substantial P&A obligations and the development of any legal requirements imposing an accelerated schedule for the performance of plugging, abandoning and removal activities, such as the BOEMRE NTL issued on September 15, 2010, may materially increase our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. (For additional information, see “—Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the U.S. Gulf of Mexico”). As of December 31, 2012, our estimated total asset retirement obligations were $345.5 million.
Additionally, we are required to make monthly contributions to the W&T Escrow Accounts, which were established to secure our P&A obligations with respect to the W&T Acquisition in October 2009, according to stipulated payment schedules for a maximum aggregate principal amount of $63.8 million. We used $20 million of the net proceeds from the November 2010 notes offering to prefund the W&T Escrow Accounts and, accordingly, one of the escrow accounts, which we refer to as the “Operated Properties Escrow Account,” is now fully funded and we have no further obligation to fund this account. However, the other escrow account, which we refer to as the “Non-Operated Properties Escrow Account,” has not been fully funded but in exchange for our prefunding, our obligation to make further payments to this account was suspended until December 1, 2011, on which date we made an initial payment of $0.2 million to the Non-Operated Properties Escrow Account, to be followed by required payments of $0.3 million per month. Pursuant to the payment schedule, this escrow account will be fully funded by the end of 2017. Until both of the W&T Escrow Accounts are fully funded, we are not permitted to withdraw cash to fund, or as reimbursement for, our P&A obligations with respect to the properties acquired as part of the W&T Acquisition (1) from the Operated Properties Escrow Account without the consent of W&T or (2) from the Non-Operated Properties Escrow Account. W&T holds a first priority lien on the W&T Escrow Accounts, and the administrative agent under our credit facility holds a second lien for the benefit of the lenders under such facility and our derivatives counterparty. 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 established to secure 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.
Further, pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”) in the principal amount of $13.1 million for future P&A costs that may be incurred on such properties. As of December 31, 2012, we have funded $8.0 million, leaving $5.1 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 aggregate principal amount of $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 December 31, 2012, we have funded $38.1 million, leaving $21.9 million to be funded through November 2013.
Our substantial indebtedness and other obligations could have important consequences. For example, it could:
• | impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes; |
• | increase our vulnerability to general adverse economic and industry conditions; |
• | result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest; |
• | have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived; |
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• | require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements; |
• | limit our flexibility in planning for, or reacting to, changes in our business and industry; and |
• | place us at a competitive disadvantage to those who have proportionately less debt. |
If we are unable to meet future debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity or sell assets. We may then be unable to obtain such financing or capital or sell assets on satisfactory terms, if at all.
We and our subsidiaries may be able to incur substantially more debt. This could further increase our leverage and attendant risks.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the Indenture governing our Notes and our credit facility do not fully prohibit us or our subsidiaries from doing so. At December 31, 2012, we and our subsidiaries collectively had approximately:
• | $201.1 million of secured indebtedness, net of unamortized discounts; and |
• | $3.6 million of unsecured short-term indebtedness. |
If new debt or liabilities are added to our current debt level, the related risks that we now face could increase.
We may not be able to generate sufficient cash flow to meet our debt service obligations.
Our ability to make payments on our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future. We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may be required to:
• | refinance all or a portion of our debt; |
• | obtain additional financing; |
• | sell some of our assets or operations; |
• | reduce or delay capital expenditures, research and development efforts and acquisitions; or |
• | revise or delay our strategic plans. |
If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of the our various debt instruments.
An increase in interest rates may increase the cost of servicing our indebtedness and could reduce our profitability.
Indebtedness we may incur under our credit facility bears interest at variable rates. As a result, any increase in interest rates, whether because of an increase in market interest rates or an increase in our own cost of borrowing, would increase the cost of servicing our indebtedness and could materially reduce the availability of debt financing, which may result in increases in the interest rates and borrowing spreads at which lenders are willing to make future debt financing available to us. The impact of such an increase would be more significant than it would be for some other companies because of our substantial indebtedness.
The covenants in the Indenture governing the Notes and our credit facility could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the notes.
The covenants contained in the Indenture governing the Notes and the agreement governing our credit facility could have important consequences for our operations, including:
• | requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities; |
• | limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities; |
• | limiting management’s discretion in operating our business; |
• | limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; |
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• | limiting our ability to hedge our production; |
• | detracting from our ability to withstand successfully a downturn in our business or the economy generally; and |
• | placing us at a competitive disadvantage against less leveraged competitors. |
If we breach any covenants under our Indenture or credit facility, a default could occur. As of and for the fiscal quarter ending December 31, 2012, we were not in compliance with certain covenants under our credit facility. We obtained a limited waiver from our lenders relating to such covenants for the fiscal quarter ending December 31, 2012. The waiver will not apply to any future fiscal quarter. In the future, if we breach a covenant, or are otherwise in default under our Indenture or credit facility, and we are unable to obtain a waiver, certain of our debt holders would be entitled to declare all amounts borrowed under the breached agreement to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and/or the termination of the agreement. In the event of acceleration of our outstanding indebtedness, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing is made available to us, it may not be on terms acceptable to us.
Our exploitation, development and production projects require substantial capital expenditures. We may be unable to obtain necessary capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploitation, development, production and acquisition of oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures. Conversely, a significant decline in product prices could result in a decrease in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows from operations, contributions from our members and through borrowings under our credit facility. Our financing needs may require us to alter or increase our capitalization substantially. The issuance of additional debt may require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:
• | our proved reserves; |
• | the level of oil and natural gas we are able to produce from existing wells; |
• | the prices at which our oil and natural gas are sold; |
• | our ability to locate, acquire and produce new reserves; |
• | the willingness of the lenders under our credit facility to lend; and |
• | our access to capital and ability to obtain financing. |
If our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves and could adversely affect our business, financial condition and results of operations.
We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.
The recent credit crisis and related turmoil in the global financial systems had an impact on our business and our financial condition, and we may face additional challenges if economic and financial market conditions deteriorate in the future. Historically, we have used contributions from our members, cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures.
In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. Further, the recent credit crisis made it more difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets increased substantially while the availability of funds from those markets generally diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on terms similar to existing debt or at all, or, in some cases, ceased to provide any new funding. A return of these conditions could materially and adversely affect our company.
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Risks Related to Environmental and Other Regulations
Our operations may incur substantial costs and expenses to comply with environmental and other government laws and regulations.
Oil and natural gas exploration, development and production operations in the United States and the U.S. Gulf of Mexico are subject to extensive federal, regional, state and local laws and regulations. Companies operating in the U.S. Gulf of Mexico are subject to laws and regulations that (1) address, among other items, land use and lease permit restrictions, bonding and other financial assurance mechanisms related to drilling and production activities, spacing of wells, unitization and pooling of properties, plugging and abandonment of wells and removal of associated infrastructure after production has ceased, operational reporting and taxation, and environmental and occupational health and safety matters; and (2) impose liability for, and require investigation and remediation of, releases of oil and hazardous or other regulated substances, including at third-party owned off-site disposal facilities where we may have disposed of wastes, and could expose us to significant incurred expenses and damages, including natural resource damages, and fines and penalties for any violation or noncompliance with any of the applicable laws or regulations.
We may incur significant capital and operating expenditures or perform other corrective actions at our wells and facilities to comply with the requirements of these environmental and occupational health and safety laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Our compliance with future laws or regulations, or with any adverse change in the interpretation or enforcement of existing laws and regulations, could increase such compliance costs. Regulatory limitations and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.
Additionally, our oil and natural gas exploitation, development and production operations are subject to stringent laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things:
• | require the acquisition of a permit before drilling or other regulated activities commence; |
• | restrict the types, quantities and concentration of materials that can be released into the environment in connection with drilling and production activities; |
• | limit or prohibit exploration or drilling activities on certain environmentally sensitive protected areas that may affect certain species, including marine mammals; |
• | impose substantial liabilities for pollution resulting from our operations; and |
• | apply specific health and safety criteria addressing worker protection. |
Costs and liabilities could arise under a wide range of federal, regional, state and local environmental laws and regulations that are amended from time to time, including, for example:
• | the OPA and comparable state laws that impose a variety of requirements and liabilities related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, on lessees and operators of offshore leases and owners and operators of oil handling facilities, including requiring owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill; |
• | the DOI, Bureau of Ocean Energy Management (“BOEM”) or BSEE NTLs and other standards issued thereunder, that relate to offshore oil and natural gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages; |
• | the Clean Air Act and comparable state laws and regulations that restricts the emission of air pollutants from many sources and impose various pre-construction, monitoring and reporting requirements; |
• | the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water; |
• | the RCRA and comparable state laws that impose requirements for the generation, storage, treatment and disposal of solid waste, including hazardous waste, from our facilities; |
• | the CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent wastes for disposal; |
• | the Federal Safe Drinking Water Act (“SWDA”), which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below ground formations that may adversely affect drinking water sources; |
• | the EPA community right to know regulations under Title III of CERCLA and similar state statutes that require us to organize and/or disclose information about hazardous materials used or produced in our operations; |
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• | the OSHA and comparable state laws, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances and appropriate control measures; and |
• | the Marine Mammal Protection Act, which ensures the protection of marine mammals through the prohibition, with certain exceptions, of the taking of marine mammals in U.S. waters and by U.S. citizens on the high seas and that may require the implementation of operating restrictions or a temporary, seasonal or permanent ban in the affected areas. |
We may be required to make significant capital and operating expenditures at our wells and platforms to comply with the requirements of these environmental laws and regulations. Failure to comply with these laws and regulations or the terms or conditions of required environmental permits may result in the assessment of administrative, civil and/or criminal penalties; the imposition of investigatory or remedial obligations as well as corrective actions; and the issuance of injunctions limiting or prohibiting some or all of our operations.
Changes in environmental or occupational health or safety laws, regulations or enforcement policies occur frequently, and any changes that result in more stringent or costly well construction, drilling or completion activities, or waste handling, storage, transport, disposal or cleanup requirements or other unforeseen liabilities could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. The costs of complying with applicable environmental laws and regulations are likely to increase over time and we cannot provide any assurance that we will be able to remain in compliance with respect to existing or new laws and regulations or that such compliance will not have a material adverse effect on our business, financial condition and results of operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbon and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical operations and waste disposal practices. Under certain environmental laws and regulations that impose strict, joint and several liability, we may be required to remediate spill incidents or contamination regardless of whether such spills or contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws and regulations at the time those actions were taken. In addition, claims for damages to persons, property or natural resources may result from spill incidents or other environmental impacts of our operations. Future spills or releases of regulated substances or accidents or the discovery of currently unknown contamination could expose us to material losses, expenditures and environmental or occupational health and safety liabilities, including liabilities resulting from lawsuits brought by private litigants for personal injury or property damage related to our operations or the area upon which our operations are conducted. We may not be able to recover some or any of these costs from insurance. See “Business—Environmental Matters and Regulation.”
BP PLC’s (“BP”) Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the U.S. Gulf of Mexico, some of which may be unforeseeable.
In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the U.S. Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the U.S. Gulf of Mexico. In response to the explosion and spill, there have been many proposals by government and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the U.S. Department of the Interior, initially through its federal Mineral Management Services (“MMS”) and subsequently through the BOEMRE (when the MMS was renamed BOEMRE in June 2010), implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling activities until the moratorium was lifted by Secretary of the Interior Ken Salazar in October 2010. While the moratorium was in place, the BOEMRE began issuing a series of NTLs imposing a variety of new safety and permitting requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico. For example, before being allowed to resume drilling in deepwater, operators in the Outer Continental Shelf must certify compliance with all applicable operating regulations found in 30 C.F.R. Part 250, such as rules relating to well casing and cementing, BOPs, safety certification, emergency response and worker training. Operators must also demonstrate the availability of adequate spill response and blowout containment resources. Although the drilling moratorium was lifted, this spill and its aftermath have led to delays in obtaining drilling permits that we believe will continue. While legislation has been introduced in the U.S. Congress to expedite the process for offshore permits including limitations on the timeframes for environmental and judicial review, there is no assurance that this or similar legislation will be adopted into law.
Effective October 1, 2011, BOEMRE was split into two federal bureaus, (1) the BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies, and (2) the BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil
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spill response and newly formed training and environmental compliance programs. Consequently, since October 1, 2011, we are required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested from the former agency and implemented in the two federal bureaus.
In addition to the drilling restrictions and new safety and permitting measures already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the U.S. Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the U.S. Gulf of Mexico more difficult, more time consuming and more costly. For example, during the previous session of Congress, a variety of amendments to the OPA were proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, which includes the U.S. Gulf of Mexico where we have substantial offshore operations. OPA subjects lessees and operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. Legislation was proposed in the previous session of Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more and there exists the possibility that similar legislation could be introduced and adopted during the current or some future session of Congress. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the OCS or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased.
Regulatory requirements and permitting procedures imposed by the BOEMRE, BOEM or BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.
Subsequent to the BP Deepwater Horizon incident in the U.S. Gulf of Mexico, the BOEMRE issued a series of NTLs and other regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the OCS. These regulatory requirements include the following:
• | the Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements; |
• | the Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers; |
• | the Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and |
• | the Workplace Safety Rule, which requires operators to have a comprehensive SEMS in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills, with amendments proposed on September 14, 2011, but not yet finalized, that would impose certain added safety procedures to a company’s SEMS not covered by the original rule and revise certain existing obligations. |
Compliance with these requirements issued by the DOI or its implementing agencies, including the BSEE and the BOEM, which two agencies are successors to BOEMRE, effective November 1, 2011, may prevent us from obtaining new drilling permits and approvals in a timely manner, which could materially adversely impact our business, financial position or results of operations. Since early 2011, there has been gradual improvement in the number of approved drilling permits issued per month for the U.S. Gulf of Mexico, however, it is possible that the improvement of this pace could slow or reverse as a result of uncertainties with respect to implementation and interpretation of NTLs and other regulatory initiatives, the ability of the BSEE to timely review submissions and issue drilling permits, or potential third party challenges to industry drilling operations in the U.S. Gulf of Mexico.
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We are unsure what long-term effect, if any, the BOEM’s or BSEE’s additional regulatory requirements and permitting procedures will have on our offshore operations. Consequently, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Deepwater Horizon incident.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rule making under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United Stated District Court for the District of Columbia in September of 2012, although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swaps,” “security-based swap,” “swap dealer” and “major swap participant.” The Dodd-Frank Act and CFTC Rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements, although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with any certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.
The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has adopted rules under the Clean Air Act requiring a reduction in emissions of GHGs from motor vehicles and requiring certain construction and operating permit reviews for GHGs from certain stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG emission sources in the United States including, among others, certain onshore and offshore oil and natural gas production facilities on an annual basis.
In addition, from time to time, Congress has considered legislation and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
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Risks Related to Our Relationship with Platinum
Platinum owns approximately 84% of our outstanding voting membership interests, giving it influence and control in corporate transactions and other matters, which may conflict with noteholders’ interests.
As of December 31, 2012, Platinum beneficially owned approximately 84% of our outstanding voting membership interests and approximately 76% of our total outstanding membership interests. As a result, and for as long as Platinum holds a membership interest in us, Platinum has the ability to remove and appoint key personnel, including all of our managers, and to determine and control our company and management policies, our financing arrangements, the payment of dividends or other distributions, and the outcome of certain company transactions or other matters submitted to our members for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. As a controlling member, Platinum could make decisions that may conflict with noteholders’ interests.
Pursuant to our Second Amended and Restated Limited Liability Company Operating Agreement (as amended and in effect as of the date hereof), if we propose to obtain additional financing through the issuance of equity or certain debt securities, Platinum is entitled to a right of first offer to provide such financing. Platinum and the other members also have, pursuant to that agreement, the right of first refusal with respect to any proposed transfer of our equity interests.
Item 1B. | Unresolved Staff Comments |
None.
Item 2. | Properties |
The information required by this Item 2. is contained in “Item 1. Business” and is incorporated herein by reference.
Item 3. | Legal Proceedings |
West Delta 32 Block Platform Incident.On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana (“West Delta 32 Incident”). At the time of the explosion, production on the platform had been shut in while crews of independent contractors performed maintenance and construction on the platform.
Three workers died as a result of the explosion and subsequent fire, and others sustained varying degrees of personal injuries. In response to the West Delta 32 Incident, we dispatched two oil spill recovery vessels to the scene to evaluate any potential environmental impact and conduct spill recovery efforts. Based on preliminary estimates of the contents of the three oil tanks involved in the incident, we reported to the required regulatory agencies a loss amount of approximately 480 barrels of oil. There was no loss of containment from any well connected to the platform and no on-going spill following the initial incident. We engaged ES&H Training and Consulting Group to clean the platform to prevent residual oil from being washed or blown into the Gulf of Mexico. This work was completed on November 30, 2012.
Regulatory Investigation and Audit.The cause of the West Delta 32 Incident is being investigated by BSEE, in coordination with the U.S. Coast Guard. This investigation is still ongoing. The United States Chemical Safety and Hazard investigation board has also made inquiry of us regarding the incident but has not yet formally opened an investigation. We are fully cooperating with all government agencies.
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 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 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 to BSEE our progress on those required improvements.
We currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the investigations and the audit. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance and associated penalties, as well as enjoin us from operating part or all of West Delta 32. We intend to vigorously defend the Company against potential enforcement actions
Civil Litigation.As of April 10, 2013, four civil lawsuits have been filed as a result of the West Delta 32 Incident. 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
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February 7, 2013, the plaintiffs amended their petition, adding another BEE unit holder as a named plaintiff and joining as defendants additional parties, including Freedom Well Services, LLC, Freedom Logistics, LLC, Elk Well Services, LLC, Freedom HHC Management LLC, and FWS Employee Incentive LLC. On March 8, 2013, the plaintiffs amended their petition for a second time to delete certain factual allegations regarding dilution of BEE’s interest in our company. Two prior lawsuits alleging many of the same facts have been dismissed. This case is being defended vigorously.
On March 22, 2013, these same investor plaintiffs filed a similar purported derivative action on behalf of BEE in the Supreme Court of New York County in the State of New York. The suit is filed against our company; John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities and individuals affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. Like the Harris County lawsuit, the plaintiffs allege that the defendants improperly diluted BEE’s percentage ownership in our company; it is unclear whether plaintiffs are also asserting claims with respect to the West Delta 32 Incident in connection with this separate lawsuit. The plaintiffs seek an unspecified amount of damages individually and on behalf of BEE in connection with these claims. Like the Harris County lawsuit, this case is being defended vigorously.
On January 31, 2013, eight individual plaintiffs sued BEEOO, BEE, and three independent contractors (Wood Group USA, Inc., Compass Engineering and Consultants, LLC, and Enviro-Tech Specialties, Inc.) in the United States District Court for the Southern District of Texas. The plaintiffs seek to recover for injuries they allege to have suffered in connection with the West Delta 32 Incident. The plaintiffs allege that they were employed by Grand Isle Shipyard, Inc., and that they were working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. The plaintiffs seek $100 million in actual damages and $300 million in punitive damages.
On February 27, 2013, the family of decedent Avelino Tajonera sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Tajonera’s wife individually and on behalf of his estate and Mr. Tajonera’s three children. The plaintiffs allege that Mr. Tajonera was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Tajonera died several days after the West Delta 32 Incident from injuries he sustained therein. The plaintiffs are seeking an unspecified amount of actual and punitive damages.
On March 25, 2013, the family of decedent Ellroy Corporal sued our company in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Corporal’s wife individually and on behalf of his estate and Mr. Corporal’s two children. The plaintiffs allege that Mr. Corporal was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Corporal died from complications due to the West Delta 32 Incident. The plaintiffs are seeking an unspecified amount of actual and punitive damages.
For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal 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. We intend to vigorously defend the Company in these proceedings.
Other Regulatory Items. We received a Notice of Proposed Civil Penalty Assessment dated April 5, 2011 (“Notice”) from the BOEMRE for an Incident of Noncompliance (“INC”) arising from a particular well’s alleged exceedance of certain testing time limits and alleged need for certain corrective actions. The INC was issued by BOEMRE during its on-site inspection of Vermilion Area Block 124, Platform F on July 30, 2010. We requested and attended a mitigation hearing with BOEMRE on the matter as we believe that a significant threat to safety or the environment did not exist, and are seeking a reduced civil penalty based on the mitigating circumstances presented in the hearing. We have received a final decision from BOEMRE on the matter and have been assessed a penalty of approximately $0.3 million of which we appealed to the Interior Board of Land Appeals (“IBLA”). We received notice on December 19, 2011 that the civil penalty would remain as assessed by the Reviewing Officer’s final decision. We paid the penalty of $0.3 million on September 5, 2012.
On June 27, 2012, we received notice from BSEE that administrative civil penalty proceedings had been initiated for two INCs issued as a result of an incident that occurred on October 9, 2011 at one of our offshore platforms. Both INCs allege operations involving well flowback operations were not conducted in a safe and workmanlike manner. As part of the civil penalty, we requested an informal meeting to present factual information to the reviewing officer that should serve to mitigate the proposed civil penalty of $140,000. The meeting was held on September 19, 2012. The Hearing Officer issued a final decision on December 31, 2012, affirming the proposed civil penalty and we have appealed the matter to the Interior Board of Land Appeals.
We are also subject to certain other environmental matters and regulations. For a discussion of these items, see Item 1.“Business—Environmental Matters and Regulation.”
We are party to various other litigation matters arising in the ordinary course of business. We do not believe the outcome of these disputes or legal actions will have a material adverse effect on our financial statements.
Item 4. | Mine Safety Disclosures |
Not applicable.
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Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
We are a privately held company and there is no established public trading market for our membership interests.
Item 6. | Selected Financial Data |
Set forth below is our summary historical consolidated financial data for the years ended December 31, 2012, 2011, 2010 and 2009 and for the period from inception (January 29, 2008) through December 31, 2008, and balance sheet data at December 31, 2012, 2011, 2010, 2009 and 2008. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.
Year Ended December 31, | Period from Inception (January 29, 2008) through December 31, | |||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
STATEMENTS OF OPERATIONS DATA (in thousands): | ||||||||||||||||||||
Crude oil, natural gas and plant product sales | $ | 285,897 | $ | 314,289 | $ | 112,566 | $ | 20,788 | $ | 13,024 | ||||||||||
Realized gain on derivative financial instruments | 23,364 | 8,099 | 9,271 | 801 | — | |||||||||||||||
Unrealized (loss) gain on derivative financial instruments | (4,783 | ) | 17,556 | (12,700 | ) | (2,756 | ) | — | ||||||||||||
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Total revenue | 304,478 | 339,944 | 109,137 | 18,833 | 13,024 | |||||||||||||||
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Operating Expenses: | ||||||||||||||||||||
Lease operating costs, workovers and production taxes | 199,422 | 182,789 | 59,555 | 10,043 | 9,995 | |||||||||||||||
Exploration | 1,682 | 1,004 | 14 | 47 | 79 | |||||||||||||||
Depreciation, depletion and amortization | 47,314 | 47,214 | 29,795 | 15,419 | 3,316 | |||||||||||||||
Impairment | 31,033 | 12,967 | 6,407 | 446 | — | |||||||||||||||
General and administrative | 26,486 | 22,029 | 14,588 | 7,164 | 3,377 | |||||||||||||||
Gain due to involuntary conversion of asset | (3,100 | ) | — | — | (18,718 | ) | (9,526 | ) | ||||||||||||
Accretion | 36,421 | 27,410 | 9,175 | 388 | 422 | |||||||||||||||
Gain on sale of asset | 38 | (142 | ) | — | — | — | ||||||||||||||
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Total operating expenses | 339,296 | 293,271 | 119,534 | 14,789 | 7,663 | |||||||||||||||
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Income (loss) from operations | $ | (34,818 | ) | $ | 46,673 | $ | (10,397 | ) | $ | 4,044 | $ | 5,361 | ||||||||
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Operating Data: | ||||||||||||||||||||
Oil (MBbl) (1) | 1,977 | 1,991 | 857 | 140 | 36 | |||||||||||||||
Natural gas (MMcf) (1) | 17,884 | 18,188 | 7,997 | 2,444 | 1,068 | |||||||||||||||
Plant products (MGal) (1) | 13,588 | 12,257 | 5,403 | 320 | — | |||||||||||||||
Oil: | ||||||||||||||||||||
Average price before effects of hedges ($/Bbl) | $ | 106.60 | $ | 108.09 | $ | 80.09 | $ | 70.43 | $ | 99.51 | ||||||||||
Average price after effects of hedges ($/Bbl) | 110.18 | 105.17 | 80.97 | 71.59 | 99.51 | |||||||||||||||
Average price differentials | 12.50 | 13.04 | 0.59 | 8.44 | (0.41 | ) | ||||||||||||||
Natural Gas: | ||||||||||||||||||||
Average price before effects of hedges ($/Mcf) | $ | 2.82 | $ | 4.18 | $ | 4.38 | $ | 4.29 | $ | 8.87 | ||||||||||
Average price after effects of hedges ($/Mcf) | 3.73 | 4.94 | 5.44 | 4.55 | 8.87 | |||||||||||||||
Average price differentials | 0.07 | 0.18 | — | 0.34 | (0.02 | ) |
(1) | Total production for each of the periods presented. |
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As of December 31, | ||||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
BALANCE SHEET DATA (in thousands): | ||||||||||||||||||||
Cash and cash equivalents | $ | 1,383 | $ | 17,260 | $ | 18,879 | $ | 6,236 | $ | 1,647 | ||||||||||
Oil and natural gas properties, net | 260,012 | 238,702 | 123,783 | 88,600 | 8,148 | |||||||||||||||
Total assets | 590,464 | 546,006 | 306,504 | 114,009 | 26,806 | |||||||||||||||
Total debt, including current portion | 204,670 | 177,041 | 150,753 | 40,133 | 6,851 | |||||||||||||||
Asset retirement obligations (net of escrow) | 109,894 | (1) | 96,185 | (1) | 8,074 | 45,431 | (4,846 | ) | ||||||||||||
Members’ equity (deficit) | (118,467 | )(2) | (29,708 | )(2) | (20,610 | ) | 5,723 | 4,919 | ||||||||||||
Year Ended December 31, | Period from Inception (January 29, 2008) through December 31, | |||||||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
OTHER FINANCIAL DATA (in thousands): | ||||||||||||||||||||
Net cash provided by (used in) operating activities | $ | 66,054 | $ | 73,647 | $ | 28,345 | $ | (528 | ) | $ | 1,479 | |||||||||
Net cash used in investing activities | (89,723 | ) | (108,641 | ) | (114,815 | ) | (27,415 | ) | (5,814 | ) | ||||||||||
Net cash provided by (used in) financing activities | 7,792 | 33,375 | 99,113 | 32,532 | 5,982 | |||||||||||||||
Adjusted EBITDA (3) | 78,995 | 110,686 | 47,052 | 4,617 | (405 | ) |
(1) | Amount also net of asset retirement obligation escrow receivable as it relates to P&A obligations. |
(2) | Amount reflects reclassification of redeemable preferred shares outside of permanent equity. For a further discussion of the reclassification, please see “Notes to Consolidated Financial Statements—Note 12—Members’ Deficit” in this Form 10-K. |
(3) | Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss), see “—Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” below. |
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Item 7. 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-K. 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, 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 December 31, 2012, we held an aggregate net interest in approximately 542,500 gross (270,600 net) acres under lease and had an interest in 1,109 gross wells, 326 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, LLC was incorporated on November 20, 2007 to act as a holding company for its then operating subsidiaries, Black Elk Energy Offshore Operations, LLC and Black Elk Energy Land Operations, 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 two wholly-owned domestic subsidiaries: Black Elk Energy Land Operations, LLC, which is a guarantor under our Indenture, and Black Elk Energy Finance Corp., which is the co-issuer of the Notes. Neither Black Elk Energy Land Operations, LLC nor Black Elk Energy Finance Corp have any material assets or operations.
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.
In 2008, we acquired our first field, South Timbalier 8, located in Louisiana state waters in the Gulf of Mexico. This acquisition was followed by an additional field acquisition in U.S. federal waters in the Gulf of Mexico, West Cameron 66.
On October 29, 2009, we completed the W&T Acquisition, purchasing interests in approximately 35 fields and 350 wells across approximately 195,000 gross (71,000 net) acres primarily located in U.S. federal waters in the Outer Continental Shelf.
In 2010, we completed two acquisitions which increased the geographic diversity of our portfolio. During the first quarter of 2010, we acquired properties in the Gulf of Mexico, primarily located within Texas state waters from Chroma Oil & Gas, LP. This acquisition consisted of six fields and added interests in an additional 40 wells and approximately 13,900 gross (6,400 net) acres to our portfolio. On September 30, 2010, we acquired 27 properties across approximately 195,944 gross (103,130 net) acres in the Gulf of Mexico from Nippon Oil Exploration U.S.A. The Nippon Acquisition included 90 producing wells, 223 wellbores, 41 platforms, and 19 producing fields.
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In February 2011, we acquired additional properties in the Gulf of Mexico, strategically located among our existing assets from Maritech Resources Incorporated. The Maritech Acquisition consisted of eight fields and added interests in 105 gross (43 net) wells and approximately 45,500 gross (22,200) net acres.
On May 31, 2011, we completed our purchase of certain properties from the Merit Entities. We acquired interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico. In connection with the Merit Acquisition, we entered into a contribution agreement with Platinum, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Units.
Our revenue, profitability and future growth rate depend significantly on factors beyond our control, such as economic, political and regulatory developments, and environmental hazards, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since our inception, commodity prices have experienced significant fluctuations.
From time to time, we use derivative financial instruments to economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Our average prices that reflect both the before and after effects of our realized commodity hedging transactions for the three years ended December 31, 2012, 2011 and 2010 are shown in the table below.
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Oil: | ||||||||||||
Average price before effects of hedges ($/Bbl) (1) | $ | 106.60 | $ | 108.09 | $ | 80.09 | ||||||
Average price after effects of hedges ($/Bbl) | 110.18 | 105.17 | 80.97 | |||||||||
Average price differentials (2) | 12.50 | 13.04 | 0.59 | |||||||||
Gas: | ||||||||||||
Average price before effects of hedges ($/Mcf) (1) | $ | 2.82 | $ | 4.18 | $ | 4.38 | ||||||
Average price after effects of hedges ($/Mcf) | 3.73 | 4.94 | 5.44 | |||||||||
Average price differentials (2) | 0.07 | 0.18 | — |
(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 |
The United States and other world economies suffered a severe recession extending into 2012 and economic conditions continue to remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in natural gas prices received for our production in 2011 and 2012. Both 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. See “Item 1A. Risk Factors—If oil and natural gas prices decline, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of our outstanding debt obligations and negatively impacting the trading value of our securities.”
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
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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
West Delta 32
On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana, in 52 feet of water. Three workers died as a result of the explosion and subsequent fire, and others sustained various degrees of person injuries. We dispatched two oil spill recovery vessels to the scene to evaluate any potential environmental impact and conduct spill recovery efforts. Based on an analysis of the sheen observed after the incident, the spill totaled less than one barrel. Based on preliminary estimates of the tank contents, BSEE requested us to also report a loss amount of 480 barrels. There was no loss of containment from any well connect to the platform. There was no loss of oil after the fire was controlled. The cause of the fire is being investigated by Black Elk and BSEE, in coordination with the U.S. Coast Guard. We have engaged ABS Consulting to assist with our investigation in order to make a cause and origin determination. The cause has not yet been determined. We engaged ES&H Training and Consulting Group to clean the platform to prevent residual oil on the platform from being washed or blown into the Gulf of Mexico. The work was completed on November 30, 2012. At BSEE’s direction, we have also engaged an independent third-party auditor to audit our SEMS program. We have insurance for some potential losses and are pursuing reimbursement for this incident. As of April 10, 2013, four civil lawsuits have been filed as a result of the West Delta 32 Incident. For additional information, please see “Risk Factors” under Item 1A of this Form 10-K and “Legal Proceedings” under Item 3 of this Form 10-K.
SEMS Audit
On January 17, 2013, we commenced a BSEE directed Independent Third Party SEMS Audit. The audit was conducted by 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 was submitted to BSEE on April 11, 2013.
Performance Improvement Plan (“PIP”)
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 |
• | Incentive compensation for safety performance |
Implementation of corrective actions is in progress. Many items have been completed, such as the establishment of several new positions within the HSE&C group to provide work oversight and improve regulatory compliance on offshore facilities. Essential documentation such as our SIMOPS Plan, 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, Job Safety Analysis and Stop Work Authority is ongoing. Additionally, we have initiated a Production Operations Performance Incentive Program to reward field operations personnel for safe and compliant performance on our facilities.
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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 Bureau of Safety and Environmental Enforcement (“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.
Capital Contributions
On January 25, 2013, we entered into a contribution agreement with PPVA Black Elk (Equity) LLC (“PPVA (Equity)”), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million of our Class E Preferred Units (the “Class E Units”) and 76 Class B Units (the “Class B Units”), having such rights, preferences and privileges as set forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. 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 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).
In the first quarter of 2013, we entered into contribution agreements with Platinum Partners Black Elk Opportunities Fund LLC (“PPBE”) or entities designated by PPBE (together, the “Platinum Group”) pursuant to which we have issued, or expect to issue 40 million additional Class E Units and 3 million additional Class B Units to the Platinum Group for an aggregate offering price of $40.0 million. As of April 10, 2013, we have issued an aggregate $50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013, we issued an additional 2,522,693.340 Class E Units as paid-in-kind dividends to the holders of Class E Units on such date.
Issuance of 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.
Stock Split
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 our 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.
Operating Agreement Amendment
On April 9, 2013, we entered into the Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC (the “Fifth Amendment”) to (1) revise and confirm the order and manner of distributions to our members and (2) permit the issuance of Class E Units in an aggregate amount not to exceed $95.0 million and the issuance of Class B Units in connection with such Class E Units in an aggregate amount not to exceed 3,800,000 units before giving effect to any capitalized Class E preferred return, for cash or property capital contributions.
Sale of Assets
On March 26, 2013, we completed the sale of four fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. Funds will be used to reduce the amount borrowed under our credit facility and for general corporate purposes. We will also work with counterparties to release approximately $29.8 million of escrows related to the sold properties.
Letter of Credit Facility Amendment and Credit Facility Amendments
In connection with the sale of the four fields to Renaissance Offshore, LLC that was completed on March 26, 2013, we entered into the Eighth Amendment to our credit facility which (1) lowered our borrowing base to $25 million from $61 million upon the sale of the four fields, (2) will further
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reduce the borrowing base to $15 million after the bonds posted with the Bureau of Ocean Management, Regulation and Enforcement related to the sold properties are released or terminated, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by 1% if the credit exposure is greater than $15 million, (4) scheduled the borrowing base redetermination date to May 31, 2013 and (5) restricted returns of capital to our stockholders or distributions of our property to our equity interest holders.
In April 2013, we also entered into the Limited Waiver and Seventh Amendment to Letter of Credit Facility (the “Seventh Amendment”) and the Limited Waiver and Ninth Amendment to our Credit Facility (the “Ninth Amendment”) to obtain waivers related to (1) the leverage ratio for the quarter ended December 31, 2012, (2) the over hedged oil position for the calendar month of January 2013 at December 31, 2012, (3) the hedge requirement only to the extent that it relates to existing oil hedges but that such noncompliance was a result of the sale of the four fields to Renaissance Offshore, LLC, provided that we will be in compliance with the covenant when the borrowing base is re-determined in May 2013 and (4) the delay in the capital contributions, which were all received by April 9, 2013. The Seventh Amendment and the Ninth Amendment removed the current ratio covenant and replaced it with a 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. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0. We paid $0.3 million to obtain the waiver.
Drilling Update
In 2013 to date, we have two drilling rigs performing sidetrack operations on our operated properties and two currently drilling on non-operated properties with another mobilizing to location. We recompleted 32 wells during 2012, 15 of which are currently producing. We plan to actively drill during 2013. Our rig activity during the remainder of 2013 will be dependent on oil and natural gas prices and, accordingly, our rig count may increase or decrease from year-end levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost.
Risks and Uncertainties
Our liquidity outlook changed during the year ended December 31, 2012 primarily as a result of lower gas prices and lower production as a result of wells that watered out, delays in the capital program, shut-ins due to pipeline repairs and Hurricane Isaac as well as the explosion and fire on our West Delta 32-E platform, which caused downtime and delays in the fields due to the BSEE requirement for approval after the incident.
While cash flows were lower than previously projected primarily due to lower production, we continued our development operations by supplementing our cash flows from operating activities with funds raised through borrowings in 2012, capital contributions from our members and an asset sale in 2013. We retained financial and technical advisors to provide recommendations on achieving improvements in production, operating expense, cash flows from operations, work over, capital expenditures, business planning and the arrangement of additional funding going forward.
As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $71.7 million at December 31, 2012 and we incurred a net loss of $64.0 million during the year ended December 31, 2012. The combination of restricted credit availability and lower production in the fourth quarter of 2012 led to significant cash reductions in the fourth quarter of 2012 and the first quarter of 2013. To increase liquidity, we stretched accounts payable and aggressively pursued accounts receivable. We have worked closely with our vendors during this time and expect to normalize the age of accounts payables within the second quarter. We continue to optimize our production portfolio and have commenced our drilling program in the fourth quarter of 2012. Currently, we have two rigs under contract and we expect to drill and complete eight operated wells and seven non-operated wells in 2013. To fund the drilling program and operations, we expect to continue to raise additional capital over the next several years. We are currently evaluating new sources of liquidity including, but not limited to, (i) renegotiating our current revolving credit facility, (ii) entering into a new revolving credit facility and (iii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. As of March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. Proceeds from the sale will be used to reduce the amount borrowed under the Credit Facility by $36 million and for general corporate purposes. We will also work with counterparties to release approximately $29.8 million of escrows related to the sold properties of which $10 million will be used to pay down the Credit Facility.
Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our plugging and abandonment (“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 our surety bonds for P&A obligations. We are currently in discussions with surety agencies to replace the 100% cash-backed letters of credit. There can be no assurance as to the availability or terms upon which such equity or debt funding might be available.
At December 31, 2012, we were not in compliance with certain covenants in our Credit Facility. We have obtained waivers for the current ratio covenant, the hedging requirements covenant and the debt leverage ratio covenant for the period ended December 31, 2012. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0. The current ratio covenant has been removed in the Seventh Amendment and the Ninth Amendment and has been replaced with a payables restriction covenant. Our liquidity projections demonstrate improvement of our financial position and we believe that we will meet our interest coverage ratio covenant, debt leverage ratio covenant and payables restriction covenant going forward. If we are unable to maintain compliance with our debt covenants or obtain waivers or amendments, then we
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will be in default under our Credit Facility and all amounts outstanding would be reclassified as current liabilities on our consolidated balance sheet. If we are unable to repay the outstanding debt as it comes due, or if we are not able to effectively manage our working capital, or as necessary, successfully access the debt capital market, such events may have a material adverse effect on our financial position. 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.
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.
As operator of certain projects that require cash commitments within the next twelve months and beyond, we retain significant control over the development concept and its timing. We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have the ability to delay certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match, on a temporary basis, our capital commitments to our available capital resources.
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 material adverse effect on us. 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. We believe we can continue to meet our obligations for at least the next twelve months through a combination of cash flows from operations, capital contributions, asset dispositions and insurance reimbursement proceeds for P&A costs on the High Island 443 A-2 well and for costs to drill the replacement well, High Island 443 A-5, as well as delaying certain facility or drilling projects in the second half of 2013.
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.
A substantial portion of 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.
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Oil and natural gas development and production in the Gulf of Mexico are regulated by the BOEM and BSEE of the 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. Additionally, we cannot influence or predict if or how the governments of other countries in which we operate may modify their regulatory requirements.
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.
Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium
In April 2010, the Deepwater Horizon, a drilling platform operated by BP PLC in ultra deepwater in the U.S. Gulf of Mexico, sank after an apparent blowout and fire. The resulting leak caused a significant oil spill. In response to the explosion and spill, the DOI implemented a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling sidetracks and bypasses of wells beginning in May 2010 until the moratorium was lifted by the DOI in October 2010.
In addition, while the moratorium was in place, the DOI, through its Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), issued a series of NTLs or regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the OCS. These requirements include the following:
• | the Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements; |
• | the Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers; |
• | the Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and |
• | the Workplace Safety Rule, which requires operators to have a comprehensive SEMS in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills, with amendments proposed on September 14, 2011, but not yet finalized, that would impose certain added safety procedures to a company’s SEMS not covered by the original rule and revise certain existing obligations. |
Compliance with these requirements issued by the DOI or its implementing agencies, including the BSEE and the BOEM, which two agencies are successors to BOEMRE, effective November 1, 2011, may prevent us from obtaining new drilling permits and approvals in a timely manner, which could materially adversely impact our business, financial position or results of operations. Since early 2011, there has been gradual improvement in the number of approved drilling permits issued per month for the U.S. Gulf of Mexico, however, it is possible that the improvement of this pace could slow or reverse as a result of uncertainties with respect to implementation and interpretation of NTLs and other regulatory initiatives, the ability of the BSEE to timely review submissions and issue drilling permits, or potential third party challenges to industry drilling operations in the U.S. Gulf of Mexico.
We are unsure what long-term effect, if any, the BOEM’s or BSEE’s additional regulatory requirements and permitting procedures will have on our offshore operations. Consequently, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Deepwater Horizon incident.
Health, Safety, and Environmental Program Update
Our Health, Safety and Environmental (“HS&E”) Program is managed by a team of experienced professionals with specialized skills in the areas of health, safety, environmental, compliance and facility security. In certain circumstances, we employ third party consultants to supplement our resource needs.
For our U.S. Gulf of Mexico operations, we have developed and implemented a Regional Oil Spill Response Plan. Our response team implementing this Regional Oil Spill Response Plan is a trained work force that receives training updates annually and performs annual spill drills as required by the BSEE. In addition, we have Environmental Safety & Health Consulting Services, Inc. (“ES&H”), our designated Oil Pollution Act spill response contractor on contractual retainer. ES&H maintains 24 hour, seven day a week manned incident command centers located in Houston, Texas and Houma, Louisiana. ES&H commences spill response activities on our behalf upon our notification of an emergency. While we focus on source control of the spill, ES&H handles all communication with state and federal agencies as well as U.S. Coast Guard and BSEE notifications. ES&H maintains a staff and equipment inventory that is available upon notice to respond to an emergency.
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We are also a member of Clean Gulf Associates (“CGA”). CGA was formed in 1972 and currently has 140 member companies, making the association the largest oil spill response cooperative in terms of membership in North America. CGA specializes in onsite control and cleanup and is on 24 hour, seven days a week alert with equipment currently stored at six bases situated along the U.S. Gulf of Mexico coast (Ingleside, Texas, Galveston, Texas, Lake Charles, Louisiana, Houma, Louisiana, Venice, Louisiana and Pascagoula, Mississippi), and is opening new sites in Leeville, Louisiana, Morgan City, Louisiana and Harvey, Louisiana. The CGA equipment inventory is available to serve member oil spill response needs including blowouts; open seas, near shore and shallow water skimming; open seas and shoreline booming; communications; dispersants; boat spray systems to apply dispersants; wildlife rehabilitation; and a forward command center. CGA has contractual retainers with an aerial dispersant company and a company that provides mechanical recovery equipment for spill responses. CGA equipment includes:
• | HOSS Barge—the largest purpose-built skimming barge in the United States with 4,000 barrels of storage capacity; |
• | Fast Response System—a self-contained skimming system for use on vessels of opportunity. CGA has nine of these units; and |
• | Fast Response Vessels (“FRV”)—four 46-foot FRVs with cruise speeds of 20-25 knots that have built-in skimming troughs and cargo tanks, outrigger skimming arms, navigation and communication equipment. |
In addition, source control support is provided, as necessary, by Boots & Coots, Inc., a provider of firefighting, well control, engineering, and training services.
On September 30, 2010, the BOEMRE announced a final SEMS rule that became effective November 15, 2010. The final SEMS rule required implementation of the following 13 elements of the American Petroleum Institute’s Recommended Practice 75 by no later than November 2011:
• | Management commitment program principles, |
• | Safety and environmental information, |
• | Hazards analyses, |
• | Management of change, |
• | Operating procedures, |
• | Safe work practices and contractor selection, |
• | Training, |
• | Mechanical integrity, |
• | Pre-Startup review, |
• | Emergency response and control, |
• | Investigation of accidents, |
• | Audits, and |
• | Records and documentation. |
On November 3, 2011, we participated in an audit exercise with BOEMRE in their Herndon, VA office. There were no significant issues or deficiencies noted during this exercise. We believe we are currently in material compliance with the SEMS requirements.
How We Evaluate Our Operations
We use a variety of financial and operational measures to assess our overall performance. Among these measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) Adjusted EBITDA (as defined in the following table).
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The following table contains certain financial and operational data for each of the years ended December 31, 2012, 2011 and 2010:
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Average daily sales: | ||||||||||||
Oil (Boepd) | 5,401 | 5,455 | 2,348 | |||||||||
Natural gas (Mcfpd) | 48,865 | 49,829 | 21,911 | |||||||||
Plant products (Galpd) | 37,125 | 33,580 | 14,802 | |||||||||
Oil equivalents (Boepd) | 14,429 | 14,559 | 6,353 | |||||||||
Average realized prices (1): | ||||||||||||
Oil ($/Bbl) | $ | 110.18 | $ | 105.17 | $ | 80.97 | ||||||
Natural gas ($/Mcf) | 3.73 | 4.94 | 5.44 | |||||||||
Plant products ($/Gallon) | 1.02 | 1.29 | 1.10 | |||||||||
Oil equivalents ($/Boe) | 56.50 | 59.30 | 51.27 | |||||||||
Costs and Expenses: | ||||||||||||
Lease operating expense ($/Boe) | 34.22 | 29.83 | 23.56 | |||||||||
Production tax expense ($/Boe) | 0.14 | 0.16 | 0.28 | |||||||||
General and administrative expense ($/Boe) | 5.02 | 4.15 | 6.29 | |||||||||
Net (loss) income (in thousands) | (63,968 | ) | 15,041 | (23,897 | ) | |||||||
Adjusted EBITDA (2) (in thousands) | 78,995 | 110,686 | 47,052 |
(1) | Average realized prices presented give effect to our hedging. |
(2) | Adjusted EBITDA is defined as net (loss) income before interest expense, unrealized gain/loss on derivative instruments, accretion, depreciation, depletion, amortization and impairment, gain on involuntary conversion of assets, provision for doubtful accounts and loss/gain on sale of asset. Adjusted EBITDA is not a measure of net (loss) income or cash flows as determined by GAAP, and should not be considered as an alternative to net (loss) income, operating (loss) income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. Our presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or nonrecurring items. A reconciliation table is provided below to illustrate how we derive Adjusted EBITDA. |
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Net (loss) income | $ | (63,968 | ) | $ | 15,041 | $ | (23,897 | ) | ||||
Adjusted EBITDA | $ | 78,995 | $ | 110,686 | $ | 47,052 | ||||||
Reconciliation of Net income (loss) to Adjusted EBITDA: | ||||||||||||
Net (loss) income | $ | (63,968 | ) | $ | 15,041 | $ | (23,897 | ) | ||||
Interest expense | 25,965 | 25,752 | 12,872 | |||||||||
Unrealized loss (gain) on derivatives instruments | 4,783 | (17,556 | ) | 12,700 | ||||||||
Accretion | 36,421 | 27,410 | 9,175 | |||||||||
Depreciation, depletion, amortization and impairment | 78,347 | 60,181 | 36,202 | |||||||||
Gain on involuntary conversion of assets | (3,100 | ) | — | — | ||||||||
Provision for doubtful accounts | 509 | — | — | |||||||||
Loss (gain) on sale of asset | 38 | (142 | ) | — | ||||||||
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Adjusted EBITDA | $ | 78,995 | $ | 110,686 | $ | 47,052 | ||||||
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Set forth below is an explanation of certain of the expenses and other financial items that we disclose in our financial statements. We utilize the successful efforts method of accounting for our oil and natural gas properties.
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Derivative (losses) gains.We utilize certain commodity-derivative contracts to manage our exposure to oil and gas price volatility. The oil and gas reference prices of these commodity-derivatives contracts were based upon futures that have a high degree of correlation with actual prices we receive. Under this method, realized gains and losses from our price risk management activities were recognized in operating revenue when the associated production occurred and the resulting cash flows were reported as cash flows from operations.
Lease operating costs. Lease operating costs consists of costs and expenses incurred to manage our production facilities and development operations, overhead, well control expenses and repairs and maintenance charges.
Workover costs.Workover costs are expenses incurred during the operations of a producing well to restore or increase production.
Depreciation, depletion, amortization and impairment. All capitalized costs of proved oil and natural gas properties are depleted through depreciation, depletion and amortization (“DD&A”) using the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental wells and productive leases are capitalized into the appropriate groups based on geographical and geophysical similarities. These capitalized costs are depleted using the units-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of depletion base is sold or abandoned.
We follow the provisions of authoritative guidance for impairment or disposal of long-lived assets. This guidance requires that long lived assets, including oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Impairment is determined to have occurred when the estimated undiscounted cash flows of the asset are less than its carrying value. Any such impairment is recognized and recorded based on the differences in carrying value and estimated fair value of the impaired asset.
Unevaluated properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to accumulated amortization.
General and administrative expenses. General and administrative expenses (“G&A expense”) include payroll and benefits for our corporate staff, costs of maintaining our headquarters, certain data processing charges, property taxes, audit and other professional fees and legal compliance.
Accretion expense.Accretion expense is associated with our asset retirement obligation liability and is recognized each period using the interest method of allocation. The capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon our interim review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate.
Interest expense. Interest expense reflects interest incurred on our outstanding debt instruments.
Income tax provision. As of December 31, 2012, we were a limited liability company not subject to entity level income tax. Our taxable income or loss is therefore passed through to our members and reported on their respective tax returns. Accordingly, no provision for federal income taxes has been recorded in our historical financial statements. We are subject to the Texas Gross Margin Tax. The Texas Gross Margin Tax generally is calculated as 1% of gross margin.
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Results of Operations
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
The following table sets forth certain information with respect to oil and gas operations for the years ended December 31, 2012 and 2011.
Year Ended December 31, | ||||||||||||||||
2012 | 2011 | Change | % Change | |||||||||||||
PRODUCTION: | ||||||||||||||||
Oil (MBbl) | 1,977 | 1,991 | (14 | ) | -1 | % | ||||||||||
Natural gas (MMcf) | 17,884 | 18,188 | (304 | ) | -2 | % | ||||||||||
Plant products (MGal) | 13,588 | 12,257 | 1,331 | 11 | % | |||||||||||
Total (MBoe) | 5,281 | 5,314 | (33 | ) | -1 | % | ||||||||||
REVENUES | ||||||||||||||||
Oil sales | $ | 210,720 | $ | 215,204 | $ | (4,484 | ) | -2 | % | |||||||
Natural gas sales | 50,470 | 75,994 | (25,524 | ) | -34 | % | ||||||||||
Plant product sales and other income | 24,707 | 23,091 | 1,616 | 7 | % | |||||||||||
Realized gain on derivative financial instruments | 23,364 | 8,099 | 15,265 | 188 | % | |||||||||||
Unrealized (loss) gain on derivative financial instruments | (4,783 | ) | 17,556 | (22,339 | ) | 127 | % | |||||||||
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304,478 | 339,944 | (35,466 | ) | -10 | % | |||||||||||
OPERATING EXPENSES | ||||||||||||||||
Lease operating | 180,691 | 158,545 | 22,146 | 14 | % | |||||||||||
Production taxes | 745 | 859 | (114 | ) | -13 | % | ||||||||||
Workover | 17,986 | 23,385 | (5,399 | ) | -23 | % | ||||||||||
Exploration | 1,682 | 1,004 | 678 | 68 | % | |||||||||||
Depreciation, depletion and amortization | 47,314 | 47,214 | 100 | 0 | % | |||||||||||
Impairment | 31,033 | 12,967 | 18,066 | 139 | % | |||||||||||
General and administrative | 26,486 | 22,029 | 4,457 | 20 | % | |||||||||||
Gain due to involuntary conversion of asset | (3,100 | ) | — | (3,100 | ) | 100 | % | |||||||||
Accretion | 36,421 | 27,410 | 9,011 | 33 | % | |||||||||||
Gain on sale of asset | 38 | (142 | ) | 180 | -127 | % | ||||||||||
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TOTAL OPERATING EXPENSES | 339,296 | 293,271 | 46,025 | 16 | % | |||||||||||
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(LOSS) INCOME FROM OPERATIONS | (34,818 | ) | 46,673 | (81,491 | ) | 175 | % | |||||||||
OTHER INCOME (EXPENSE) | ||||||||||||||||
Interest income | 319 | 373 | (54 | ) | -14 | % | ||||||||||
Miscellaneous (expense) income | (3,504 | ) | (6,253 | ) | 2,749 | -44 | % | |||||||||
Interest expense | (25,965 | ) | (25,752 | ) | (213 | ) | 1 | % | ||||||||
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TOTAL OTHER INCOME (EXPENSE) | (29,150 | ) | (31,632 | ) | 2,482 | -8 | % | |||||||||
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NET (LOSS) INCOME | $ | (63,968 | ) | $ | 15,041 | $ | (79,009 | ) | 525 | % | ||||||
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Production
Oil and natural gas production.Total oil, natural gas and plant product production of 5,281 MBoe decreased 33 MBoe, or 1%, during the year ended December 31, 2012, compared to the same period in 2011. The decrease in production during 2012 was due to lower production in the third quarter of 2012 (196 MBoe), primarily as a result of downtime for Hurricane Isaac, and lower production in the fourth quarter of 2012 (414 MBoe) as a result of downtime in fields requiring hot work, which was delayed due to the BSEE requirement for approval after the West Delta 32 Incident, partially offset by a full year of production of the properties acquired in the Merit Acquisition (872 MBoe).
Revenues
Total revenues.Total revenues for the year ended December 31, 2012 of $304.5 million decreased $35.5 million, or 10%, over the comparable period in 2011. The decrease in revenues during 2012 was a result of lower oil, natural gas and plant product prices. Total revenues were also lower due to a $4.8 million unrealized loss on derivative financial instruments for the year ended December 31, 2012 compared to a $17.6 million unrealized gain for the prior year. The decrease in revenues was partially offset by the $15.3 million increase in realized gain on derivative financial instruments.
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We entered into certain oil and natural gas commodity derivative contracts in 2012 and 2011. We realized gains on these derivative contracts in the amounts of $23.4 million and $8.1 million for the years ended December 31, 2012 and 2011, respectively. We recognized an unrealized loss of $4.8 million and a gain of $17.6 million for the years ended December 31, 2012 and 2011, respectively. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $28.4 million for the year ended December 31, 2012 compared to the same period in 2011 as a result of lower oil and natural gas production from uneconomic leases and several fields being shut-in and lower oil, natural gas and plant product prices.
Excluding hedges, we realized average oil prices of $106.60 per barrel and gas prices of $2.82 per Mcf for the year ended December 31, 2012. Excluding hedges, for the year ended December 31, 2011, we realized average oil prices of $108.09 per barrel and gas prices of $4.18 per Mcf. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2011, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.
Operating Expenses
Lease operating costs.Our lease operating costs for the year ended December 31, 2012 increased to $180.7 million, or $34.22 per Boe, compared to $158.5 million, or $29.83 per Boe, for the same period of 2011. The increase in lease operating costs during 2012 was directly related to the additional properties acquired in the Maritech Acquisition and the Merit Acquisition, including non-recurring safety and regulatory costs on these acquired properties, as well as expenses incurred related to the West Delta 32 Incident. The increase in cost per Boe during 2012 was also primarily attributable to a mix of increased properties and lower production due to Hurricane Isaac and downtime in the fields requiring hot work which was delayed due to the BSEE requirement for approval after the West Delta 32 Incident.
Workover costs.Our workover costs decreased $5.4 million to $18.0 million for the year ended December 31, 2012 compared to $23.4 million for the same period in 2011. For the year ended December 31, 2012, West Cameron 20/45, Eugene Island 156/South Marsh 22, South Pass 86/87/89, West Delta 31/32, Vermilion 119/120/124 and Eugene Island 331 were the primary workover expense projects.
Exploration.Exploration expense was $1.7 million and $1.0 million for the years ended December 31, 2012 and 2011, respectively. We elected to participate in the drilling of the South Pelto Block 13 No. STK BP2 with a 10.33% working interest. The well was designed to test the CP 12B sand. The operator encountered mechanical problems and commenced bypass operations which were unsuccessful. The operator opted to abandon the drilling and the well was deemed non-commercial.
Depreciation, depletion, amortization and impairment.DD&A expense was $47.3 million, or $8.96 per Boe, and $47.2 million, or $8.88 per Boe, for the years ended December 31, 2012 and 2011, respectively. In 2012, the DD&A expense was relatively flat compared to 2011 as a result of an increase in the DD&A rate partially offset by lower production due to uneconomic leases and several fields being shut-in. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $31.0 million and $13.0 million in impairments for the years ended December 31, 2012 and 2011, respectively, as the estimated undiscounted cash flows of oil and gas properties were less than its carrying value on certain properties.
General and administrative expenses.G&A expense was $26.5 million, or $5.02 per Boe, and $22.0 million, or $4.15 per Boe, for the years ended December 31, 2012 and 2011, respectively. The increase in G&A expense was primarily due to higher costs for additional staff and bonding insurance attributable to our 2011 acquisitions. Our legal fees were also higher in 2012 as a result of the West Delta 32 Incident, recapitalization efforts and litigation expense.
Gain due to involuntary conversion of asset.On September 27, 2012, an incident occurred on our High Island 443 A-2 ST well which required the closing of the blind/shear rams to properly shut in and maintain control of the well due to several days of unsuccessful attempts to repair a small hydrocarbon leak on a conductor riser. Additional surface diagnostics found the inner casing strings to be most likely compromised. On October 12, 2012, the BSEE advised us to plug and abandon the well. We filed an insurance claim and costs were reimbursed by our insurance company. We recorded a gain of $3.1 million, after a deductible of $0.5 million.
Accretion expense.We recognized accretion expense of $36.4 million and $27.4 million for the years ended December 31, 2012 and 2011, respectively. The increase in accretion expense in 2012 was attributable to assumed asset retirement obligations related to our acquisitions in 2011.
Miscellaneous expense.Miscellaneous expense decreased $2.7 million to $3.5 million for the year ended December 31, 2012 compared to $6.3 million for the same period in 2011. The higher expense in 2011 was a result of the consent solicitation fee paid under the First Supplemental Indenture.
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Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
The following table sets forth certain information with respect to oil and gas operations for the years ended December 31, 2011 and 2010.
Year Ended December 31, | ||||||||||||||||
2011 | 2010 | Change | % Change | |||||||||||||
PRODUCTION: | ||||||||||||||||
Oil (MBbl) | 1,991 | 857 | 1,134 | 132 | % | |||||||||||
Natural gas (MMcf) | 18,188 | 7,997 | 10,191 | 127 | % | |||||||||||
Plant products (MGal) | 12,257 | 5,403 | 6,854 | 127 | % | |||||||||||
Total (MBoe) | 5,314 | 2,319 | 2,995 | 129 | % | |||||||||||
REVENUES | ||||||||||||||||
Oil sales | $ | 215,204 | $ | 68,654 | $ | 146,550 | 213 | % | ||||||||
Natural gas sales | 75,994 | 34,999 | 40,995 | 117 | % | |||||||||||
Plant product sales and other income | 23,091 | 8,913 | 14,178 | 159 | % | |||||||||||
Realized gain on derivative financial instruments | 8,099 | 9,271 | (1,172 | ) | -13 | % | ||||||||||
Unrealized gain (loss) on derivative financial instruments | 17,556 | (12,700 | ) | 30,256 | 238 | % | ||||||||||
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339,944 | 109,137 | 230,807 | 211 | % | ||||||||||||
OPERATING EXPENSES | ||||||||||||||||
Lease operating | 158,545 | 54,627 | 103,918 | 190 | % | |||||||||||
Production taxes | 859 | 640 | 219 | 34 | % | |||||||||||
Workover | 23,385 | 4,288 | 19,097 | 445 | % | |||||||||||
Exploration | 1,004 | 14 | 990 | 7071 | % | |||||||||||
Depreciation, depletion and amortization | 47,214 | 29,795 | 17,419 | 58 | % | |||||||||||
Impairment | 12,967 | 6,407 | 6,560 | 102 | % | |||||||||||
General and administrative | 22,029 | 14,588 | 7,441 | 51 | % | |||||||||||
Accretion | 27,410 | 9,175 | 18,235 | 199 | % | |||||||||||
Gain on sale of asset | (142 | ) | — | (142 | ) | -100 | % | |||||||||
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TOTAL OPERATING EXPENSES | 293,271 | 119,534 | 173,737 | 145 | % | |||||||||||
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INCOME (LOSS) FROM OPERATIONS | 46,673 | (10,397 | ) | 57,070 | 549 | % | ||||||||||
OTHER INCOME (EXPENSE) | ||||||||||||||||
Interest income | 373 | 129 | 244 | 189 | % | |||||||||||
Miscellaneous (expense) income | (6,253 | ) | (757 | ) | (5,496 | ) | 726 | % | ||||||||
Interest expense | (25,752 | ) | (12,872 | ) | (12,880 | ) | 100 | % | ||||||||
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TOTAL OTHER INCOME (EXPENSE) | (31,632 | ) | (13,500 | ) | (18,132 | ) | 134 | % | ||||||||
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NET INCOME (LOSS) | $ | 15,041 | $ | (23,897 | ) | $ | 38,938 | 163 | % | |||||||
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Production
Oil and natural gas production.Total oil, natural gas and plant product production of 5,314 MBoe increased 2,995 MBoe, or 129%, during the year ended December 31, 2011, compared to the same period in 2010. The increase in production during 2011 was primarily a result of properties acquired in the Nippon Acquisition in September 2010 (1,792 MBoe), the Maritech Acquisition in February 2011 (285 MBoe) and the Merit Acquisition in May 2011 (1,188 MBoe).
Revenues
Total revenues.Total revenues for the year ended December 31, 2011 of $339.9 million increased $230.8 million, or 211%, over the comparable period in 2010. The increase in revenues during 2011 was a result of increased production related to the properties acquired in the Nippon Acquisition ($103.0 million), the Maritech Acquisition ($22.4 million), and the Merit Acquisition ($69.2 million) as well as higher oil prices. Total revenues were also higher due to a $17.6 million unrealized gain on derivative financial instruments for the year ended December 31, 2011 compared to a $12.7 million unrealized loss for the prior year.
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We entered into certain oil and natural gas commodity derivative contracts in 2011 and 2010. We realized gains on these derivative contracts in the amounts of $8.1 million and $9.3 million for the years ended December 31, 2011 and 2010, respectively. We recognized an unrealized gain (loss) of $17.6 million and ($12.7) million for the years ended December 31, 2011 and 2010, respectively. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $201.7 million for the year ended December 31, 2011 compared to the same period in 2010 as a result of increased oil, natural gas and plant products production from the acquisitions and higher oil prices.
Excluding hedges, we realized average oil prices of $108.09 per barrel and gas prices of $4.18 per Mcf for the year ended December 31, 2011. Excluding hedges, for the year ended December 31, 2010, we realized average oil prices of $80.09 per barrel and gas prices of $4.38 per Mcf. Although average prices realized from the sale of oil reflected the economic turnaround that began during 2010, economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.
Operating Expenses
Lease operating costs.Our lease operating costs for the year ended December 31, 2011 increased to $158.5 million, or $29.83 per Boe, compared to $54.6 million, or $23.56 per Boe, for the same period of 2010. The increase in lease operating costs during 2011 was directly related to the increase in properties from the Nippon Acquisition, the Maritech Acquisition and the Merit Acquisition. The increase in cost per Boe during 2011 is primarily attributable to a mix of increased properties and related workover activities.
Workover costs.Our workover costs increased $19.1 million to $23.4 million for the year ended December 31, 2011 compared to $4.3 million for the same period in 2010. For the year ended December 31, 2011, High Island 571, Galveston 424 and South Timbalier 8 were the primary workover expense projects.
Exploration.We elected to participate in the drilling of the South Pelto Block 13 No. STK BP2 with a 10.33% working interest. The well was designed to test the CP 12B sand. The operator encountered mechanical problems and commenced bypass operations which were unsuccessful. The operator opted to abandon the drilling and the well is deemed non-commercial.
Depreciation, depletion, amortization and impairment.DD&A expense was $47.2 million, or $8.88 per Boe, and $29.8 million, or $12.85 per Boe, for the years ended December 31, 2011 and 2010, respectively. In 2011, the increase in DD&A expense was the result of increased production associated with the properties acquired in 2011 and 2010. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded $13.0 million and $6.4 million in impairments for the years ended December 31, 2011 and 2010, respectively, as the estimated undiscounted cash flows of oil and gas properties were less than its carrying value on certain properties.
General and administrative expenses.G&A expense was $22.0 million, or $4.15 per Boe, and $14.6 million, or $6.29 per Boe, for the years ended December 31, 2011 and 2010, respectively. The increase in G&A expense is primarily due to higher costs for additional staff, contract personnel, professional services, bonding insurance and other related administrative costs attributable to our growth in 2011 and 2010.
Accretion expense.We recognized accretion expense of $27.4 million and $9.2 million for the years ended December 31, 2011 and 2010, respectively. The increase in accretion expense in 2011 was attributable to assumed asset retirement obligations related to our acquisitions in 2011 and 2010.
Miscellaneous expense.Miscellaneous expense increased $5.5 million to $6.3 million for the year ended December 31, 2011 compared to $0.8 million for the same period in 2010. The significant increase was a result of the consent solicitation fee paid under the First Supplemental Indenture to the Indenture.
Interest expense.Interest expense increased $12.9 million for the year ended December 31, 2011 compared to the same period in 2010. The increase of interest expense in 2011 compared to 2010 was a result of borrowings under our credit facility to fund the Merit P&A obligation, the issuance of the Notes in November 2010, the proceeds of which were used to fund the Nippon Acquisition and associated escrow deposits for future P&A costs, and amortization of debt issuance costs as a result of the repayment of loans with proceeds from the Notes, which was partially offset by lower fixed interest rates.
Liquidity and Capital Resources
Our primary sources of liquidity to date have been capital contributions from our members, proceeds from the offering of our senior notes, which closed in November 2010, borrowings under our lines of credit and cash flows from operations. We believe that our working capital requirements, contractual obligations and expected capital expenditures discussed below, as well as our other liquidity needs for the next twelve months, can be met from cash flows provided by operations, capital contributions and a $3.1
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million partial payment of insurance reimbursement for P&A costs on the High Island 443 A-2 well (after a deductible of $0.5 million). Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our P&A obligations. We are currently evaluating new sources of liquidity including, but not limited to (i) renegotiating our current revolving credit facility (ii) entering into a new revolving credit facility and (iii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. We continue to review our escrow accounts to determine if there are opportunities to replace our letters of credit, which are 100% cash-backed, with surety bonds.
Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.
Senior Secured Revolving Credit Facility
On December 24, 2010, we entered into an aggregate $110 million credit facility (the “Credit Facility”) with Capital One, N.A., as administrative agent and a lender thereunder. The Credit Facility is comprised of (1) a senior secured reserve-based revolving credit facility (the “Revolving Credit Facility”), under which our initial borrowing base was set at $35 million and (2) a $75 million secured letter of credit facility (the “Letter of Credit Facility”), which is to be used exclusively for the issuance of letters of credit in support of our future P&A obligations relating to our oil and gas properties. The Credit Facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.5% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the borrowing based utilization percentage in effect from time to time. The borrowing base under our Revolving Credit Facility is subject to redetermination on a semi-annual basis, effective April 1 and October 1, and up to one additional time during any six-month period, as may be requested by either us or the administrative agent, acting at the direction of the majority of the lenders. The October 1, 2012 redetermination was completed in November 2012 with no changes to the Revolving Credit Facility. In January 2013, we entered into the sixth amendment to the Credit Facility, which decreased the Revolving Credit Facility available thereunder to $61 million until April 15, 2013, at which time the borrowing base shall be re-determined. The borrowing base will be determined by the administrative agent in its sole discretion and consistent with its normal oil and gas lending criteria in existence at that particular time. Our obligations under the Credit Facility are guaranteed by our existing subsidiaries and are secured on a first-priority basis by all of our and our subsidiaries’ assets, in the case of the Revolving Credit Facility, and by cash collateral, in the case of the Letter of Credit Facility. The Credit Facility has a maturity date of June 22, 2014.
The Credit Facility is subject to certain customary fees and expenses of the lenders and administrative agent thereunder.
The Credit Facility contains customary 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.
The Credit Facility requires that the ratio of our consolidated current assets to our consolidated current liabilities never be less than 1.0 to 1.0. In addition, our Credit Facility requires that as of the end of each quarter, our ratio of consolidated EBITDA to our consolidated interest charges for the four immediately preceding consecutive fiscal quarters never be less than 3.0 to 1.0.
The Credit Facility provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, material inaccuracies of representations and warranties, covenant defaults, cross-defaults to other material indebtedness, including the notes, voluntary and involuntary bankruptcy proceedings, material money judgments, certain change of control events and other customary events of default.
We have entered into various amendments to the Credit Facility. These amendments have (1) changed our amount available for borrowing under the Revolving Credit Facility from $35 million to $25 million, (2) increased the secured letter of credit from $75 million to $200 million, (3) amended certain provisions governing our swap agreements, (4) updated the fees on the letters of credit to 2% on a go-forward basis, (5) updated the “change in control” definition, (6) amended the definition of debt included in the calculation of the covenants, (7) changed the maturity date from December 24, 2013 to June 22, 2014, (8) received a limited waiver for any defaults arising for the noncompliance of the current ratio calculation and the unwinding of certain hedges executed under the BP Swap Agreements as of December 31, 2012, (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 the Platinum Group during the first quarter of 2013 and (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants.
As of December 31, 2012, we were not in compliance with our current ratio covenant, our hedging requirement covenant and our leverage ratio covenant under the Credit Agreement. Our current ratio covenant was calculated to be 0.6 to 1.0, which was lower than the required 1.0 to 1.0. Our hedging requirement of our notional volumes exceeded 75% for the month of January 2013 by 5% of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. Our
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leverage ratio covenant was calculated to be 2.54 to 1.0, which was slightly higher than the maximum 2.5 to 1.0. We received a limited waiver relating to such covenants for the fiscal quarter ended December 31, 2012. The waiver will not apply to any future fiscal quarter. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0. The current ratio covenant has been removed in the Seventh Amendment and the Ninth Amendment and has been replaced with a payables restriction covenant. We paid $0.3 million to obtain the waiver.
As of December 31, 2012, letters of credit in the aggregate amount of $137.4 million were outstanding under the Letter of Credit Facility and we had $52.0 million in borrowings under the Revolving Credit Facility. As of April 10, 2013, we had no funds available for additional borrowings under the Revolving Credit Facility.
For a further discussion of our Credit Facility, please see “Notes to Consolidated Financial Statements—Note 10—Debt and Notes Payable” in this Form 10-K.
13.75 % Senior Secured Notes
On November 23, 2010, we issued $150 million in aggregate principal amount of the Notes discounted at 99.109%. The net proceeds were used to repay all of the outstanding indebtedness under our lines of credit, to fund BOEMRE collateral requirements and to prefund our P&A escrow accounts. We pay interest on the Notes semi-annually, on June 1st and December 1st of each year, in arrears, commencing June 1, 2011. The Notes mature on December 1, 2015.
The Notes are secured by a security interest in the issuers’ and the guarantors’ assets (excluding the escrow accounts set up for the future P&A obligations of the properties acquired in the W&T Acquisition). The liens securing the Notes are subordinated and junior to any first lien indebtedness, including our derivative contracts obligation and Credit Facility.
We have the right or the obligation to redeem the Notes under various conditions. 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 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 31, 2011, we 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 Class D Units that can be repaid over time and (3) obligate us to make an offer to repurchase the Notes semiannually at an offer price equal to 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest to the extent it meets certain defined financial tests and as permitted by our credit facilities.
As of December 31, 2012, we were in compliance with our covenants under the Indenture. As of December 31, 2012, the recorded value of the Notes was $149.1 million, which includes the unamortized discount of $0.9 million.
Member Contributions
On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivable, in exchange for 30 million of our Class D Units. The Class D Units are non-voting units having an aggregate liquidation preference of $30 million and accruing dividends payable in kind at a rate per annum of 24%, compounded annually to the extent they are not distributed. The dividends are expected to be repaid after the Notes mature. At December 31, 2012, Platinum contributed a total of $30.0 million in cash, of which $14.9 million was received during 2012.
On January 25, 2013, we entered into a contribution agreement with PPVA (Equity), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million Class E Units and 76 Class B Units, having such rights, preferences and privileges as set forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. 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 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).
In the first quarter of 2013, we entered into contribution agreements with PPBE or the Platinum Group pursuant to which we have issued, or expect to issue 40 million additional Class E Units and 3 million additional Class B Units to the Platinum Group for an aggregate offering price of $40.0 million. As of April 10, 2013, we have issued an aggregate $50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013, we issued an additional 2,522,693.340 Class E Units as paid-in-kind dividends to the holders of Class E Units on such date.
On February 12, 2013, we entered into an agreement with Platinum under which we agreed to issue Class B Units to Platinum in
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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.
During 2012, we have restated our 2011 consolidated financial statements to report the Class D Cumulative Convertible Participating Preferred Units outside of permanent equity as the redemption feature is conditional, but at the holders’ option. Platinum cannot redeem the units until obligations to bondholders are satisfied. We reflected the necessary adjustments in the fourth quarter of 2012 and calculated the impact on our quarterly reports on Form 10-Q for the quarterly periods ending June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012 and September 30, 2012. For a further discussion of the reclassification, please see “Notes to Consolidated Financial Statements—Note 12—Members’ Deficit” in this Form 10-K.
Capital Expenditures
We have a total capital expenditure budget of $127.2 million (excluding expenditures directly related to any acquisitions) for 2013, which is a 175% increase over the approximately $46.3 million of capital expenditures during 2012. Approximately $25.2 million of our 2013 capital budget was expended in the first two months of 2013 for various projects including recompletions and drilling, and the remaining $71.5 million will be used for drilling and development during the remainder of the year. The capital expenditure limitation set forth in the Indenture was amended in conjunction with the Consent Solicitation on May 31, 2011 to a maximum limit of 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year after December 31, 2011.
Our capital budget may be adjusted as business conditions warrant and the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results 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.
To date, our 2013 capital budget has been funded from cash flow from operations, capital contributions and a $3.6 million partial payment of insurance reimbursement for P&A costs on the High Island 443 A-2 well (before a deductible of $0.5 million). We are currently evaluating new sources of liquidity including, but not limited to (i) renegotiating our current revolving credit facility (ii) entering into a new revolving credit facility and (iii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. We continue to review our escrow accounts to determine if there are opportunities to replace our letters of credit, which are 100% cash-backed, with surety bonds. We believe the cash flow from operations, $50 million in capital contributions, insurance reimbursement on the P&A costs on the High Island 443 A-2 well and drilling of the replacement well, High Island 443 A-5 ST, along with new sources of liquidity described above should be sufficient to fund our 2013 capital expenditure budget.
We expect that our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “—Oil and Natural Gas Hedging” and “—Quantitative and Qualitative Disclosures About Market Risk.”
We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
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Cash Flows
The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the years ended December 31, 2012, 2011 and 2010 (in thousands):
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Net cash provided by (used in) operating activities | $ | 66,054 | $ | 73,647 | $ | 28,345 | ||||||
Net cash used in investing activities | (89,723 | ) | (108,641 | ) | (114,815 | ) | ||||||
Net cash provided by financing activities | 7,792 | 33,375 | 99,113 | |||||||||
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Net (decrease) increase in cash and equivalents | $ | (15,877 | ) | $ | (1,619 | ) | $ | 12,643 | ||||
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Cash flows provided by operating activities. Cash provided by operating activities totaling $66.1 million in 2012 compared to $73.6 million during 2011. Significant components of net cash provided by operating activities during the year ended December 31, 2012 included $122.1 million of non-cash items, primarily DD&A expense, impairment of oil and gas properties and accretion of asset retirement obligations as well as $8.0 million of changes in operating assets and liabilities, partially offset by a net loss of $64.0 million as a result of lower oil and gas production and prices and higher lease operating costs. The cash provided by operating activities in 2011 of $73.6 million, an increase of $45.3 million from the same period in 2010, was primarily attributed to higher net income as a result of the 2010 and 2011 acquisitions.
Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” below.
Cash flows used in investing activities. Cash used in investing activities totaling $89.7 million in 2012 was primarily attributable to additions to the oil and gas properties and the funding of the future P&A obligations through escrow. The cash used in investing activities in 2011 is primarily attributable to the assets purchased in the Maritech Acquisition and Merit Acquisition and the funding of the future P&A obligations through escrow. Cash used in investing activities in 2010 is attributable to the assets purchased in the Nippon Acquisition and the funding of the collateral requirements securing our P&A obligations with respect to the acquired properties and the W&T Escrow Accounts. The Nippon assets were purchased on September 30, 2010.
Cash flows provided by financing activities. Cash flows provided by financing activities of $7.8 million in 2012 were attributable to borrowings under the Credit Facility and short-term notes partially offset by payments on the Credit Facility and short-term notes, tax distributions to members, and debt issue costs. Cash flows provided by financing activities of $33.4 million in 2011 were attributable to borrowing on the Credit Facility and short term notes as well as a $30 million contribution from Platinum, which were partially offset by payments on the Credit Facility, debt issuance costs of the Notes, and tax distributions to members. Cash flows provided by financing activities in 2010 were attributable to the issuance of the notes partially offset by the repayment of borrowings under our lines of credit with Platinum.
W&T Escrow Accounts
On September 14, 2009, we completed the W&T Acquisition, pursuant to which we acquired certain oil, natural gas and mineral interests and leases, along with related wells, infrastructure, equipment, information and other rights and assets. In connection with the W&T Acquisition, the parties identified certain of the acquired properties as “Operated Properties” and the remaining properties as “Non-Operated Properties.”
As a condition to W&T’s willingness to sell the W&T Properties to us, we were required to provide adequate financial assurance of our ability to pay for the costs of plugging and abandoning and/or removing wells, platforms, facilities, pipelines and other equipment related to the W&T Properties. Accordingly, we were required to, among other things, (i) establish separate escrow accounts with respect to the Operated Properties and the Non-Operated Properties, (ii) make monthly contributions to each escrow account according to stipulated payments schedules until such accounts are fully funded to a maximum aggregate principal amount of $63.8 million, (iii) grant a second priority security interest to W&T on the W&T Properties and (iv) deliver, or cause to be delivered, a performance and payment guarantee from Platinum to W&T with respect to future P&A obligations associated with the Operated Properties and our obligation to fund the Operated Properties Escrow Account.
We used $20 million of the net proceeds of the Senior Notes Offering to prefund the W&T Escrow Accounts. As a result of this prefunding payment, the Operated Properties Escrow Account is now fully funded and we therefore have no further obligation to fund the Operated Properties Escrow Account. Platinum’s guarantee of our funding obligations under the Operated Properties Escrow Account terminated upon the full funding of the Operated Properties Escrow Account. The Non-Operated Properties Escrow Account has not been
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fully funded but in exchange for our prefunding, our obligation to make further payments to this account has been suspended for one year. Our funding obligations re-commenced on December 1, 2011, on which date we were required to make an initial payment of $0.2 million to the Non-Operated Properties Escrow Account, to be followed by payments of $0.3 million per month. Pursuant to this stipulated payment schedule, the Non-Operated Properties Escrow Account will be fully funded by the end of 2017.
In exchange for our agreement to prefund the W&T Escrow Accounts, W&T agreed to amend the documents relating to the acquisition of the W&T Properties to fully release, with respect to the Operated Properties, or subordinate, with respect to the Non-Operated Properties, its existing security interests and mortgages on such properties and allow us to grant new, second liens on those assets to the benefit of the holders of the notes (the “W&T Amendments”). Accordingly, the collateral for the notes includes all of the Operated Properties and Non-Operated Properties acquired in the W&T Acquisition, except for certain properties that were previously released or relinquished. W&T retained a third lien on the Non-Operated Properties.
Until the Non-Operated Properties Escrow Account has been fully funded (and therefore both W&T Escrow Accounts are fully funded), we are not permitted to withdraw cash to fund, or as reimbursement for, our P&A obligations with respect to the W&T Properties (i) from the Operated Properties Escrow Account without the consent of W&T or (ii) from the Non-Operated Properties Escrow Account.
W&T has a first priority lien on the Escrow Accounts, with the administrative agent under our credit facility holding a second lien for the benefit of the lenders under such facility and our derivatives counterparty. Our agreement with W&T prohibits the creation of any additional liens on the W&T Escrow Accounts, other than the liens described above.
On December 19, 2012, we entered into a Third Amendment with W&T. Pursuant to the Third Amendment, we caused 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 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.
Nippon Surety Bonds
On September 30, 2010, we completed the Nippon Acquisition in which we assumed $57.4 million in asset retirement obligations related to P&A obligations associated with the Nippon Properties. We fully funded the P&A obligations through surety bonds. The cancelation of the bonds will only be allowed once all P&A obligations relating to the properties have been fully performed and Nippon has given its consent.
Maritech Escrow Account
Pursuant to the purchase agreement for the Maritech Acquisition, we are required to fund an escrow account (the “Maritech Escrow Account”), relating to the Maritech Properties, the principal amount of $13.1 million for future P&A costs that may be incurred on such properties. As of December 31, 2012, we have funded $8.0 million, leaving $5.1 million to be funded through February 2014. Maritech will allow us to withdraw funds from the escrow account if all P&A obligations have been satisfied for any particular well or related asset on a lease.
Merit Escrow Account
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 aggregate principal 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 the first day of the first month following closing. As of December 31, 2012, we have funded $38.1 million, leaving $21.9 million to be funded through November 2013. We will be allowed to withdraw amounts from the escrow account for reimbursement of our P&A obligations relating to any particular well or asset on a lease once we obtain a consent from Merit and we have deposited $60 million in the escrow account.
Asset Retirement Obligations
As many as four times per year, we review and, to the extent necessary, revise our asset retirement obligation estimates. In 2012, our asset retirement obligation increased by $56.8 million primarily as a result of our revaluation of our P&A liability, which included updates to our estimates as well as expected useful life. In 2012, we also recognized $36.4 million in accretion expense. In 2011, we
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increased our asset retirement obligation by $166.4 million primarily as a result of the Maritech Acquisition and Merit Acquisition and we recognized $27.4 million in accretion expense. In 2010, we increased our asset retirement obligations by $70.9 million, primarily as a result of the Nippon Acquisition, and recognized $9.2 million in accretion expense.
At December 31, 2012 and 2011, we recorded total asset retirement obligations of $345.5 million and $288.7 million, respectively, and have funded approximately $215.3 million and $172.2 million, respectively, in collateral to secure our P&A obligations, inclusive of performance bonds. As of December 31, 2012 and 2011, we also have a guaranteed escrow amount of $20.3 million for certain fields which will be refunded to us once we have completed our P&A obligations on the entire field. The escrow is guaranteed by TETRA Technologies, Inc.
Contractual Obligations
We have various contractual obligations in the normal course of our operations and financing activities. The following schedule summarizes our contractual obligations and other contractual commitments at December 31, 2012.
Payments Due by Period | ||||||||||||||||||||
Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | After 5 Years | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Contractual Obligations | ||||||||||||||||||||
Total debt and notes payable | $ | 205,552 | $ | 3,552 | $ | 202,000 | $ | — | $ | — | ||||||||||
Interest on debt and notes payable | 63,615 | 22,979 | 40,636 | — | — | |||||||||||||||
Operating leases (1) | 42,859 | 30,689 | 4,254 | 3,303 | 4,613 | |||||||||||||||
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Total contractual obligations | 312,026 | 57,220 | 246,890 | 3,303 | 4,613 | |||||||||||||||
Other Obligations | ||||||||||||||||||||
Asset retirement obligations (2) | 345,505 | 41,572 | 135,541 | 35,569 | 132,823 | |||||||||||||||
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Total obligations (3) | $ | 657,531 | $ | 98,792 | $ | 382,431 | $ | 38,872 | $ | 137,436 | ||||||||||
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(1) | Consists of office space leases for our Houston, Texas offices and services provided in the office. |
(2) | Asset retirement obligations will be partially funded via the escrow. |
(3) | Does not include Class D Cumulative Convertible Participating Preferred Units as they are redeemable at the holders’ option. |
Off-Balance Sheet Arrangements
In October 2010, we guaranteed a loan that a related party used to purchase two helicopters in the aggregate principal amount of $3.2 million. The related party is not consolidated in our financials as the entity is not material to us (see “Item 14. Certain Relationships and Related Transactions and Director Independence”). On August 1, 2012, a purchase agreement was signed to sell certain aircraft equipment from the related party. The proceeds of the sale were applied to the balance of the guaranteed loan. The loan was repaid in full on December 28, 2012. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.
Oil and Gas Hedging
As part of our risk management program, we hedge a portion of our anticipated oil and natural gas production to reduce our exposure to fluctuations in oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions.
While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions
At December 31, 2012, commodity derivative instruments were in place covering approximately 66% of our projected oil sales volumes and 28% of our projected natural gas volumes through 2013.
Please see “Notes to Consolidated Financial Statements—Note 8—Derivative Instruments” for additional discussion regarding the accounting applicable to our hedging program.
Critical Accounting Policies
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” is based upon our consolidated financial statements, which have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”). The preparation of these statements requires that we make estimates and assumptions that affect the reported amounts of
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assets, liabilities, revenues and expenses. We base these estimates on historical experience and on assumptions that we consider reasonable under the circumstances; however, reported results could differ from the current estimates under different assumptions and/or conditions. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience, current market factors and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements.
Oil and Natural Gas Properties
We account for oil and natural gas properties using the successful efforts method of accounting. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are those costs incurred to operate and maintain our wells and related equipment and facilities and are expensed as incurred.
Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated at least bi-annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. Depletion is calculated each quarter based upon the latest estimated reserves data available. Asset retirement obligations are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement obligations are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well, the proceeds are credited to accumulated depletion and depreciation.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.
Oil and Natural Gas Reserve Quantities: Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our independent engineering firm prepares a reserve and economic evaluation of all our properties on a well-by-well basis utilizing information provided to it by us and information available from state agencies that collect information reported to it by the operators of our properties. The estimate of our proved reserves as of December 31, 2012, 2011 and 2010 has been prepared and presented in accordance with SEC rules and accounting standards which use pricing based on 12-month unweighted first-day-of-the-month average pricing.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.
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Derivative Financial Instruments: In accordance with authoritative guidance for derivatives and hedges, all derivative instruments are measured periodically and at year end and are recorded on the consolidated balance sheets at fair value. Derivative contracts that are designated as part of a qualifying cash flow hedge, per the requirements for cash flow hedges, are granted hedge accounting thereby allowing us to treat the effective changes in the fair value of the derivative instrument in accumulated other comprehensive income, while recording the ineffective portion as an adjustment to unrealized gain (loss). Derivative contracts that are not designated as part of a valid qualifying hedge or fail to meet the requirements of the pronouncement as a highly effective hedge, are treated by recording the changes in the fair value from period to period, through earnings. The amounts paid or received upon each monthly settlement, are recorded as derivative gain (loss) with the offset recorded to cash. These monthly settlements are included in oil and gas revenue on our consolidated statements of operations.
For the years ended December 31, 2012, 2011 and 2010, 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 gains (losses) recorded in the consolidated statements of operations.
Asset Retirement Obligations: Authoritative guidance for asset retirement obligations uses a cumulative effect approach to recognize transition amounts for asset retirement obligations and accumulated depreciation. The accounting guidance requires companies to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as part of the cost of the related oil and natural gas properties. We recognize the legal obligation of the dismantlement, restoration and abandonment costs associated with our oil and natural gas properties with our asset retirement obligation. These costs are impacted by our estimated remaining life as well as current market conditions associated with these costs.
Liabilities for expenditures of a noncapital nature are recorded when environmental assessment or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.
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. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.
Inflation and Changes in Prices
Our revenues, the value of our assets, and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. For the years ended December 31, 2012, 2011 and 2010, we received an average of $106.60, $108.09 and $80.09 per barrel of oil, respectively, and $2.82, $4.18 and $4.38 per Mcf of natural gas, respectively, before consideration of commodity derivative contracts. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the first six months of 2008, commodity prices for oil and natural gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends have put pressure not only on our operating costs but also on capital costs. During 2012, commodity prices have softened and services and costs have not decreased in proportion to the lower prices. Higher costs are partially fueled by unconventional plays onshore as well as resource shifts out of the Gulf of Mexico.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to a variety of market risks including commodity price risk, credit risk and interest rate risk. We address these risks through a program of risk management, which may include the use of derivative instruments.
The following quantitative and qualitative information is provided about financial instruments to which we are a party, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit.
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Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
Commodity Price Risk
Our primary market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our total annual production for the year ended December 31, 2012, our annual revenue would increase or decrease by approximately $19.8 million for each $10.00 per barrel change in oil prices and $17.9 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging. Based on our total annual production for the year ended December 31, 2011, our revenues would have increased or decreased by approximately $19.9 million for each $10.00 per barrel change in oil prices and $18.2 million for each $1.00 per MMBtu change in natural gas prices without giving effect to any hedging.
To partially reduce price risk caused by these market fluctuations, we hedge a significant portion of our anticipated oil and natural gas production as part of our risk management program. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions.
At December 31, 2012, the fair value of our commodity derivatives were included in our consolidated balance sheets for approximately $2.4 million as current assets and $5.1 million as long-term liabilities. At December 31, 2011, the fair value of our commodity derivatives was approximately $4.2 million and $2.1 million, which were recorded as current assets and long-term liabilities, respectively, in the consolidated balance sheets. For the years ended December 31, 2012, 2011 and 2010, we realized a net increase in oil and natural gas revenues related to hedging transactions of approximately $23.4 million, $8.1 million and $9.3 million, respectively.
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As of December 31, 2012, we maintained the following commodity derivative contracts:
Remaining Contract Term: Oil | Contract Type | Notational Volume in Bbls/Month | NYMEX Strike Price | |||||||||
December 2013 - December 2013 | Swap | 27,750 | $ | 96.90 | ||||||||
January 2013 - October 2013 | Swap | 27,750 | $ | 96.90 | ||||||||
November 2013 - November 2013 | Swap | 26,800 | $ | 96.90 | ||||||||
January 2013 - December 2013 | Swap | 19,750 | $ | 85.90 | ||||||||
January 2014 - February 2014 | Swap | 19,000 | $ | 96.90 | ||||||||
January 2013 - June 2013 | Swap | 15,542 | $ | 100.80 | ||||||||
January 2014 - December 2014 | Swap | 15,000 | $ | 65.00 | ||||||||
January 2014 - May 2014 | Swap | 10,083 | $ | 100.80 | ||||||||
December 2013 - December 2013 | Swap | 10,042 | $ | 100.80 | ||||||||
July 2013 - July 2013 | Swap | 7,132 | $ | 100.80 | ||||||||
August 2013 - August 2013 | Swap | 5,980 | $ | 100.80 | ||||||||
September 2013 - September 2013 | Swap | 3,897 | $ | 100.80 | ||||||||
October 2013 - October 2013 | Swap | 3,259 | $ | 100.80 | ||||||||
January 2013 - January 2013 | Swap | 9,042 | $ | 88.80 | ||||||||
February 2013 - February 2013 | Swap | 23,522 | $ | 88.80 | ||||||||
March 2013 - March 2013 | Swap | 16,792 | $ | 88.80 | ||||||||
April 2013 - April 2013 | Swap | 23,812 | $ | 88.80 | ||||||||
May 2013 - May 2013 | Swap | 24,012 | $ | 88.80 | ||||||||
June 2013 - June 2013 | Swap | 29,752 | $ | 88.80 | ||||||||
July 2013 - July 2013 | Swap | 23,143 | $ | 88.80 | ||||||||
August 2013 - August 2013 | Swap | 24,915 | $ | 88.80 | ||||||||
September 2013 - September 2013 | Swap | 28,688 | $ | 88.80 | ||||||||
October 2013 - October 2013 | Swap | 28,006 | $ | 88.80 | ||||||||
November 2013 - November 2013 | Swap | 31,605 | $ | 88.80 | ||||||||
December 2013 - December 2013 | Swap | 38,743 | $ | 88.80 | ||||||||
January 2014 - January 2014 | Swap | 4,723 | $ | 88.80 | ||||||||
February 2014 - February 2014 | Swap | 13,313 | $ | 88.80 | ||||||||
March 2014 - March 2014 | Swap | 8,413 | $ | 88.80 | ||||||||
April 2014 - April 2014 | Swap | 12,473 | $ | 88.80 | ||||||||
May 2014 - May 2014 | Swap | 11,793 | $ | 88.80 | ||||||||
June 2014 - June 2014 | Swap | 15,546 | $ | 88.80 | ||||||||
July 2014 - July 2014 | Swap | 11,845 | $ | 88.80 | ||||||||
August 2014 - August 2014 | Swap | 13,165 | $ | 88.80 | ||||||||
September 2014 - September 2014 | Swap | 16,235 | $ | 88.80 | ||||||||
October 2014 - October 2014 | Swap | 15,605 | $ | 88.80 | ||||||||
November 2014 - November 2014 | Swap | 18,525 | $ | 88.80 | ||||||||
December 2014 - December 2014 | Swap | 22,526 | $ | 88.80 | ||||||||
January 2013 - January 2013 | Swap | 66,000 | $ | 87.85 | ||||||||
February 2013 - February 2013 | Swap | 34,000 | $ | 87.85 | ||||||||
March 2013 - March 2013 | Swap | 50,000 | $ | 87.85 | ||||||||
April 2013 - April 2013 | Swap | 35,000 | $ | 87.85 | ||||||||
May 2013 - May 2013 | Swap | 36,000 | $ | 87.85 | ||||||||
June 2013 - June 2013 | Swap | 23,000 | $ | 87.85 | ||||||||
July 2013 - July 2013 | Swap | 15,000 | $ | 87.85 | ||||||||
August 2013 - August 2013 | Swap | 11,000 | $ | 87.85 | ||||||||
September 2013 - September 2013 | Swap | 20,000 | $ | 87.85 | ||||||||
October 2013 - October 2013 | Swap | 4,000 | $ | 87.85 | ||||||||
November 2013 - November 2013 | Swap | 250 | $ | 87.85 | ||||||||
December 2013 - December 2013 | Swap | 2,500 | $ | 87.85 | ||||||||
January 2014 - January 2014 | Swap | 46,000 | $ | 87.85 | ||||||||
February 2014 - February 2014 | Swap | 25,000 | $ | 87.85 | ||||||||
March 2014 - March 2014 | Swap | 56,000 | $ | 87.85 | ||||||||
April 2014 - April 2014 | Swap | 45,000 | $ | 87.85 | ||||||||
May 2014 - May 2014 | Swap | 46,000 | $ | 87.85 | ||||||||
June 2014 - June 2014 | Swap | 48,000 | $ | 87.85 | ||||||||
July 2014 - July 2014 | Swap | 36,000 | $ | 87.85 | ||||||||
August 2014 - August 2014 | Swap | 34,000 | $ | 87.85 | ||||||||
September 2014 - September 2014 | Swap | 26,000 | $ | 87.85 | ||||||||
October 2014 - October 2014 | Swap | 27,000 | $ | 87.85 | ||||||||
November 2014 - November 2014 | Swap | 20,000 | $ | 87.85 | ||||||||
December 2014 - December 2014 | Swap | 31,000 | $ | 87.85 | ||||||||
September 2013 - September 2013 | Swap | (17,500 | ) | $ | 89.15 |
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Remaining Contract Term: Natural Gas | Contract Type | Notational Volume in MMBtus/Month | NYMEX Strike Price | |||||||||
January 2013 - June 2013 | Swap | 200,669 | $ | 4.94 | ||||||||
July 2013 - July 2013 | Swap | 148,788 | $ | 4.94 | ||||||||
August 2013 - August 2013 | Swap | 139,212 | $ | 4.94 | ||||||||
January 2014 - June 2014 | Swap | 129,960 | $ | 4.94 | ||||||||
December 2013 - December 2013 | Swap | 119,462 | $ | 4.94 | ||||||||
September 2013 - September 2013 | Swap | 116,125 | $ | 4.94 | ||||||||
January 2013 - December 2013 | Swap | 104,000 | $ | 4.60 | ||||||||
October 2013 - October 2013 | Swap | 91,166 | $ | 4.94 | ||||||||
January 2014 - February 2014 | Swap | 82,000 | $ | 4.60 | ||||||||
November 2013 - November 2013 | Swap | 64,926 | $ | 4.94 | ||||||||
January 2013 - December 2013 | Swap | 47,000 | $ | 5.00 |
Subsequent to December 31, 2012, we entered into the following derivatives:
Remaining Contract Term: Natural Gas | Contract Type | Notational Volume in MMBtus/Month | NYMEX Strike Price | |||||||||
April 2013 - April 2013 | Swap | 56,381 | 4.085 | |||||||||
May 2013 - May 2013 | Swap | 54,278 | 4.085 | |||||||||
June 2013 - June 2013 | Swap | 25,731 | 4.085 | |||||||||
July 2013 - July 2013 | Swap | 36,765 | 4.085 | |||||||||
August 2013 - August 2013 | Swap | 34,275 | 4.085 | |||||||||
September 2013 - September 2013 | Swap | 31,739 | 4.085 | |||||||||
October 2013 - October 2013 | Swap | 34,551 | 4.085 | |||||||||
November 2013 - November 2013 | Swap | 28,939 | 4.085 | |||||||||
December 2013 - December 2013 | Swap | 37,906 | 4.085 | |||||||||
January 2014 - January 2014 | Swap | 43,347 | 4.085 | |||||||||
February 2014 - February 2014 | Swap | 32,636 | 4.085 | |||||||||
March 2014 - March 2014 | Swap | 46,764 | 4.085 | |||||||||
April 2014 - April 2014 | Swap | 41,253 | 4.085 | |||||||||
May 2014 - May 2014 | Swap | 40,391 | 4.085 | |||||||||
June 2014 - June 2014 | Swap | 20,112 | 4.085 | |||||||||
July 2014 - July 2014 | Swap | 39,283 | 4.085 | |||||||||
August 2014 - August 2014 | Swap | 34,246 | 4.085 | |||||||||
September 2014 - September 2014 | Swap | 29,753 | 4.085 | |||||||||
October 2014 - October 2014 | Swap | 28,635 | 4.085 | |||||||||
November 2014 - November 2014 | Swap | 27,081 | 4.085 | |||||||||
December 2014 - December 2014 | Swap | 34,114 | 4.085 | |||||||||
January 2015 - January 2015 | Swap | 27,838 | 4.085 | |||||||||
February 2015 - February 2015 | Swap | 24,461 | 4.085 | |||||||||
March 2015 - March 2015 | Swap | 26,443 | 4.085 | |||||||||
June 2014 - June 2014 | Swap | 40,391 | 4.185 | |||||||||
July 2014 - July 2014 | Swap | 20,112 | 4.185 | |||||||||
August 2014 - August 2014 | Swap | 39,283 | 4.185 | |||||||||
September 2014 - September 2014 | Swap | 34,246 | 4.185 | |||||||||
October 2014 - October 2014 | Swap | 29,753 | 4.185 | |||||||||
November 2014 - November 2014 | Swap | 28,635 | 4.185 | |||||||||
December 2014 - December 2014 | Swap | 27,081 | 4.185 | |||||||||
January 2015 - January 2015 | Swap | 34,114 | 4.185 | |||||||||
February 2015 - February 2015 | Swap | 27,838 | 4.185 | |||||||||
March 2015 - March 2015 | Swap | 24,461 | 4.185 |
For further discussion of our hedging activities, please see “Notes to Consolidated Financial Statements - Note 8 - Derivative Instruments” included in this Form 10-K.
Credit Risk
We monitor our risk of loss associated with non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables which totaled $17.8 million at December 31, 2012 and $10.5 million at
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December 31, 2011. Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have an interest. We also have exposure to credit risk from the sale of our oil and natural gas production that we market to energy marketing companies and refineries; the receivables totaled $27.2 million at December 31, 2012 and $35.9 million at December 31, 2011.
In order to minimize our exposure to credit risk, we request prepayment of costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. In addition, we monitor our exposure to counterparties on oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We historically have not required our counterparties to provide collateral to support oil and natural gas sales receivables owed to us.
Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under our Revolving Credit Facility, which bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate, plus applicable margins ranging from 2.75% to 3.5%, or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the grid when the borrowing based utilization percentage is at its highest level. Based on the $52.0 million outstanding under the Revolving Credit Facility as of December 31, 2012, an increase of 100 basis points in the underlying interest rate would have had a $0.5 million impact on our annual interest expense. However, there is no guarantee that we will not borrow additional amounts under the Revolving Credit Facility in the future, and, in the event we borrow amounts and interest rates significantly increase, the interest that we would be required to pay would be more significant. We do not believe our variable interest rate exposure warrants entry into interest rate hedges and, therefore, we have not hedged our interest rate exposure. However, to reduce our exposure to changes in interest rates for our borrowings under the Revolving Credit Facility, we may in the future enter into interest rate risk management arrangements for a portion of our outstanding debt to alter our interest rate exposure. See “—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility” for additional information on our Revolving Credit Facility.
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Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
66 | ||||
67 | ||||
As of December 31, 2012 and 2011 | ||||
68 | ||||
Years Ended December 31, 2012, 2011 and 2010 | ||||
69 | ||||
Years Ended December 31, 2012, 2011 and 2010 | ||||
70 | ||||
Years Ended December 31, 2012, 2011 and 2010 | ||||
71 |
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Report of Independent Registered Public Accounting Firm
To the Members of
Black Elk Energy Offshore Operations, LLC:
We have audited the accompanying consolidated balance sheets of Black Elk Energy Offshore Operations, LLC and Subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, members’ deficit and cash flows for each of the three years in the period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board of the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Black Elk Energy Offshore Operations, LLC and Subsidiaries as of December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 12, the 2011 consolidated financial statements have been restated to report Class D Cumulative Convertible Participating Preferred Units outside of permanent members’ deficit.
/s/ UHY LLP
Houston, Texas
April 15, 2013
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, 2012 | December 31, 2011 | |||||||
(restated) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents | $ | 1,383 | $ | 17,260 | ||||
Accounts receivable, net of allowance for doubtful accounts of $509 at December 31, 2012 | 49,653 | 52,299 | ||||||
Due from affiliates | 347 | 163 | ||||||
Prepaid expenses and other | 28,381 | 26,637 | ||||||
Derivative assets | 2,408 | 4,216 | ||||||
|
|
|
| |||||
TOTAL CURRENT ASSETS | 82,172 | 100,575 | ||||||
|
|
|
| |||||
OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $191,326 and $114,056 at December 31, 2012 and 2011, respectively | 260,012 | 238,702 | ||||||
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $1,717 and $870 at December 31, 2012 and 2011, respectively | 1,968 | 2,245 | ||||||
OTHER ASSETS | ||||||||
Debt issue costs, net | 6,972 | 8,726 | ||||||
Asset retirement obligation escrow receivable | 20,348 | 20,348 | ||||||
Escrow for abandonment costs | 215,263 | 172,153 | ||||||
Other assets | 3,729 | 3,257 | ||||||
|
|
|
| |||||
TOTAL OTHER ASSETS | 246,312 | 204,484 | ||||||
|
|
|
| |||||
TOTAL ASSETS | $ | 590,464 | $ | 546,006 | ||||
|
|
|
| |||||
LIABILITIES AND MEMBERS’ DEFICIT | ||||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable and accrued expenses | $ | 108,736 | $ | 72,309 | ||||
Asset retirement obligations | 41,572 | 15,238 | ||||||
Current portion of debt and notes payable | 3,552 | 4,154 | ||||||
|
|
|
| |||||
TOTAL CURRENT LIABILITIES | 153,860 | 91,701 | ||||||
|
|
|
| |||||
LONG-TERM LIABILITIES | ||||||||
Gas imbalance payable | 2,521 | 1,362 | ||||||
Dividends payable | 12,408 | �� | 4,200 | |||||
Derivative liabilities | 5,091 | 2,116 | ||||||
Asset retirement obligations, net of current portion | 303,933 | 273,448 | ||||||
Debt, net of current portion, net of unamortized discount of $882 and $1,113 at December 31, 2012 and 2011, respectively | 201,118 | 172,887 | ||||||
|
|
|
| |||||
TOTAL LONG-TERM LIABILITIES | 525,071 | 454,013 | ||||||
|
|
|
| |||||
TOTAL LIABILITIES | 678,931 | 545,714 | ||||||
CLASS D CUMULATIVE CONVERTIBLE PARTICIPATING PREFERRED UNITS | 30,000 | 30,000 | ||||||
COMMITMENTS AND CONTINGENCIES | ||||||||
MEMBERS’ DEFICIT | (118,467 | ) | (29,708 | ) | ||||
|
|
|
| |||||
TOTAL LIABILITIES AND MEMBERS’ DEFICIT | $ | 590,464 | $ | 546,006 | ||||
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
REVENUES: | ||||||||||||
Oil sales | $ | 210,720 | $ | 215,204 | $ | 68,654 | ||||||
Natural gas sales | 50,470 | 75,994 | 34,999 | |||||||||
Plant product sales and other revenue | 24,707 | 23,091 | 8,913 | |||||||||
Realized gain on derivative financial instruments | 23,364 | 8,099 | 9,271 | |||||||||
Unrealized (loss) gain on derivative financial instruments | (4,783 | ) | 17,556 | (12,700 | ) | |||||||
|
|
|
|
|
| |||||||
TOTAL REVENUES | 304,478 | 339,944 | 109,137 | |||||||||
OPERATING EXPENSES: | ||||||||||||
Lease operating | 180,691 | 158,545 | 54,627 | |||||||||
Production taxes | 745 | 859 | 640 | |||||||||
Workover | 17,986 | 23,385 | 4,288 | |||||||||
Exploration | 1,682 | 1,004 | 14 | |||||||||
Depreciation, depletion and amortization | 47,314 | 47,214 | 29,795 | |||||||||
Impairment | 31,033 | 12,967 | 6,407 | |||||||||
General and administrative | 26,486 | 22,029 | 14,588 | |||||||||
Gain due to involuntary conversion of asset | (3,100 | ) | — | — | ||||||||
Accretion | 36,421 | 27,410 | 9,175 | |||||||||
Loss (gain) on sale of asset | 38 | (142 | ) | — | ||||||||
|
|
|
|
|
| |||||||
TOTAL OPERATING EXPENSES | 339,296 | 293,271 | 119,534 | |||||||||
|
|
|
|
|
| |||||||
(LOSS) INCOME FROM OPERATIONS | (34,818 | ) | 46,673 | (10,397 | ) | |||||||
OTHER INCOME (EXPENSE): | ||||||||||||
Interest income | 319 | 373 | 129 | |||||||||
Miscellaneous expense | (3,504 | ) | (6,253 | ) | (757 | ) | ||||||
Interest expense | (25,965 | ) | (25,752 | ) | (12,872 | ) | ||||||
|
|
|
|
|
| |||||||
TOTAL OTHER EXPENSE | (29,150 | ) | (31,632 | ) | (13,500 | ) | ||||||
|
|
|
|
|
| |||||||
NET (LOSS) INCOME | (63,968 | ) | 15,041 | (23,897 | ) | |||||||
PREFERRED UNIT DIVIDENDS | 8,208 | 4,200 | — | |||||||||
|
|
|
|
|
| |||||||
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS | $ | (72,176 | ) | $ | 10,841 | $ | (23,897 | ) | ||||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ DEFICIT
(in thousands)
Retained | Total | |||||||||||
Earnings | Members’ | |||||||||||
Members’ | (Accumulated | Equity | ||||||||||
Capital | Deficit) | (Deficit) | ||||||||||
Balance at December 31, 2009 | $ | 826 | $ | 4,896 | $ | 5,722 | ||||||
Distribution | (2,435 | ) | — | (2,435 | ) | |||||||
Net loss | — | (23,897 | ) | (23,897 | ) | |||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2010 | (1,609 | ) | (19,001 | ) | (20,610 | ) | ||||||
Distribution | (19,939 | ) | — | (19,939 | ) | |||||||
Dividends | — | (4,200 | ) | (4,200 | ) | |||||||
Net income | — | 15,041 | 15,041 | |||||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2011 (restated) | (21,548 | ) | (8,160 | ) | (29,708 | ) | ||||||
Contribution | 110 | — | 110 | |||||||||
Distribution | (16,693 | ) | — | (16,693 | ) | |||||||
Dividends | — | (8,208 | ) | (8,208 | ) | |||||||
Net loss | — | (63,968 | ) | (63,968 | ) | |||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2012 | $ | (38,131 | ) | $ | (80,336 | ) | $ | (118,467 | ) | |||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net (loss) income | $ | (63,968 | ) | $ | 15,041 | $ | (23,897 | ) | ||||
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities: | ||||||||||||
Depreciation, depletion, and amortization | 47,314 | 47,214 | 29,795 | |||||||||
Impairment of oil and gas properties | 31,033 | 12,967 | 6,407 | |||||||||
Accretion of asset retirement obligations | 36,421 | 27,410 | 9,175 | |||||||||
Amortization of debt issue cost | 4,777 | 2,915 | 834 | |||||||||
Accretion of debt discount | 232 | 203 | — | |||||||||
Unrealized loss (gain) on derivative instruments | 4,783 | �� | (17,556 | ) | 12,700 | |||||||
Loss (gain) on sale of assets | 38 | (142 | ) | — | ||||||||
Provision on doubtful accounts | 509 | — | — | |||||||||
Gain on involuntary conversion of assets | (3,100 | ) | — | — | ||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | 5,238 | (26,348 | ) | (15,591 | ) | |||||||
Due to/from affiliates, net | (185 | ) | 413 | (413 | ) | |||||||
Prepaid expenses and other assets | (1,744 | ) | (13,513 | ) | (12,613 | ) | ||||||
Accounts payable and accrued expenses | 36,427 | 38,199 | 22,687 | |||||||||
Gas imbalance | 999 | (4,748 | ) | 468 | ||||||||
Settlement of asset retirement obligations | (32,720 | ) | (8,408 | ) | (1,207 | ) | ||||||
|
|
|
|
|
| |||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES | 66,054 | 73,647 | 28,345 | |||||||||
|
|
|
|
|
| |||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Additions to oil and gas properties | (42,238 | ) | (21,169 | ) | (25,397 | ) | ||||||
Acquisitions of oil and gas properties | (3,455 | ) | (27,398 | ) | 19,164 | |||||||
Sale of oil and gas properties | (38 | ) | 150 | — | ||||||||
Additions to property and equipment | (570 | ) | (1,699 | ) | (868 | ) | ||||||
Deposits | (312 | ) | (540 | ) | — | |||||||
Restricted cash | — | — | 522 | |||||||||
Escrow deposit (payments) | (43,110 | ) | (57,985 | ) | (108,236 | ) | ||||||
|
|
|
|
|
| |||||||
NET CASH USED IN INVESTING ACTIVITIES | (89,723 | ) | (108,641 | ) | (114,815 | ) | ||||||
|
|
|
|
|
| |||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Proceeds from issuance of long-term debt and notes payable | 17,644 | 18,979 | 205,198 | |||||||||
Payments on long-term debt and notes payable | (18,247 | ) | (16,895 | ) | (94,578 | ) | ||||||
Borrowings on bank debt | 171,500 | 158,457 | — | |||||||||
Payments on bank debt | (143,500 | ) | (134,457 | ) | — | |||||||
Debt issuance costs | (3,022 | ) | (2,770 | ) | (9,072 | ) | ||||||
Contributions from members | 110 | 30,000 | — | |||||||||
Distributions to members | (16,693 | ) | (19,939 | ) | (2,435 | ) | ||||||
|
|
|
|
|
| |||||||
NET CASH PROVIDED BY FINANCING ACTIVITIES | 7,792 | 33,375 | 99,113 | |||||||||
|
|
|
|
|
| |||||||
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | (15,877 | ) | (1,619 | ) | 12,643 | |||||||
CASH AND CASH EQUIVALENTS—beginning of year | 17,260 | 18,879 | 6,236 | |||||||||
|
|
|
|
|
| |||||||
CASH AND CASH EQUIVALENTS—end of year | $ | 1,383 | $ | 17,260 | $ | 18,879 | ||||||
|
|
|
|
|
| |||||||
SUPPLEMENTAL CASH FLOW INFORMATION | ||||||||||||
Cash paid for interest | $ | 23,603 | $ | 22,050 | $ | 11,008 | ||||||
|
|
|
|
|
| |||||||
NON-CASH INVESTING AND FINANCING ACTIVITIES | ||||||||||||
Asset retirement obligations | $ | 53,118 | $ | 147,442 | $ | 62,911 | ||||||
|
|
|
|
|
| |||||||
Assumption of gas imbalances | $ | — | $ | (1,159 | ) | $ | 2,041 | |||||
|
|
|
|
|
| |||||||
Increase in asset retirement obligation escrow receivable | $ | — | $ | 20,348 | $ | — | ||||||
|
|
|
|
|
| |||||||
Paid-in-kind dividends on preferred equity and accrued distributions to members | $ | 8,208 | $ | 4,200 | $ | — | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTE 1—ORGANIZATION AND BUSINESS
Black Elk Energy Offshore Operations, LLC and our wholly-owned subsidiaries (collectively, “Black Elk”, “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 January 29, 2008 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.
NOTE 2—RISKS AND UNCERTAINTIES
Our liquidity outlook changed during the year ended December 31, 2012 primarily as a result of lower gas prices and lower production as a result of wells that watered out, delays in the capital program, shut-ins due to pipeline repairs and Hurricane Isaac as well as the explosion and fire on our West Delta 32-E platform, which caused downtime and delays in the fields due to the Bureau of Safety and Environmental Enforcement (“BSEE”) requirement for approval after the incident.
While cash flows were lower than previously projected primarily due to lower production, we continued our development operations by supplementing our cash flows from operating activities with funds raised through borrowings in 2012, capital contributions from our members and an asset sale in 2013. We retained financial and technical advisors to provide recommendations on achieving improvements in production, operating expense, cash flows from operations, work over, capital expenditures, business planning and the arrangement of additional funding going forward.
As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $71.7 million at December 31, 2012 and we incurred a net loss of $64.0 million during the year ended December 31, 2012. The combination of restricted credit availability and lower production in the fourth quarter of 2012 led to significant cash reductions in the fourth quarter of 2012 and the first quarter of 2013. To increase liquidity, we stretched accounts payable and aggressively pursued accounts receivable. We have worked closely with our vendors during this time and expect to normalize the age of accounts payables within the second quarter. We continue to optimize our production portfolio and have commenced our drilling program in the fourth quarter of 2012. Currently, we have two rigs under contract and we expect to drill and complete eight operated wells and seven non-operated wells in 2013. To fund the drilling program and operations, we expect to continue to raise additional capital over the next several years. We are currently evaluating new sources of liquidity including, but not limited to, (i) renegotiating our current revolving credit facility, (ii) entering into a new revolving credit facility and (iii) accessing the debt capital markets. Additionally, we are evaluating potential asset sales of core and non-core assets to optimize our portfolio. As of March 26, 2013, we sold four producing fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. Proceeds from the sale will be used to reduce the amount borrowed under the Credit Facility by $36 million and for general corporate purposes. We will also work with counterparties to release approximately $29.8 million of escrows related to the sold properties of which $10 million will be used to pay down the Credit Facility.
Our primary use of capital has been for the acquisition, development and exploitation of oil and natural gas properties as well as providing collateral to secure our plugging and abandonment (“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 our surety bonds for P&A obligations. We are currently in discussions with surety agencies to replace the 100% cash-backed letters of credit. There can be no assurance as to the availability or terms upon which such equity or debt funding might be available.
At December 31, 2012, we were not in compliance with certain covenants in our Credit Facility. We have obtained waivers for the current ratio covenant, the hedging requirements covenant and the debt leverage ratio covenant for the period ended December 31, 2012. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0. The current ratio covenant has been removed in the Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement (the “Seventh Amendment”) and the Limited Waiver and Ninth Amendment to Credit Agreement (the “Ninth Amendment”) and has been replaced with a payables restriction covenant. Our liquidity projections demonstrate improvement of our financial position and we believe that we will meet our interest coverage ratio covenant, debt leverage ratio covenant and payables restrictions covenant going forward. If we are unable to maintain compliance with our debt covenants or obtain waivers or amendments, then we will be in default under our Credit Facility and all amounts outstanding would be reclassified as current liabilities on our consolidated balance sheet. If we are unable to repay the outstanding debt as it comes due, or if we are not able to effectively manage our working capital, or as necessary, successfully access the debt capital market, such events may have a material adverse effect on our financial position. 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.
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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.
As operator of certain projects that require cash commitments within the next twelve months and beyond, we retain significant control over the development concept and its timing. We consider the control and flexibility afforded by operating our properties under development to be instrumental to our business plan and strategy. To manage our liquidity, we have the ability to delay certain capital commitments, and within certain constraints, we can continue to conserve capital by further delaying or eliminating future capital commitments. While postponing or eliminating capital projects will delay or reduce future cash flows from scheduled new production, this control and flexibility is one method by which we can match, on a temporary basis, our capital commitments to our available capital resources.
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 material adverse effect on us. 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. We believe we can continue to meet our obligations for at least the next twelve months through a combination of cash flows from operations, capital contributions, asset dispositions and insurance reimbursement proceeds for P&A costs on the High Island 443 A-2 well and for costs to drill the replacement well, High Island 443 A-5, as well as delaying certain facility or drilling projects in the second half of 2013.
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.
A substantial portion of 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 Bureau of Ocean Energy Management (“BOEM”) and 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. Additionally, we cannot influence or predict if or how the governments of other countries in which we operate may modify their regulatory requirements.
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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—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Reclassifications: Certain reclassifications have been made to conform 2010 and 2011 balances to our 2012 presentation. Such reclassifications had no effect on net income 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. 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 U.S. generally accepted accounting principles (“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 date of 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.
We account for business combinations using the purchase method, in accordance with authoritative guidance from the Financial Accounting Standards Board (“FASB”). We use estimates to record the fair value of assets acquired and liabilities assumed.
Oil and natural gas reserves estimates, which are the basis for unit-of-production depletion and the impairment test, are based on assumptions that have inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
Cash and Cash Equivalents: We consider all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash and cash equivalents.
Revenue Recognition: Oil and natural gas revenues are recorded using the sales method whereby we recognize revenues based on the amount of oil and natural gas sold to purchasers. We produce plant products such as ethane, butane, propane and other product as part of processing our natural gas. These products are sold to certain gas processing plants. All natural gas revenues are reported net of the plant products.
We do not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exits; (ii) delivery has occurred or services have been rendered; (iii) the seller’s price to the buyer is fixed or determinable; and (iv) collectability is reasonable assured.
We record revenues based on physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create gas imbalances that we recognize as a receivable (payable) when there are not sufficient reserves to make up the gas imbalance. A gas imbalance receivable (payable) can also be a result of imbalances acquired in conjunction with the acquisition of oil and gas properties. At December 31, 2012 and December 31, 2011, our net gas receivable imbalances were $0.4 million and $1.4 million, respectively.
Allowance for Doubtful Accounts:Trade and other receivables are recorded at their outstanding balances adjusted for an allowance for doubtful accounts. The allowance for doubtful accounts is determined by analyzing the payment history and credit worthiness of each debtor. Receivable balances are charged off when they are considered uncollectible by management. Recoveries of receivables previously charged off are recorded as income when received. At December 31, 2012, allowance for doubtful accounts totaled $0.5 million. No allowance for doubtful accounts was considered necessary at December 31, 2011.
Oil and Natural Gas Properties: We account for oil and natural gas properties using the successful efforts method of accounting. Under this method of accounting, costs relating to the acquisition of and development of proved properties are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and natural gas producing activities are capitalized. Production costs are charged to expense as those costs are incurred to operate and maintain our wells and related equipment and facilities.
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Depreciation, depletion and amortization (“DD&A”) of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. DD&A expense related to oil and natural gas properties for the years ended December 31, 2012, 2011 and 2010 was $46.5 million, $46.6 million and $29.6 million, respectively. As more fully described below, proved reserves are estimated annually by our independent petroleum engineer, and are subject to future revisions based on availability of additional information. DD&A is calculated each quarter based upon the latest estimated reserves data available. Asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
Upon sale or retirement of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to operations.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties by field to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows based on management’s expectations of future oil and natural gas prices. For the years ended December 31, 2012, 2011 and 2010, we recorded an impairment charge of approximately $31.0 million, $13.0 million and $6.4 million, respectively.
Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.
Other Property and Equipment: Other property and equipment consists principally of furniture, fixtures and equipment and leasehold improvements. Other property and equipment and related accumulated depreciation and amortization are relieved upon retirement or sale and the gain or loss is included in operations. Maintenance and repairs are charged to operations. Renewals and betterments that extend the useful life of property and equipment are capitalized to the appropriate property and equipment accounts. Depreciation of other property and equipment is computed using the straight-line method based on estimated useful lives of the property and equipment. Depreciation expense of other property and equipment for the years ended December 31, 2012, 2011 and 2010 was $0.8 million, $0.6 million and $0.2 million, respectively.
In accordance with authoritative guidance on accounting for the impairment or disposal of long-lived assets, we assess the recoverability of the carrying value of our non-oil and natural gas long-lived assets when events occur that indicate an impairment in value may exist. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If this occurs, an impairment loss is recognized for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset.
Oil and Natural Gas Reserve Quantities: Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our independent engineering firm prepares a reserve and economic evaluation of all our properties on a well-by-well basis utilizing information provided to it by us and information available from state agencies that collect information reported to it by the operators of our properties. As discussed below, the estimate of our proved reserves as of December 31, 2012 and 2011 have been prepared and presented in accordance with SEC rules and applicable accounting standards. These rules require companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month un-weighted first-day-of-the-month average pricing.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to DD&A and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the report. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the quantities of oil, natural gas, and natural gas liquids ultimately recovered.
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Debt Issue Costs: Debt issue costs associated with long-term debt under revolving credit facilities and senior notes are carried at cost, net of amortization using the straight-line method over the term of the applicable long-term debt facility or the term of the notes, which approximates the interest method. Amortization expense for the years ended December 31, 2012, 2011 and 2010 amounted to $4.8 million, $2.9 million and $0.8 million, respectively.
Future amortization expense is as follows:
Year Ending December 31, | (in thousands) | |||
2013 | $ | 3,742 | ||
2014 | 1,766 | |||
2015 | 1,464 | |||
2016 | — | |||
2017 | — | |||
|
| |||
$ | 6,972 | |||
|
|
Derivative Financial Instruments: We utilize certain derivative contracts to reduce our exposure to fluctuating oil and natural gas prices. The oil and natural gas reference prices of these derivative contracts are based upon futures which have a high degree of correlation with actual prices received by us. We did not designate any of our derivative contracts as qualifying cash flow hedges. Accordingly, all gains and losses from our price risk management activities are currently included in earnings. Open positions are marked-to-market and recorded as unrealized gains or losses. When settled, the resulting cash flows are reported as cash flows from operating activities.
Asset Retirement Obligations: Accounting guidance for asset retirement obligations requires companies to recognize a liability for the present value of all obligations associated with retirement of tangible long-lived assets and to capitalize an equal amount as part of the cost of the related oil and natural gas properties. We recognize the legal obligation of the dismantlement, restoration and abandonment costs associated with our oil and natural gas properties with our asset retirement obligations. These costs are impacted by our estimated remaining lives of the properties, as well as current market conditions associated with these activities.
Environmental Expenditures: We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.
Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.
Income Taxes: We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes.
In May 2006, the state of Texas enacted a margin-based franchise tax law that replaced the existing franchise tax. This tax is commonly referred to as the Texas margin tax and is generally calculated as 1% of gross margin. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax became effective for franchise tax reports due on or after January 1, 2008. During the years ended December 31, 2012, 2011 and 2010, the margin tax was immaterial to the consolidated financial statements.
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. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.
NOTE 4—ACQUISITIONS
Merit Energy Corp
On May 31, 2011, we purchased certain properties from Merit Energy Corp. (the “Merit Acquisition”). We acquired interests in various properties across approximately 250,126 gross (127,894 net) acres in the Gulf of Mexico for a purchase price of $39 million (before normal purchase price adjustments) and the assumption of $121.2 million in asset retirement obligations related to P&A obligations associated with acquired properties, subject to customary adjustments for a transaction of that type.
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At closing, we were 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 payable in 30 equal monthly installments payable on the first day of each month commencing on June 1, 2011.
Prior to closing, we paid the sellers an earnest money deposit of $6 million. The earnest money was applied against the purchase price. We financed the remainder of the purchase price and related expenditures with existing available cash and approximately $35 million in borrowings under our Credit Facility (as defined in Note 10), together with equity financing from our members.
In order to consummate this acquisition, we commenced a Consent Solicitation that was completed on May 31, 2011 (the “Consent Solicitation”) to amend the maximum capital expenditures provision of the indenture (together with amendments and supplements thereto, the “Indenture”) governing our outstanding 13.75% Senior Secured Notes due 2015 (the “Notes”). On May 31, 2011, we acquired the consents to (1) increase the amount of capital expenditures permitted by us on an annual basis, (2) enable us to obtain financial support from our majority equity holder in the amount of a $30 million investment, and (3) obligate us to make an offer to repurchase the Notes semi-annually at an offer price of 103% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest if we meet certain defined financial tests and as permitted by our credit facilities.
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The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed (after purchase price adjustments), based on their fair values on May 31, 2011:
(in thousands) | ||||
Oil and gas properties | $ | 153,404 | ||
Gas imbalances—receivable | 1,487 | |||
Less: | ||||
Gas imbalances—payable | 314 | |||
Asset retirement obligations | 121,164 | |||
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| |||
Cash paid | $ | 33,413 | ||
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|
The fair values of evaluated oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (1) oil and natural gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.
Maritech Acquisition
On February 23, 2011, we acquired properties in the Gulf of Mexico from Maritech Resources Incorporated (the “Maritech Acquisition”), primarily located within federal offshore waters for a purchase price of $6 million before normal purchase price adjustments and the assumption of $12.8 million in asset retirement obligations related to P&A obligations associated with acquired properties. During the second quarter of 2011, we recorded an additional amount of P&A obligations of $13.0 million of which TETRA Technologies, Inc., the parent of Maritech Resources Incorporated, has guaranteed escrow accounts for certain fields in the amount of $20.3 million, which will not be refunded until the entire field is plugged and abandoned. The purchase included eight fields and adds interest in an additional 108 gross wells and an estimated 46 thousand gross acres to our portfolio. Upon closing on the Maritech Acquisition in February 2011, we entered into an irrevocable letter of credit (“ILOC”) with Capital One, N.A., in the amount of $2.8 million related to P&A obligations for interests in properties acquired. In May 2011, a separate deposit account was created for collateral related to the ILOC, including an increase of $0.1 million based on evaluation by the surety company, and funds related to this ILOC were moved from restricted cash to escrow for abandonment costs.
The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed after purchase price adjustments, based on their fair values on February 23, 2011:
(in thousands) | ||||
Oil and gas properties | $ | 2,377 | ||
Escrow | 20,348 | |||
Less: | ||||
Gas imbalances | 14 | |||
Asset retirement obligations | 25,726 | |||
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| |||
Cash received | $ | (3,015 | ) | |
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The fair values of evaluated oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (1) oil and natural gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.
Nippon Acquisition
On September 30, 2010, we acquired the Nippon Properties for a purchase price of $5 million before normal purchase price adjustments and the assumption of $57.4 million in asset retirement obligations related to P&A obligations associated with acquired properties. The Nippon Acquisition gave us an aggregate interest in 684 gross wells on 41 platforms located across 157 thousand gross acres offshore.
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The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed after purchase price adjustments, based on their fair values on September 30, 2010:
Nippon Acquisition
(in thousands) | ||||
Oil and gas properties | $ | 35,989 | ||
Less: | ||||
Gas imbalances | 2,041 | |||
Asset retirement obligations | 57,416 | |||
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| |||
Cash received | $ | (23,468 | ) | |
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The fair values of evaluated oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (1) oil and natural gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.
Chroma Acquisition
On January 30, 2010, we acquired properties in the Gulf of Mexico, primarily located within Texas state waters from Chroma Oil & Gas, LP for a purchase price of $5 million before normal purchase price adjustments. The purchase included 6 fields and added interest in an additional 40 wells and an estimated 13 thousand gross acres to our portfolio.
The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on January 30, 2010:
(in thousands) | ||||
Oil and gas properties | $ | 10,462 | ||
Less: | ||||
Asset retirement obligations | 5,761 | |||
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| |||
Cash paid | $ | 4,701 | ||
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The fair values of evaluated oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (1) oil and natural gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Significant inputs into the valuation of the asset retirement obligations include estimates of: (1) plug and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.
Merit and Nippon Pro Forma Information
The following unaudited pro forma combined, condensed financial information for the years ended December 31, 2011 and 2010 was derived from our historical financial statements giving effect to the Merit Acquisition and the Nippon Acquisition as if they had occurred on January 1, 2010. These unaudited pro forma financial results have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed the acquisitions as of January 1, 2010 or the results that will be attained in the future.
Revenue | Earnings (1) | |||||||
(in thousands) | (in thousands) | |||||||
Supplemental pro forma for January 1, 2011 through December 31, 2011 | $ | 393,146 | $ | 16,833 | ||||
Supplemental pro forma for January 1, 2010 through December 31, 2010 | $ | 299,626 | $ | 3,065 |
(1) | Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses. |
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The revenues and earnings of the Merit Acquisition and the Nippon Acquisition included in our consolidated statements of operations for the year ended December 31, 2011 are as follows:
Revenue | Earnings (1) | |||||||
(in thousands) | (in thousands) | |||||||
Merit | $ | 69,156 | $ | 14,855 | ||||
Nippon | $ | 126,242 | $ | 56,721 |
(1) | Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses. |
The revenues and earnings of the Nippon Acquisition included in our consolidated statements of operations for the year ended December 31, 2010 are as follows:
Revenue | Earnings (1) | |||||||
(in thousands) | (in thousands) | |||||||
Nippon | $ | 23,230 | $ | 11,467 |
(1) | Earnings include revenues less lease operating expenses, exploration, marketing and transportation, workover, DD&A, accretion, and general and administrative expenses. |
NOTE 5—OIL AND GAS PROPERTIES
The following table reflects capitalized costs related to our oil and gas properties:
At December 31, | ||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Proved properties | $ | 451,338 | $ | 352,758 | ||||
Accumulated depletion, depreciation, amortization and impairment | (191,326 | ) | (114,056 | ) | ||||
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| |||||
Oil and Natural Gas Properties, net | $ | 260,012 | $ | 238,702 | ||||
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NOTE 6—ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Below are the components of accounts payable and accrued expenses:
At December 31, | ||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Accounts payable—trade | $ | 61,530 | $ | 33,341 | ||||
Accrued operating expenses | 42,194 | 32,383 | ||||||
Interest payable | 1,913 | 1,940 | ||||||
Other payables | 3,099 | 4,645 | ||||||
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| |||||
$ | 108,736 | $ | 72,309 | |||||
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NOTE 7—ASSET RETIREMENT OBLIGATIONS
Accounting guidance requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon our interim review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.
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The following table describes the change to our asset retirement obligations:
At December 31, | ||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Beginning of year | $ | 288,686 | $ | 122,242 | ||||
Revaluation of liability | 53,118 | 147,442 | ||||||
Liabilities settled | (32,720 | ) | (8,408 | ) | ||||
Accretion expense | 36,421 | 27,410 | ||||||
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| |||||
End of year | $ | 345,505 | $ | 288,686 | ||||
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NOTE 8—DERIVATIVE INSTRUMENTS
In accordance with authoritative guidance on derivatives and hedging, all derivative instruments are measured at each period end and are recorded on the consolidated balance sheets at fair value. Derivative contracts that are designated as part of a qualifying cash flow hedge, per the accounting guidance, are granted hedge accounting thereby allowing us to treat the effective changes in the fair value of the derivative instrument in accumulated other comprehensive income, while recording the ineffective portion as an adjustment to unrealized gain (loss). Derivative contracts that are not designated as part of a valid qualifying hedge or fail to meet the requirements of the pronouncement as a highly effective hedge, are treated by recording the changes in the fair value from period to period, through earnings. The amounts paid or received upon each monthly settlement, are recorded as realized gain (loss) on derivative financial instruments, as appropriate.
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.
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At December 31, 2012 and 2011, we had the following contracts outstanding (Asset (Liability) and Fair Value Gain (Loss)):
As of December 31, 2012 | ||||||||||||||||||||||||||||||||||||||||
Crude Oil | Natural Gas | Total | ||||||||||||||||||||||||||||||||||||||
Period | Volume (Bbls) | Contract Price ($/Bbl) | Asset (Liability) | Fair Value Gain (Loss) | Volume (MMBtu) | Contract Price ($/MMBtu) | Asset (Liability) | Fair Value Gain (Loss) | Asset (Liability) | Fair Value Gain (Loss) | ||||||||||||||||||||||||||||||
(in thousands) | (in thousands) | (in thousands) | ||||||||||||||||||||||||||||||||||||||
Swaps: | ||||||||||||||||||||||||||||||||||||||||
1/13 - 10/13 | 27,750 | $ | 96.90 | $ | 983 | $ | 983 | 104,000 | $ | 4.60 | $ | 1,114 | $ | 1,114 | $ | 2,097 | $ | 2,097 | ||||||||||||||||||||||
11/13 - 11/13 | 26,800 | 96.90 | 88 | 88 | 104,000 | 4.60 | 81 | 81 | 169 | 169 | ||||||||||||||||||||||||||||||
12/13 - 12/13 | 27,750 | 96.90 | 95 | 95 | 104,000 | 4.60 | 61 | 61 | 156 | 156 | ||||||||||||||||||||||||||||||
1/14 - 2/14 | 19,000 | 96.90 | 136 | 136 | 82,000 | 4.60 | 80 | 80 | 216 | 216 | ||||||||||||||||||||||||||||||
1/13 - 6/13 | 15,542 | 100.80 | 715 | 715 | 200,669 | 4.94 | 1,806 | 1,806 | 2,521 | 2,521 | ||||||||||||||||||||||||||||||
7/13 - 7/13 | 7,132 | 100.80 | 47 | 47 | 148,788 | 4.94 | 194 | 194 | 241 | 241 | ||||||||||||||||||||||||||||||
8/13 - 8/13 | 5,980 | 100.80 | 40 | 40 | 139,212 | 4.94 | 176 | 176 | 216 | 216 | ||||||||||||||||||||||||||||||
9/13 - 9/13 | 3,897 | 100.80 | 26 | 26 | 116,125 | 4.94 | 145 | 145 | 171 | 171 | ||||||||||||||||||||||||||||||
10/13 - 10/13 | 3,259 | 100.80 | 22 | 22 | 91,166 | 4.94 | 110 | 110 | 132 | 132 | ||||||||||||||||||||||||||||||
11/13 - 11/13 | — | — | — | — | 64,926 | 4.94 | 71 | 71 | 71 | 71 | ||||||||||||||||||||||||||||||
12/13 - 12/13 | 10,042 | 100.80 | 70 | 70 | 119,462 | 4.94 | 107 | 107 | 177 | 177 | ||||||||||||||||||||||||||||||
1/14 - 5/14 | 10,083 | 100.80 | 361 | 361 | 129,960 | 4.94 | 547 | 547 | 908 | 908 | ||||||||||||||||||||||||||||||
6/14 - 6/14 | — | — | — | — | 129,960 | 4.94 | 111 | 111 | 111 | 111 | ||||||||||||||||||||||||||||||
1/13 - 12/13 | 19,750 | 85.90 | (1,649 | ) | (1,649 | ) | 47,000 | 5.00 | 785 | 785 | (864 | ) | (864 | ) | ||||||||||||||||||||||||||
1/14 - 12/14 | 15,000 | 65.00 | (4,199 | ) | (4,199 | ) | — | — | — | — | (4,199 | ) | (4,199 | ) | ||||||||||||||||||||||||||
1/13 - 1/13 | 9,042 | 88.80 | (29 | ) | (29 | ) | — | — | — | — | (29 | ) | (29 | ) | ||||||||||||||||||||||||||
2/13 - 2/13 | 23,522 | 88.80 | (84 | ) | (84 | ) | — | — | — | — | (84 | ) | (84 | ) | ||||||||||||||||||||||||||
3/13 - 3/13 | 16,792 | 88.80 | (67 | ) | (67 | ) | — | — | — | — | (67 | ) | (67 | ) | ||||||||||||||||||||||||||
4/13 - 4/13 | 23,812 | 88.80 | (103 | ) | (103 | ) | — | — | — | — | (103 | ) | (103 | ) | ||||||||||||||||||||||||||
5/13 - 5/13 | 24,012 | 88.80 | (110 | ) | (110 | ) | — | — | — | — | (110 | ) | (110 | ) | ||||||||||||||||||||||||||
6/13 - 6/13 | 29,752 | 88.80 | (140 | ) | (140 | ) | — | — | — | — | (140 | ) | (140 | ) | ||||||||||||||||||||||||||
7/13 - 7/13 | 23,143 | 88.80 | (108 | ) | (108 | ) | — | — | — | — | (108 | ) | (108 | ) | ||||||||||||||||||||||||||
8/13 - 8/13 | 24,915 | 88.80 | (114 | ) | (114 | ) | — | — | — | — | (114 | ) | (114 | ) | ||||||||||||||||||||||||||
9/13 - 9/13 | 28,688 | 88.80 | (127 | ) | (127 | ) | — | — | — | — | (127 | ) | (127 | ) | ||||||||||||||||||||||||||
10/13 - 10/13 | 28,006 | 88.80 | (120 | ) | (120 | ) | — | — | — | — | (120 | ) | (120 | ) | ||||||||||||||||||||||||||
11/13 - 11/13 | 31,605 | 88.80 | (130 | ) | (130 | ) | — | — | — | — | (130 | ) | (130 | ) | ||||||||||||||||||||||||||
12/13 - 12/13 | 38,743 | 88.80 | (152 | ) | (152 | ) | — | — | — | — | (152 | ) | (152 | ) | ||||||||||||||||||||||||||
1/14 - 1/14 | 4,723 | 88.80 | (17 | ) | (17 | ) | — | — | — | — | (17 | ) | (17 | ) | ||||||||||||||||||||||||||
2/14 - 2/14 | 13,313 | 88.80 | (48 | ) | (48 | ) | — | — | — | — | (48 | ) | (48 | ) | ||||||||||||||||||||||||||
3/14 - 3/14 | 8,413 | 88.80 | (29 | ) | (29 | ) | — | — | — | — | (29 | ) | (29 | ) | ||||||||||||||||||||||||||
4/14 - 4/14 | 12,473 | 88.80 | (41 | ) | (41 | ) | — | — | — | — | (41 | ) | (41 | ) | ||||||||||||||||||||||||||
5/14 - 5/14 | 11,793 | 88.80 | (37 | ) | (37 | ) | — | — | — | — | (37 | ) | (37 | ) | ||||||||||||||||||||||||||
6/14 - 6/14 | 15,546 | 88.80 | (46 | ) | (46 | ) | — | — | — | — | (46 | ) | (46 | ) | ||||||||||||||||||||||||||
7/14 - 7/14 | 11,845 | 88.80 | (33 | ) | (33 | ) | — | — | — | — | (33 | ) | (33 | ) | ||||||||||||||||||||||||||
8/14 - 8/14 | 13,165 | 88.80 | (34 | ) | (34 | ) | — | — | — | — | (34 | ) | (34 | ) | ||||||||||||||||||||||||||
9/14 - 9/14 | 16,235 | 88.80 | (41 | ) | (41 | ) | — | — | — | — | (41 | ) | (41 | ) | ||||||||||||||||||||||||||
10/14 - 10/14 | 15,605 | 88.80 | (38 | ) | (38 | ) | — | — | — | — | (38 | ) | (38 | ) | ||||||||||||||||||||||||||
11/14 - 11/14 | 18,525 | 88.80 | (42 | ) | (42 | ) | — | — | — | — | (42 | ) | (42 | ) | ||||||||||||||||||||||||||
12/14 - 12/14 | 22,526 | 88.80 | (46 | ) | (46 | ) | — | — | — | — | (46 | ) | (46 | ) | ||||||||||||||||||||||||||
1/13 - 1/13 | 66,000 | 87.85 | (272 | ) | (272 | ) | — | — | — | — | (272 | ) | (272 | ) | ||||||||||||||||||||||||||
2/13 - 2/13 | 34,000 | 87.85 | (154 | ) | (154 | ) | — | — | — | — | (154 | ) | (154 | ) | ||||||||||||||||||||||||||
3/13 - 3/13 | 50,000 | 87.85 | (246 | ) | (246 | ) | — | — | — | — | (246 | ) | (246 | ) | ||||||||||||||||||||||||||
4/13 - 4/13 | 35,000 | 87.85 | (184 | ) | (184 | ) | — | — | — | — | (184 | ) | (184 | ) | ||||||||||||||||||||||||||
5/13 - 5/13 | 36,000 | 87.85 | (198 | ) | (198 | ) | — | — | — | — | (198 | ) | (198 | ) | ||||||||||||||||||||||||||
6/13 - 6/13 | 23,000 | 87.85 | (129 | ) | (129 | ) | — | — | — | — | (129 | ) | (129 | ) | ||||||||||||||||||||||||||
7/13 - 7/13 | 15,000 | 87.85 | (84 | ) | (84 | ) | — | — | — | — | (84 | ) | (84 | ) | ||||||||||||||||||||||||||
8/13 - 8/13 | 11,000 | 87.85 | (60 | ) | (60 | ) | — | — | — | — | (60 | ) | (60 | ) | ||||||||||||||||||||||||||
9/13 - 9/13 | 20,000 | 87.85 | (106 | ) | (106 | ) | — | — | — | — | (106 | ) | (106 | ) | ||||||||||||||||||||||||||
10/13 - 10/13 | 4,000 | 87.85 | (21 | ) | (21 | ) | — | — | — | — | (21 | ) | (21 | ) | ||||||||||||||||||||||||||
11/13 - 11/13 | 250 | 87.85 | (1 | ) | (1 | ) | — | — | — | — | (1 | ) | (1 | ) | ||||||||||||||||||||||||||
12/13 - 12/13 | 2,500 | 87.85 | (12 | ) | (12 | ) | — | — | — | — | (12 | ) | (12 | ) | ||||||||||||||||||||||||||
1/14 - 1/14 | 46,000 | 87.85 | (211 | ) | (211 | ) | — | — | — | — | (211 | ) | (211 | ) | ||||||||||||||||||||||||||
2/14 - 2/14 | 25,000 | 87.85 | (110 | ) | (110 | ) | — | — | — | — | (110 | ) | (110 | ) | ||||||||||||||||||||||||||
3/14 - 3/14 | 56,000 | 87.85 | (239 | ) | (239 | ) | — | — | — | — | (239 | ) | (239 | ) | ||||||||||||||||||||||||||
4/14 - 4/14 | 45,000 | 87.85 | (186 | ) | (186 | ) | — | — | — | — | (186 | ) | (186 | ) | ||||||||||||||||||||||||||
5/14 - 5/14 | 46,000 | 87.85 | (182 | ) | (182 | ) | — | — | — | — | (182 | ) | (182 | ) | ||||||||||||||||||||||||||
6/14 - 6/14 | 48,000 | 87.85 | (181 | ) | (181 | ) | — | — | — | — | (181 | ) | (181 | ) | ||||||||||||||||||||||||||
7/14 - 7/14 | 36,000 | 87.85 | (129 | ) | (129 | ) | — | — | — | — | (129 | ) | (129 | ) | ||||||||||||||||||||||||||
8/14 - 8/14 | 34,000 | 87.85 | (117 | ) | (117 | ) | — | — | — | — | (117 | ) | (117 | ) | ||||||||||||||||||||||||||
9/14 - 9/14 | 26,000 | 87.85 | (86 | ) | (86 | ) | — | — | — | — | (86 | ) | (86 | ) | ||||||||||||||||||||||||||
10/14 - 10/14 | 27,000 | 87.85 | (86 | ) | (86 | ) | — | — | — | — | (86 | ) | (86 | ) | ||||||||||||||||||||||||||
11/14 - 11/14 | 20,000 | 87.85 | (61 | ) | (61 | ) | — | — | — | — | (61 | ) | (61 | ) | ||||||||||||||||||||||||||
12/14 - 12/14 | 31,000 | 87.85 | (87 | ) | (87 | ) | — | — | — | — | �� | (87 | ) | (87 | ) | |||||||||||||||||||||||||
9/13 - 9/13 | (17,500 | ) | 89.15 | 72 | 72 | — | — | — | — | 72 | 72 | |||||||||||||||||||||||||||||
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$ | (8,071 | ) | $ | (8,071 | ) | $ | 5,388 | $ | 5,388 | $ | (2,683 | ) | $ | (2,683 | ) | |||||||||||||||||||||||||
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81
Table of Contents
Index to Financial Statements
As of December 31, 2011 | ||||||||||||||||||||||||||||||||||||||||
Crude Oil | Natural Gas | Total | ||||||||||||||||||||||||||||||||||||||
Period | Volume (Bbls) | Contract Price ($/Bbl) | Asset (Liability) | Fair Value Gain (Loss) | Volume (MMBtu) | Contract Price ($/MMBtu) | Asset (Liability) | Fair Value Gain (Loss) | Asset (Liability) | Fair Value Gain (Loss) | ||||||||||||||||||||||||||||||
(in thousands) | (in thousands) | (in thousands) | ||||||||||||||||||||||||||||||||||||||
Swaps: | ||||||||||||||||||||||||||||||||||||||||
1/12 - 10/12 | 23,000 | $ | 96.90 | $ | (481 | ) | $ | (481 | ) | 227,000 | $ | 4.60 | $ | 3,679 | $ | 3,679 | $ | 3,198 | $ | 3,198 | ||||||||||||||||||||
11/12 - 11/12 | 22,080 | 96.90 | (23 | ) | (23 | ) | — | — | — | — | (23 | ) | (23 | ) | ||||||||||||||||||||||||||
12/12 - 12/12 | 23,000 | 96.90 | (18 | ) | (18 | ) | — | — | — | — | (18 | ) | (18 | ) | ||||||||||||||||||||||||||
1/13 - 10/13 | 27,750 | 96.90 | 234 | 234 | 104,000 | 4.60 | 800 | 800 | 1,033 | 1,033 | ||||||||||||||||||||||||||||||
11/13 - 11/13 | 26,800 | 96.90 | 60 | 60 | — | — | — | — | 60 | 60 | ||||||||||||||||||||||||||||||
12/13 - 12/13 | 27,750 | 96.90 | 71 | 71 | — | — | — | — | 71 | 71 | ||||||||||||||||||||||||||||||
1/14 - 2/14 | 19,000 | 96.90 | 115 | 115 | 82,000 | 4.60 | 30 | 30 | 145 | 145 | ||||||||||||||||||||||||||||||
1/12 - 12/12 | 17,050 | 81.22 | (3,598 | ) | (3,598 | ) | — | — | — | — | (3,598 | ) | (3,598 | ) | ||||||||||||||||||||||||||
1/12 - 12/12 | 1,900 | 81.14 | (400 | ) | (400 | ) | 112,000 | 5.00 | 2,356 | 2,356 | 1,956 | 1,956 | ||||||||||||||||||||||||||||
1/12 - 7/12 | — | — | — | — | 5,250 | 5.89 | 102 | 102 | 102 | 102 | ||||||||||||||||||||||||||||||
1/12 - 7/12 | 200 | 83.50 | (22 | ) | (22 | ) | 53,000 | 5.70 | 961 | 961 | 939 | 939 | ||||||||||||||||||||||||||||
8/12 - 12/12 | — | — | — | — | 53,000 | 5.70 | 597 | �� | 597 | 597 | 597 | |||||||||||||||||||||||||||||
1/12 - 12/12 | 27,500 | 85.90 | (4,232 | ) | (4,232 | ) | 26,838 | 5.89 | 849 | 849 | (3,383 | ) | (3,383 | ) | ||||||||||||||||||||||||||
1/12 - 5/12 | 22,125 | 100.80 | 174 | 174 | 318,958 | 4.94 | 2,993 | 2,993 | 3,168 | 3,168 | ||||||||||||||||||||||||||||||
6/12 - 6/12 | 22,125 | 100.80 | 33 | 33 | 303,880 | 4.94 | 532 | 532 | 565 | 565 | ||||||||||||||||||||||||||||||
7/12 - 7/12 | 12,048 | 100.80 | 21 | 21 | 106,638 | 4.94 | 180 | 180 | 201 | 201 | ||||||||||||||||||||||||||||||
8/12 - 8/12 | 8,296 | 100.80 | 17 | 17 | 90,586 | 4.94 | 150 | 150 | 166 | 166 | ||||||||||||||||||||||||||||||
9/12 - 9/12 | 3,998 | 100.80 | 9 | 9 | 56,141 | 4.94 | 92 | 92 | 101 | 101 | ||||||||||||||||||||||||||||||
10/12- 10/12 | 1,884 | 100.80 | 5 | 5 | 41,462 | 4.94 | 66 | 66 | 71 | 71 | ||||||||||||||||||||||||||||||
11/12 - 11/12 | — | — | — | — | 2,951 | 4.94 | 4 | 4 | 4 | 4 | ||||||||||||||||||||||||||||||
12/12 - 12/12 | 15,140 | 100.80 | 47 | 47 | 106,375 | 4.94 | 124 | 124 | 171 | 171 | ||||||||||||||||||||||||||||||
1/13 - 6/13 | 15,542 | 100.80 | 382 | 382 | 200,669 | 4.94 | 1,279 | 1,279 | 1,661 | 1,661 | ||||||||||||||||||||||||||||||
7/13 - 7/13 | 7,132 | 100.80 | 37 | 37 | 148,788 | 4.94 | 150 | 150 | 186 | 186 | ||||||||||||||||||||||||||||||
8/13 - 8/13 | 5,980 | 100.80 | 32 | 32 | 139,212 | 4.94 | 137 | 137 | 170 | 170 | ||||||||||||||||||||||||||||||
9/13 - 9/13 | 3,897 | 100.80 | 22 | 22 | 116,125 | 4.94 | 114 | 114 | 136 | 136 | ||||||||||||||||||||||||||||||
10/13 - 10/13 | 3,259 | 100.80 | 19 | 19 | 91,166 | 4.94 | 86 | 86 | 105 | 105 | ||||||||||||||||||||||||||||||
11/13 - 11/13 | — | — | — | — | 64,926 | 4.94 | 54 | 54 | 54 | 54 | ||||||||||||||||||||||||||||||
12/13 - 12/13 | 10,041 | 100.80 | 64 | 64 | 119,462 | 4.94 | 74 | 74 | 137 | 137 | ||||||||||||||||||||||||||||||
1/14 - 5/14 | 10,083 | 100.80 | 357 | 357 | 129,960 | 4.94 | 395 | 395 | 752 | 752 | ||||||||||||||||||||||||||||||
6/14 - 6/14 | — | — | — | — | 129,960 | 4.94 | 88 | 88 | 88 | 88 | ||||||||||||||||||||||||||||||
1/13 - 12/13 | 19,750 | 85.90 | (2,330 | ) | (2,330 | ) | 47,000 | 5.00 | 585 | 585 | (1,745 | ) | (1,745 | ) | ||||||||||||||||||||||||||
1/14 - 12/14 | 15,000 | 65.00 | (4,971 | ) | (4,971 | ) | — | — | — | — | (4,971 | ) | (4,971 | ) | ||||||||||||||||||||||||||
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$ | (14,377 | ) | $ | (14,377 | ) | $ | 16,477 | $ | 16,477 | $ | 2,100 | $ | 2,100 | |||||||||||||||||||||||||||
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82
Table of Contents
Index to Financial Statements
The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):
Asset Derivatives | Liability Derivatives | |||||||||||
Derivatives Not Designated as Hedging Instruments under Accounting Guidance | Balance Sheet Location | Fair Value at December 31, 2012 | Balance Sheet Location | Fair Value at | ||||||||
Commodity Contracts | Derivative financial instruments | Derivative financial instruments | ||||||||||
Current | $ | 6,808 | Current | $ | (4,400 | ) | ||||||
Non-current | 1,235 | Non-current | (6,326 | ) | ||||||||
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Total derivative instruments | $ | 8,043 | $ | (10,726 | ) | |||||||
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Asset Derivatives | Liability Derivatives | |||||||||||
Derivatives Not Designated as Hedging | Balance Sheet Location | Fair Value at | Balance Sheet Location | Fair Value at | ||||||||
Commodity Contracts | Derivative financial instruments | Derivative financial instruments | ||||||||||
Current | $ | 12,990 | Current | $ | (8,774 | ) | ||||||
Non-current | 5,203 | Non-current | (7,319 | ) | ||||||||
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Total derivative instruments | $ | 18,193 | $ | (16,093 | ) | |||||||
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The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):
Derivatives Not Designated as Hedging | Twelve Months Ended December 31, | |||||||||||||
Instruments under Accounting Guidance | Statements of Operations Location | 2012 | 2011 | 2010 | ||||||||||
Commodity Contracts | Realized gain on derivative financial instruments | $ | 23,364 | $ | 8,099 | $ | 9,271 | |||||||
Commodity Contracts | Unrealized (loss) gain on derivative financial instruments | (4,783 | ) | 17,556 | (12,700 | ) | ||||||||
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Total derivative instruments | $ | 18,581 | $ | 25,655 | $ | (3,429 | ) | |||||||
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NOTE 9—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 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.
83
Table of Contents
Index to Financial Statements
The following tables present information about our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2011, and indicate the fair value hierarchy of the valuation techniques utilized by us to determine such fair value (in thousands):
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 | $ | — | ||||||||
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$ | 8,043 | $ | — | $ | 8,043 | $ | — | |||||||||
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Liabilities | ||||||||||||||||
Oil and Natural Gas Derivatives | $ | (10,726 | ) | $ | — | $ | (10,726 | ) | $ | — | ||||||
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$ | (10,726 | ) | $ | — | $ | (10,726 | ) | $ | — | |||||||
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Fair Value Measurements at December 31, 2011 Using Fair Value Hierarchy | ||||||||||||||||
Fair Value as of December 31, 2011 | Level 1 | Level 2 | Level 3 | |||||||||||||
Assets | ||||||||||||||||
Oil and Natural Gas Derivatives | $ | 18,193 | $ | — | $ | 18,193 | $ | — | ||||||||
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$ | 18,193 | $ | — | $ | 18,193 | $ | — | |||||||||
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Liabilities | ||||||||||||||||
Oil and Natural Gas Derivatives | $ | (16,093 | ) | $ | — | $ | (16,093 | ) | $ | — | ||||||
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$ | (16,093 | ) | $ | — | $ | (16,093 | ) | $ | — | |||||||
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At December 31, 2012 and 2011, management estimates that the derivative contracts had a fair value of ($2.7) million and $2.1 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 December 31, 2012, 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 December 31, 2012 was $205.5 million.
Fair Value on a Non-Recurring Basis
As of December 31, 2012, oil and gas properties with a carrying value of $291.0 million were written down to their fair value of $260.0 million, resulting in an impairment charge, which is recognized under “Impairments” in the consolidated statements of operations, of $31.0 million for the year ended December 31, 2012. As of December 31, 2011, oil and gas properties were written down to their fair value of $238.7 million from a carrying value of $251.7 million, a $13.0 million impairment charge. 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.
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NOTE 10—DEBT AND NOTES PAYABLE
Our debt and notes payable are summarized as follows:
December 31, 2012 | December 31, 2011 | |||||||
(in thousands) | ||||||||
Senior Secured Revolving Credit Facility | $ | 52,000 | $ | 24,000 | ||||
13.75% Senior Secured Notes, net of discount | 149,118 | 148,887 | ||||||
AFCO Credit Corporation-insurance note payable | 3,552 | — | ||||||
First Insurance—note payable | — | 4,154 | ||||||
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| |||||
Total debt | 204,670 | 177,041 | ||||||
Less: current portion | (3,552 | ) | (4,154 | ) | ||||
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| |||||
Total long-term debt | $ | 201,118 | $ | 172,887 | ||||
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Senior Secured Revolving Credit Facility
On December 24, 2010 we entered into an aggregate $110 million credit facility (the “Credit Facility”) comprised of a senior secured revolving credit facility of up to $35 million (the “Revolving Credit Facility”) and a $75 million secured letter of credit 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 2.75% to 3.5% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.25% to 2.00%. The applicable margin is computed based on the borrowing based utilization percentage in effect from time to time.
We have entered into various amendments to the Credit Facility. These amendments have (1) changed our amount available for borrowing under the Revolving Credit Facility from $35 million to $25 million, (2) increased the secured letter of credit from $75 million to $200 million, (3) amended certain provisions governing our swap agreements, (4) updated the fees on the letters of credit to 2% on a go-forward basis, (5) updated the “change in control” definition, (6) amended the definition of debt included in the calculation of the covenants, (7) changed the maturity date from December 24, 2013 to June 22, 2014, (8) received a waiver as of and for the fiscal quarter ending December 31, 2012 for any defaults arising for the noncompliance of the current ratio calculation and the unwinding of certain hedges executed under the BP Swap Agreements, (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 or entities designated by PPBE (the “Platinum Group”) during the first quarter of 2013 and (11) revised the definition of “Event of Default” to include non-compliance with new affirmative covenants.
As of December 31, 2012, letters of credit in the aggregate amount of $137.4 million were outstanding under the Letter of Credit Facility. We had $52.0 million in borrowings under the Revolving Credit Facility of which $18.0 million was available for additional borrowings.
A commitment of 0.5% per annum is computed based on the unused borrowing base and paid quarterly. For the years ended December 31, 2012 and 2011, we recognized $68,357 and $167,054 in commitment fees, respectively, which have been included in “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. We and the administrative agent may each elect to cause the borrowing base to be re-determined one time between scheduled semi-annual redetermination periods.
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 rate coverage ratio to be less than 3.0 to 1.0, or our current ratio (in each case as defined in our revolving Credit Facility) to be less than 1.0 to 1.0. 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 December 31, 2012, we were not in compliance with our current ratio covenant, our hedging requirement covenant and our leverage ratio covenant. Our current ratio covenant was calculated to be 0.6 to 1.0 which was lower than the required 1.0 to 1.0. Our hedging requirement of our notional volumes exceeded 75% for the month of January 2013 by 5% of the reasonably anticipated total volume of projected production from proved, developed, and producing oil and gas properties. Our leverage ratio covenant was calculated to be 2.54 to 1.0, which was slightly higher than the maximum 2.5 to 1.0. We received a limited waiver relating to such covenants for the fiscal quarter ended December 31, 2012. The waiver will not apply to any future fiscal quarter. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0. The current ratio covenant has been removed in the Seventh Amendment and the Ninth Amendment and has been replaced with a payables restriction covenant. We paid $0.3 million to obtain the waiver.
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13.75% Senior Secured Notes
On November 23, 2010, we issued $150 million face value of 13.75% Senior Secured 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 Bureau of Ocean Energy Management, Regulation and Enforcement 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, of which all principal then outstanding will be due. As of December 31, 2012 and 2011, the recorded value of the Notes was $149.1 million and $148.9 million, respectively, which includes the unamortized discount of $0.9 million and $1.1 million, respectively. We incurred underwriting and debt issue costs of $7.2 million which have been capitalized and will be amortized over the life of the Notes.
The Notes are secured by a security interest in the issuers’ and the guarantors’ assets (excluding the W&T Escrow Accounts) 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 was completed on May 31, 2011 and 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 to, among other things: (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 (as defined in Note 18) 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 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 a maximum limit of $60 million for the fiscal year ending December 31, 2012 and 30% of consolidated earnings before interest expense, income taxes, DD&A and impairment, and exploration expense for any year thereafter. As of December 31, 2012, we were in compliance with our covenants under the Indenture.
AFCO Credit Corporation—Insurance Notes Payable
In 2012, we entered into a note to finance annual insurance premiums related to our oil and natural gas properties for an aggregate $17.6 million. The note bears interest at an annual rate of 1.95% compounded monthly. At December 31, 2012, the total outstanding balance was $3.6 million.
First Insurance—Notes Payable
During 2011, we entered into two notes to finance annual insurance premiums related to our oil and natural gas properties for an aggregate $19.0 million. The notes bear interest at annual rates of 2.06% compounded monthly. During February 2012, we paid off the notes.
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The amounts of required principal payments based on our outstanding debt amounts as of December 31, 2012, were as follows:
Year Ending December 31, | (in thousands) | |||
2013 | $ | 3,552 | ||
2014 | 52,000 | |||
2015 | 150,000 | |||
2016 | — | |||
2017 | — | |||
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205,552 | ||||
Unamortized discount on 13.75% Senior Secured Notes | (882 | ) | ||
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Total debt | $ | 204,670 | ||
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NOTE 11—DEFINED CONTRIBUTION PLAN
We have a 401(k) Defined Contribution Plan (the “Plan”). Employees become eligible to contribute to the plan and to receive employer contributions the first of the month subsequent to completing one month of service. The Plan allows eligible employees to contribute up to 90% of their annual compensation, not to exceed the maximum amounts permitted by IRS regulations. The defined contribution plan provides that we will make a safe harbor contribution equal to 3% of compensation for the plan year. Employees are 100% vested in contributions that they make to the Plan and any safe harbor contributions. Other contributions made by us fully vest after three years of service. We provided matching contributions to the Plan for the years ended December 31, 2012, 2011 and 2010 of $0.3 million, $0.5 million and $0.3 million, respectively.
NOTE 12—MEMBERS’ DEFICIT
The Member Agreement (the “Agreement”) has two classes of members. Net income (loss) is allocated to the members in accordance with the terms set forth in the Agreement. The Agreement allows for preferred returns to certain members after internal rate of return and return of investment hurdles are met.
On May 31, 2011, Platinum Partners Value Arbitrage Fund L.P., and/or its affiliates (collectively “Platinum”) entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million units of our Class D Preferred Units (the “Class D Units”), having such rights, preferences and privileges as set forth in our Second Amendment and Restated Operating Agreement, as amended. The Class D Units were issued in the name of Platinum’s wholly owned subsidiary, PPVA Black Elk (Equity) LLC.
The Class D Units are non-voting units, have an aggregate liquidation preference of $30 million and accrue dividends payable in kind at a rate per annum of 24%, compounded annually to the extent they are not distributed. As of December 31, 2012 and 2011, we have accrued dividends in the amounts of $12.4 million and $4.2 million, respectively, which are included in “Long-Term Liabilities” on the consolidated balance sheets. The dividends were reclassed to a long-term liability in the second quarter of 2012 as they are expected to be repaid after the Notes mature. At December 31, 2012, Platinum contributed a total of $30.0 million in cash as the financial instruments were converted into cash during the year. During the first quarter of 2013, we exchanged the Class D Units for Class E Units and also received additional contributions from PPVA Black Elk (Equity) LLC (“PPVA (Equity)”) and the Platinum Group. See Note 20.
In accordance with accounting guidance on distinguishing liabilities from equity, we have restated our 2011 consolidated financial statements to report the Class D Cumulative Convertible Participating Preferred Units outside of permanent equity as the redemption feature is conditional, but at the holders’ option. Platinum cannot redeem the units until obligations to bondholders are satisfied. We reflected the necessary adjustments in the fourth quarter of 2012 and calculated the impact on our quarterly reports on Form 10-Q for the quarterly periods ending June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012 and September 30, 2012.
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The applicable line items on the Form 10-Q Consolidated Balance Sheets have been restated below for the quarterly periods ending June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, and September 30, 2012 (in thousands):
At June 30, 2011 | ||||||||||||
As Previously Reported on 10-Q | Adjustments | As Restated | ||||||||||
Class D Cumulative Convertible Participating Preferred Units | $ | — | $ | 30,000 | $ | 30,000 | ||||||
Members’ Equity (Deficit) | 5,604 | (30,000 | ) | (24,396 | ) | |||||||
At September 30, 2011 | ||||||||||||
As Previously Reported on 10-Q | Adjustments | As Restated | ||||||||||
Class D Cumulative Convertible Participating Preferred Units | $ | — | $ | 30,000 | $ | 30,000 | ||||||
Members’ Equity (Deficit) | 48,426 | (30,000 | ) | 18,426 | ||||||||
At December 31, 2011 | ||||||||||||
As Previously Reported on 10-Q | Adjustments | As Restated | ||||||||||
Class D Cumulative Convertible Participating Preferred Units | $ | — | $ | 30,000 | $ | 30,000 | ||||||
Members’ Equity (Deficit) | 292 | (30,000 | ) | (29,708 | ) | |||||||
At March 31, 2012 | ||||||||||||
As Previously Reported on 10-Q | Adjustments | As Restated | ||||||||||
Class D Cumulative Convertible Participating Preferred Units | $ | — | $ | 30,000 | $ | 30,000 | ||||||
Members’ Deficit | (13,276 | ) | (30,000 | ) | (43,276 | ) | ||||||
At June 30, 2012 | ||||||||||||
As Previously Reported on 10-Q | Adjustments | As Restated | ||||||||||
Class D Cumulative Convertible Participating Preferred Units | $ | — | $ | 30,000 | $ | 30,000 | ||||||
Members’ Deficit | (709 | ) | (30,000 | ) | (30,709 | ) | ||||||
At September 30, 2012 | ||||||||||||
As Previously Reported on 10-Q | Adjustments | As Restated | ||||||||||
Class D Cumulative Convertible Participating Preferred Units | $ | — | $ | 30,000 | $ | 30,000 | ||||||
Members’ Deficit | (39,090 | ) | (30,000 | ) | (69,090 | ) |
NOTE 13—GAIN ON INVOLUNTARY CONVERSION
West Delta 32
On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform, located in the Gulf of Mexico approximately 17 miles southeast of Grand Isle, Louisiana, in 52 feet of water. Three workers died as a result of the explosion and subsequent fire, and others sustained various degrees of person injuries. We dispatched two oil spill recovery vessels to the scene to evaluate any potential environmental impact and conduct spill recovery efforts. Based on an analysis of the sheen observed after the incident, the spill totaled less than one barrel. Based on preliminary estimates of the tank contents, BSEE requested us to also report a loss amount of 480 barrels. There was no loss of containment from any well connect to the platform. There was no loss of oil after the fire was controlled. The cause of the fire is being investigated by Black Elk and BSEE, in coordination with the U.S. Coast Guard. We have engaged ABS Consulting to assist with our investigation in order to make a cause and origin determination. The cause has not yet been determined. We engaged ES&H Training and Consulting Group to clean the platform to prevent residual oil on the platform from being washed or blown into the Gulf of Mexico. The work was completed on November 30, 2012. At BSEE’s direction, we have also engaged an independent third-party auditor to audit our SEMS program. We have insurance for some potential losses and are pursuing reimbursement for this incident. We have not recorded a receivable for reimbursement under our insurance policy. As of April 2013, four civil lawsuits have been filed as a result of the West Delta 32 Incident. For additional information, please see “Risk Factors” under Item 1A of this Form 10-K and “Legal Proceedings” under Item 3 of this Form 10-K.
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 Bureau of Safety and Environmental Enforcement (“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 drill are also insurance recoverable.
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The claim was approved. 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.
NOTE 14—RELATED PARTY TRANSACTIONS
We pay for certain operating and general and administrative expenses on behalf of Black Elk Energy, LLC, the parent company of Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. At December 31, 2012 and 2011, we had receivables from Black Elk Energy, LLC in the amount of $23,430 and $22,430, respectively.
We had two notes payable to affiliates of a member, Platinum, which were paid in full in November 2010. Interest expense and prepayment penalties totaling $1.2 million were recorded for the year ended December 31, 2010.
We had a line of credit with a member, Platinum, which was paid in full on November 23, 2010. Interest expense for the period ended December 31, 2010 was $8.1 million.
During 2011, we entered into a contribution agreement with Platinum. See Note 12. We also entered into additional contributions with (“PPVA (Equity)”) and the Platinum Group in 2013. See Note 20.
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 member of our management), 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. As of December 31, 2011, the balance of the loan was $3.0 million. On August 1, 2012, Freedom entered into a purchase agreement with Gulf State Aviation, whereby Gulf State Aviation purchased certain aircraft equipment from Freedom, including the two helicopters. The proceeds of the sale were applied to the balance of the guaranteed loan when the sale was finalized in December 2012 and there was no remaining balance due on the loan as of December 31, 2012. 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.
In April 2011, Freedom Well Services (“FWS”) was formed by certain members of our management, Freedom Well Services Employee Incentive, LLC and Platinum, our majority equity holder, to provide well P&A, slick line and electronic line services as well as consulting services around platform decommissioning and removal. Although we did not contribute capital for start-up costs, we funded the purchase of equipment as a prepayment for services rendered with the expectation that the prepayment will be reimbursed as the business continues to grow and generate cash flows. As of December 31, 2012 and 2011, prepayments were $8.7 million and $6.6 million, respectively, to FWS which is included in “Prepaid expenses and other” on our consolidated balance sheet. FWS also leased office space from us until February 2013. The amount due for rent at December 31, 2012 and 2011 was $0.1 million and $38,688, respectively. FWS also provided us well P&A and other services. As of December 31, 2012 and 2011, we owed FWS $0.3 million and $0.1 million, respectively.
For periods ended December 31, 2012, 2011 and 2010, we paid $0.2 million, $1.0 million and $0.5 million, respectively, to Up and Running Solutions, LLC, for IT consulting services. Up and Running Solutions, LLC is owned by the wife of an employee, David Cantu (a member of our management). At December 31, 2011, the outstanding amount due to Up and Running Solutions, LLC was $72,222. There were no amounts due to Up and Running Solutions, LLC at December 31, 2012.
NOTE 15—MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK
Major Customers
The following purchasers and operators accounted for 10% or more of our oil and natural gas sales:
Year Ended December 31, | ||||||||||||
Customer | 2012 | 2011 | 2010 | |||||||||
Conoco Phillips Company | 3 | % | 7 | % | 14 | % | ||||||
Shell Trading (US) Company | 18 | % | 51 | % | 52 | % | ||||||
JP Morgan Ventures Energy Corporation | 41 | % | 8 | % | 0 | % |
In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of our customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.
Concentrations of Credit Risk
We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. We had cash deposits in certain banks that at times exceeded the maximum limits federally insured by the Federal Deposit Insurance Corporation. We monitor the financial condition of the banks and have experienced no losses on those accounts.
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Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Based on the current demand for oil and natural gas, we do not expect that termination of sales to any of our current purchasers would have a material adverse effect on our ability to find replacement purchasers and to sell our production at favorable market prices.
Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We actively monitor our credit risks related to financial institutions and counterparties including monitoring credit agency ratings, financial position and current news to mitigate this credit risk.
A substantial portion of our oil and natural gas reserves and production are located in the Gulf of Mexico. Our company may be disproportionally exposed to the impact of delays of interruptions of production from these wells due to mechanical problems, damages to the current producing reservoirs and significant governmental regulations, including any curtailment of production or interruption of transportation of oil or natural gas produced from these wells.
NOTE 16—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 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.
West Delta 32
On November 16, 2012, an explosion and fire occurred on our West Delta 32-E platform. The cause of the West Delta 32 Incident is being investigated by BSEE, in coordination with the U.S. Coast Guard. We are fully cooperating with all government agencies and have engaged ABS Consulting to assist with our investigation. At BSEE’s direction, we have also engaged an independent third-party auditor to audit our SEMS program. We currently cannot assess the probability of losses, or reasonably estimate a range of any potential losses related to the investigations and the audit. As a result of the investigation, it is possible that BSEE could issue Incidents of Non-Compliance and associated penalties, as well as enjoin us from operating part or all of West Delta 32. We intend to vigorously defend the Company in these investigations.
As of April 10, 2013, four civil lawsuits have been filed as a result of the West Delta 32 Incident. 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 February 7, 2013, the plaintiffs amended their petition, adding another BEE unit holder as a named plaintiff and joining as defendants additional parties, including Freedom Well Services, LLC, Freedom Logistics, LLC, Elk Well Services, LLC, Freedom HHC Management LLC, and FWS Employee Incentive LLC. On March 8, 2013, the plaintiffs amended their petition for a second time to delete certain factual allegations regarding dilution of BEE’s interest in our company. Two prior lawsuits alleging many of the same facts have been dismissed. This case is being defended vigorously.
On March 22, 2013, these same investor plaintiffs filed a similar purported derivative action on behalf of BEE in the Supreme Court of New York County in the State of New York. The suit is filed against our company; John Hoffman; our majority unit holder, PPVA Black Elk (Equity) LLC; several entities and individuals affiliated with PPVA Black Elk (Equity) LLC; and Iron Island Technologies, Inc. Like the Harris County lawsuit, the plaintiffs allege that the defendants improperly diluted BEE’s percentage ownership in our company; it is unclear whether plaintiffs are also asserting claims with respect to the West Delta 32 Incident in connection with this separate lawsuit. The plaintiffs seek an unspecified amount of damages individually and on behalf of BEE in connection with these claims. Like the Harris County lawsuit, this case is being defended vigorously.
On January 31, 2013, eight individual plaintiffs sued BEEOO, BEE, and three independent contractors (Wood Group USA, Inc., Compass Engineering and Consultants, LLC, and Enviro-Tech Specialties, Inc.) in the United States District Court for the Southern District of Texas. The plaintiffs seek to recover for injuries they allege to have suffered in connection with the West Delta 32 Incident. The plaintiffs allege that they were employed by Grand Isle Shipyard, Inc., and that they were working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. The plaintiffs seek $100 million in actual damages and $300 million in punitive damages.
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On February 27, 2013, the family of decedent Avelino Tajonera sued BEEOO in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Tajonera’s wife individually and on behalf of his estate and Mr. Tajonera’s three children. The plaintiffs allege that Mr. Tajonera was employed by Grand Isle Shipyard, Inc. and was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Tajonera died several days after the West Delta 32 Incident from injuries he sustained therein. The plaintiffs are seeking an unspecified amount of actual and punitive damages.
On March 25, 2013, the family of decedent Ellroy Corporal sued our company in the United States District Court for the Eastern District of Louisiana. The lawsuit was filed by Mr. Corporal’s wife individually and on behalf of his estate and Mr. Corporal’s two children. The plaintiffs allege that Mr. Corporal was working on the West Delta 32 Block Platform at the time of the West Delta 32 Incident. They allege that Mr. Corporal died from complications due to the West Delta 32 Incident. The plaintiffs are seeking an unspecified amount of actual and punitive damages.
For each proceeding, we are currently evaluating the plaintiff’s petitions and determining appropriate courses of response with the aid of legal 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. We intend to vigorously defend the Company in these proceedings.
Operating Leases
We lease office space and certain equipment under non-cancellable operating lease agreements that expire on various dates through 2020. The termination date of the agreement is December 31, 2020.
Approximate future minimum lease payments for operating leases at December 31, 2012 were as follows:
Year Ending December 31, | (in thousands) | |||
2013 | $ | 30,689 | ||
2014 | 2,284 | |||
2015 | 1,970 | |||
2016 | 1,791 | |||
2017 | 1,512 | |||
Thereafter | 4,613 | |||
|
| |||
$ | 42,859 | |||
|
|
Rent expense of approximately $1.5 million, $1.0 million and $0.5 million was incurred under operating leases in the years ended December 31, 2012, 2011 and 2010, respectively.
During 2012, we entered into two drilling unit contracts. One of the contracts was updated in November 2012 to a term of 270 days in addition to the demobilization being completed while the other contract is for the duration of one well. We commenced drilling operations on one well in December 2012.
Escrow Accounts
Pursuant to the purchase agreement from W&T Offshore, Inc. (“W&T”), 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. We were required to fully fund such obligations by the end of 2012 with respect to the operating properties and by the end of 2016 with respect to non-operating properties. The maximum obligation of $63.8 million may be adjusted downward in certain situations. We may withdraw cash from the W&T Escrow Accounts as reimbursement for performed P&A obligations. However, no cash may be withdrawn if at any point we are in default under our stipulated payment schedules. 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 December 31, 2012, we have funded $13.4 million into the non-operating escrow account, leaving $17.8 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 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.
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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 December 31, 2012, we have funded $8.0 million, leaving $5.1 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 December 31, 2012, we have funded $38.1 million, leaving $21.9 million to be funded through November 2013.
NOTE 17—UNCERTAIN TAX POSITIONS
As we are considered a flow through entity for U.S. federal tax purposes, our only exposure to uncertain tax positions relates to the Texas margins tax.
We did not have unrecognized tax benefits as of December 31, 2012 and 2011, and do not expect this to change significantly over the next 12 months. In accordance with accounting guidance for income taxes, we will recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2012 and 2011, we have not accrued interest or penalties related to uncertain tax positions.
Our tax years for fiscal years ended December 31, 2012, 2011, and 2010 are subject to examination in the United States and relevant state jurisdictions.
NOTE 18—SUPPLEMENTAL OIL AND NATURAL GAS RESERVE INFORMATION (UNAUDITED)
The supplementary data presented herein reflects information for all of our oil and natural gas producing activities.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to our oil and natural gas activities for the years ended December 31, 2012, 2011 and 2010:
Year Ending December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(in thousands) | ||||||||||||
Oil and Gas Activities: | ||||||||||||
Exploration costs | $ | 1,682 | $ | 1,004 | $ | 14 | ||||||
Development costs | 42,238 | 21,169 | 25,397 | |||||||||
Acquisition costs | 3,455 | 27,398 | (19,164 | ) | ||||||||
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Costs incurred | $ | 47,375 | $ | 49,571 | $ | 6,247 | ||||||
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Estimated Net Quantities of Oil and Natural Gas Reserves
The following estimates of the net proved oil and natural gas reserves of our oil and natural gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.
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Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed reserves in barrels (“MBbls”) and cubic feet (“MMcf”) for each of the periods indicated were as follows:
Crude Oil and NGLs (MBbls) | Natural Gas (MMcf) | Total (MBOE) | ||||||||||
Proved reserves at December 31, 2010 | 10,257 | 68,598 | 21,690 | |||||||||
Purchases of minerals in place | 7,288 | 63,406 | 17,856 | |||||||||
Extensions and discoveries | 3,889 | 31,790 | 9,187 | |||||||||
Revisions of previous estimates | 972 | 4,787 | 1,770 | |||||||||
Production | (2,283 | ) | (18,188 | ) | (5,314 | ) | ||||||
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Proved reserves at December 31, 2011 | 20,123 | 150,393 | 45,189 | |||||||||
Extensions and discoveries | 3,761 | 11,343 | 5,652 | |||||||||
Revisions of previous estimates | (94 | ) | (30,759 | ) | (5,221 | ) | ||||||
Production | (2,301 | ) | (17,884 | ) | (5,281 | ) | ||||||
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Proved reserves at December 31, 2012 | 21,489 | 113,093 | 40,339 | |||||||||
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Proved developed reserves at December 31, 2012 | 12,261 | 73,001 | 24,428 | |||||||||
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Significant items included in the categories of proved developed reserve changes for the years ended December 31, 2012 and 2011 in the above table include the following:
• | The increase in 2011 was a result of the purchase of minerals in the Maritech Acquisition and the Merit Acquisition. |
• | The decrease in 2012 was primarily due to revisions of previous estimates as a result of dropped and revised cases as well as pricing adjustments. |
Our proved undeveloped reserves at December 31, 2012 were 15.9 MMBoe, consisting of 9.2 MBbls of oil and NGLs and 40.1 Bcf of natural gas. Decreases in proved undeveloped reserves in 2012 were primarily due to the reclassification of several PUDs that had reached the five year period and a lower pricing environment. All proved undeveloped reserves are scheduled to be drilled by 2017 excluding the twelve drills waiting on wellbore availability. Our proved undeveloped reserves at December 31, 2011 were 19.5 MMBoe, consisting of 8.3 MBbls of oil and NGLs and 67.1 Bcf of natural gas. Increases in proved undeveloped reserves were primarily due to continued evaluation of our existing asset base and the Merit Acquisition.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a standardized measure of the discounted net future cash flows and changes applicable to proved oil and natural gas reserves required by accounting guidance for disclosures about oil and natural gas producing activities. The future cash flows are based on estimated oil and natural gas reserves utilizing prices and costs in effect as of year-end, discounted at 10% per year and assuming continuation of existing economic conditions.
The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of our proved oil and natural gas properties.
The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
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December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(in thousands) | ||||||||||||
Future cash inflows | $ | 2,552,252 | $ | 2,641,791 | $ | 1,104,561 | ||||||
Future cost: | ||||||||||||
Production | 695,079 | 714,076 | 318,974 | |||||||||
Development | 496,834 | 544,523 | 278,785 | |||||||||
Future income taxes | — | — | 11,591 | |||||||||
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Future net cash flows | 1,360,339 | 1,383,192 | 495,211 | |||||||||
10% annual discount for estimated timing of cash flows | 302,546 | 321,784 | 103,022 | |||||||||
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Standardized measure of discounted future net cash flows | $ | 1,057,793 | $ | 1,061,408 | $ | 392,189 | ||||||
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Changes in Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Proved Reserves
Year Ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
(in thousands) | ||||||||||||
Beginning of year: | $ | 1,061,408 | $ | 392,189 | $ | 43,186 | ||||||
Purchase of minerals in place | — | 612,048 | 304,368 | |||||||||
Extensions and discoveries and improved recovery, net of future production and development cost | 202,334 | 314,920 | 83,105 | |||||||||
Accretion of discount | 83,566 | 34,238 | 1,903 | |||||||||
Net change in sales prices net of production costs | (61,407 | ) | 112,923 | 27,605 | ||||||||
Changes in estimated future development costs | 6,420 | (359,942 | ) | (123,154 | ) | |||||||
Previously estimated future development costs incurred | 39,433 | 17,198 | 1,136 | |||||||||
Revisions of quantity estimates | (186,902 | ) | 60,822 | 103,940 | ||||||||
Sales, net of production costs | (88,837 | ) | (131,500 | ) | (53,011 | ) | ||||||
Timing differences and other | 1,778 | 8,512 | 3,111 | |||||||||
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Net increase (decrease) | (3,615 | ) | 669,219 | 349,003 | ||||||||
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End of year | $ | 1,057,793 | $ | 1,061,408 | $ | 392,189 | ||||||
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The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
NOTE 19—QUARTERLY FINANCIAL DATA (Unaudited)
The table below sets forth unaudited financial information for each quarter of the last two years (in thousands):
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
Year ended December 31, 2012 | ||||||||||||||||
Total revenues | $ | 76,181 | $ | 106,594 | $ | 57,125 | $ | 64,578 | ||||||||
Loss (income) from operations | 1,245 | 28,721 | (25,153 | ) | (39,631 | ) | ||||||||||
Net (loss) income | (5,654 | ) | 21,517 | (32,575 | ) | (47,256 | ) | |||||||||
Net (loss) income attributable to common unit holders | (7,454 | ) | 19,573 | (34,807 | ) | (49,488 | ) | |||||||||
Year ended December 31, 2011 | ||||||||||||||||
Total revenues | $ | 24,513 | $ | 98,849 | $ | 141,348 | $ | 75,234 | ||||||||
Loss (income) from operations | (18,196 | ) | 39,888 | 58,352 | (33,371 | ) | ||||||||||
Net (loss) income | (24,119 | ) | 28,046 | 51,114 | (40,000 | ) | ||||||||||
Net (loss) income attributable to common unit holders | (24,119 | ) | 27,446 | 49,314 | (41,800 | ) |
NOTE 20—SUBSEQUENT EVENTS
Capital Contributions. On January 25, 2013, we entered into a contribution agreement with PPVA Black Elk (Equity) LLC (“PPVA (Equity)”), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million of our Class E Preferred Units (the “Class E Units”) and 76 Class B Units (the “Class B Units”), having such rights, preferences and privileges as set
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forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. 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 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).
In the first quarter of 2013, we entered into contribution agreements with PPBE or the Platinum Group pursuant to which we have issued, or expect to issue 40 million additional Class E Units and 3 million additional Class B Units to the Platinum Group for an aggregate offering price of $40.0 million. As of April 10, 2013, we have issued an aggregate $50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013, we issued an additional 2,522,693.340 Class E Units as paid-in-kind dividends to the holders of Class E Units on such date.
Issuance of 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.
Stock Split. 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.
Sale of Properties. On March 26, 2013, we completed the sale of four fields to Renaissance Offshore, LLC for approximately $52.5 million subject to normal purchase price adjustments. Funds will be used to reduce the amount borrowed under the Credit Facility and general corporate purposes. We will also work with counterparties to release approximately $29.8 million of escrows related to the sold properties.
Letter of Credit Facility Amendment and Credit Facility Amendments.In connection with the sale of the four fields to Renaissance Offshore, LLC that closed on March 26, 2013, we entered into the Eighth Amendment to our Credit Facility which (1) lowered our borrowing base to $25 million from $61 million upon the sale of the four fields, (2) will further reduce the borrowing base to $15 million after the bonds posted with the Bureau of Ocean Management, Regulation and Enforcement related to the sold properties are released or terminated, (3) increased the applicable margin with respect to each ABR loan or Eurodollar loan outstanding by 1% if the credit exposure is greater than $15 million, (4) scheduled the borrowing base redetermination date to May 31, 2013 and (5) restricted returns of capital to our stockholders or distributions of our property to our equity interest holders.
In April 2013, we also entered into the Seventh Amendment and the Ninth Amendment to obtain waivers related to (1) the leverage ratio for the quarter ended December 31, 2012, (2) the over hedged oil position for the calendar month of January 2013 at December 31, 2012, (3) the hedge requirement only to the extent that it relates to existing oil hedges but that such noncompliance was a result of the sale of the four fields to Renaissance Offshore, LLC, provided that we will be in compliance with the covenant when the borrowing base is re-determined in May 2013 and (4) the delay in the capital contributions, which were all received by April 9, 2013. The Seventh Amendment and the Ninth Amendment removed the current ratio covenant and replaced it with a 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. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0. We paid $0.3 million to obtain the waiver.
Operating Agreement Amendment. In April 2013, we entered into the Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC (the “Fifth Amendment”) to (1) revise and confirm the order and manner of distributions to our members and (2) permit the issuance of Class E Units in an aggregate amount not to exceed $95.0 million and the issuance of Class B Units in connection with such Class E Units in an aggregate amount not to exceed 3,800,000 units before giving effect to any capitalized Class E preferred return, for cash or property capital contributions.
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New Swap Transactions.On March 20, 2013, we entered into the following swap transactions:
Remaining Contract Term: Natural Gas | Contract Type | Notational Volume in MMBtus/Month | NYMEX Strike Price | |||||||||
April 2013 - April 2013 | Swap | 56,381 | 4.085 | |||||||||
May 2013 - May 2013 | Swap | 54,278 | 4.085 | |||||||||
June 2013 - June 2013 | Swap | 25,731 | 4.085 | |||||||||
July 2013 - July 2013 | Swap | 36,765 | 4.085 | |||||||||
August 2013 - August 2013 | Swap | 34,275 | 4.085 | |||||||||
September 2013 - September 2013 | Swap | 31,739 | 4.085 | |||||||||
October 2013 - October 2013 | Swap | 34,551 | 4.085 | |||||||||
November 2013 - November 2013 | Swap | 28,939 | 4.085 | |||||||||
December 2013 - December 2013 | Swap | 37,906 | 4.085 | |||||||||
January 2014 - January 2014 | Swap | 43,347 | 4.085 | |||||||||
February 2014 - February 2014 | Swap | 32,636 | 4.085 | |||||||||
March 2014 - March 2014 | Swap | 46,764 | 4.085 | |||||||||
April 2014 - April 2014 | Swap | 41,253 | 4.085 | |||||||||
May 2014 - May 2014 | Swap | 40,391 | 4.085 | |||||||||
June 2014 - June 2014 | Swap | 20,112 | 4.085 | |||||||||
July 2014 - July 2014 | Swap | 39,283 | 4.085 | |||||||||
August 2014 - August 2014 | Swap | 34,246 | 4.085 | |||||||||
September 2014 - September 2014 | Swap | 29,753 | 4.085 | |||||||||
October 2014 - October 2014 | Swap | 28,635 | 4.085 | |||||||||
November 2014 - November 2014 | Swap | 27,081 | 4.085 | |||||||||
December 2014 - December 2014 | Swap | 34,114 | 4.085 | |||||||||
January 2015 - January 2015 | Swap | 27,838 | 4.085 | |||||||||
February 2015 - February 2015 | Swap | 24,461 | 4.085 | |||||||||
March 2015 - March 2015 | Swap | 26,443 | 4.085 | |||||||||
June 2014 - June 2014 | Swap | 40,391 | 4.185 | |||||||||
July 2014 - July 2014 | Swap | 20,112 | 4.185 | |||||||||
August 2014 - August 2014 | Swap | 39,283 | 4.185 | |||||||||
September 2014 - September 2014 | Swap | 34,246 | 4.185 | |||||||||
October 2014 - October 2014 | Swap | 29,753 | 4.185 | |||||||||
November 2014 - November 2014 | Swap | 28,635 | 4.185 | |||||||||
December 2014 - December 2014 | Swap | 27,081 | 4.185 | |||||||||
January 2015 - January 2015 | Swap | 34,114 | 4.185 | |||||||||
February 2015 - February 2015 | Swap | 27,838 | 4.185 | |||||||||
March 2015 - March 2015 | Swap | 24,461 | 4.185 |
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedure
The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
As required by Rule 15d-15(b) under the Exchange Act, management annually reviews our accounting policies and practices, and as a result of such review, in February 2013, identified it had an error in its accounting for non-routine and non-systematic transactions. As a result of this material weakness (as further discussed below), our Chief Executive Officer and Interim Chief Financial Officer have concluded that our disclosure controls and procedures as of December 31, 2012 were not effective at a reasonable level of assurance, based on the evaluation of these controls and procedures required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act. Notwithstanding the material weakness further discussed below, our Chief Executive Officer and Interim Chief Financial Officer believe that the financial statements included in this report fairly present in all material respects (and in accordance with U.S. generally accepted accounting principles) our financial condition, results of operations and cash flows for the periods presented.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined by Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is designed under the supervision of our Chief Executive Officer and Interim Chief Financial Officer in order to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of the changes within the organization and internal reporting.
We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer, of the effectiveness of our internal controls over financial reporting pursuant to Rule 13a-15(c) under the Securities Exchange Act as of the end of the period covered by this Form 10-K. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this evaluation, management used the criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In connection with such evaluation, our management identified a material weakness in our control environment based on the criteria established inInternal Control-Integrated Frameworkissued by the COSO. A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements will not be prevented or detected.
The material weakness identified was our lack of a sufficient control over our financial accounting and reporting processes regarding the accounting for non-routine and non-systematic transactions. As of December 31, 2012, management has concluded that our control over the selection and application of our accounting policies related to non-routine and non-systematic transactions were ineffective to ensure that such transactions were recorded in accordance with U.S. generally accepted accounting principles. Specifically, the updated asset portion of the revised estimate of our asset retirement obligations were not included in the impairment computation of Net Book Value. This control deficiency resulted in us recording certain adjustments prior to the issuance of our consolidated financial statements included in this Form 10-K. Because of this material weakness, management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2012.
Changes in Internal Controls over Financial Reporting
As a result of the material weakness identified, management has implemented and will continue to implement changes to our internal controls that are both organizational and process-focused in an effort to improve the control environment, including as it relates to our application of accounting principles regarding non-routine and non-systematic transactions. The changes to our control environment through the date of this Form 10-K include, among others:
• | Retirement of our former Vice President, Chief Financial Officer and Member in September 2012; |
• | Appointment of our Interim Chief Financial Officer in January 2013; |
• | Engagement in search for permanent Chief Financial Officer in 2013; |
• | Appointment of our General Counsel in January 2013; |
• | Retirement of our former Vice President, Facilities in March 2013; and |
• | Changes in certain process owners due to turnover and reduction in force. |
Process changes have improved our internal controls environment and increased the likelihood of our identifying non-routine and non-systematic transactions. We will continue our efforts to improve our control environment and to focus on improving our processes and systems to help ensure that our financial reporting, operational and business requirements are met in a timely manner going forward.
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Letter of Credit Facility Amendment and Credit Facility Amendment
On April 10, 2013, we entered into the Limited Waiver and Seventh Amendment to Letter of Credit Facility (the “Seventh Amendment”) and the Limited Waiver and Ninth Amendment to our Credit Facility (the “Ninth Amendment”) by and among Black Elk Energy Offshore Operations, LLC, as the Borrower, the Guarantors party thereto, the Lenders and Capital One, N.A. as Administrative Agent. Pursuant to the Seventh Amendment and the Ninth Amendment, the lenders under the Letter of Credit Facility and the Credit Facility granted us waivers relating to (1) the leverage ratio for the quarter ended December 31, 2012, (2) the over hedged oil position for the calendar month of January 2013 at December 31, 2012, (3) the hedge requirement only to the extent that it relates to existing oil hedges but that such noncompliance was a result of the sale of the four fields to Renaissance Offshore, LLC, provided that we will be in compliance with the covenant when the borrowing base is re-determined in May 2013 and (4) the delay in the capital contributions, which were all received by April 9, 2013. In addition, the Seventh Amendment and the Ninth Amendment removed the current ratio covenant and replaced it with a 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. For the quarter ended March 31, 2013 only, the interest coverage ratio covenant has been amended to be no less than 2.25 to 1.00 and the leverage ratio covenant has been amended to not exceed 3.5 to 1.0.
The foregoing description of the Seventh Amendment and the Ninth Amendment are qualified in their entirety by the full text of such agreements, copies of which are attached to this Form 10-K as Exhibit 4.39 and Exhibit 4.40 and are incorporated by reference herein.
Operating Agreement Amendment
On April 9, 2013, we entered into the Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC (the “Fifth Amendment”).
The Fifth Amendment amended our operating agreement to, among other things, (1) revise and confirm the order and manner of distributions to our members and (2) permit the issuance of Class E Units in an aggregate amount not to exceed $95.0 million and the issuance of Class B Units in connection with such Class E Units in an aggregate amount not to exceed 3,800,000 units before giving effect to any capitalized Class E preferred return, for cash or property capital contributions.
The foregoing description of the Fifth Amendment is qualified in its entirety by the full text of such agreement, a copy of which is attached to this Form 10-K as Exhibit 3.10 and is incorporated by reference herein.
Item 10. Directors, Executive Officers and Corporate Governance
The following table sets forth the names, ages and offices of our directors, executive officers and other key employees. There were no family relationships among any of our managers or executive officers. Pursuant to the terms of our Second Amended and Restated Operating Agreement, the members of our Board of Managers are appointed by the holders of our Class B Units and our executive officers are appointed by, and serve at the pleasure of, our Board of Managers.
Name | Age | Title | ||
John Hoffman | 54 | President, Chief Executive Officer and Manager | ||
Gary Barton | 50 | Interim Chief Financial Officer | ||
Arthur Garza | 46 | Chief Technical Officer | ||
Tad LeBlanc | 54 | Vice President, Health, Safety, Environment and Compliance | ||
Michelle Simmons | 50 | Chief Accounting Officer | ||
Daniel Small | 43 | Manager |
Set forth below is the description of the backgrounds of our managers, executive officers and other key employees.
John Hoffman.As one of our founders, John Hoffman has served as our President and Chief Executive Officer since our inception in January 2008. He has also served as a member of our Board of Managers since that time pursuant to the terms of our Second Amended and Restated Operating Agreement. Mr. Hoffman is a Registered Professional Engineer with 30 years of industry experience. Mr. Hoffman has extensive experience in field development and operations, onshore and offshore. Prior to starting and building our Company, Mr. Hoffman held various leadership positions at Amoco Corporation, a global chemical and oil company (“Amoco”), from 1981 to 1996, including from 1991 to 1996 at Gulf of Suez Petroleum, a joint venture owned in equal shares by BP and The Egyptian General Petroleum Company, BP America Inc., a leading producer of oil and natural gas in the United States, from 1996 to 2006 and Stone Energy Corporation, an independent oil and gas company, from 2006-2007. His new field development
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experience spans internationally in the Egyptian Western Desert and Gulf of Suez. In the United States, his developments include major projects in deepwater Gulf of Mexico as well as on the OCS margins. Mr. Hoffman has extensive exploitation experience and knowledge with a unique demonstrated track record of increasing reserves and production while lowering costs. Mr. Hoffman has numerous publications in journals for his work on sand control, subsea wells and innovative coiled tubing pipelines. During his time with Gulf Suez Petroleum, Mr. Hoffman was awarded the Chairman’s Award for Operational Excellence. Mr. Hoffman received this prestigious Chairman’s Award once more during his tenure with Amoco while working the Amoco Deepwater Strategy. Further distinguishing his superior business skills, Mr. Hoffman was honored as a winner of Ernst & Young Entrepreneur of the Year Gulf Coast Area Award in 2011.
Gary Barton.Gary Barton serves as our Interim Chief Financial Officer, a position he has held since January 2013.Mr. Barton also currently serves as a Senior Director with Alvarez & Marsal North America, LLC (“A&M”) in Houston, Texas, a position he has held since April 2008. A&M is a global professional services firm specializing in turnaround and interim management, performance improvement and business advisory services. Mr. Barton has more than 20 years of advisory and interim management experience. His primary areas of expertise are financial and business management and improvement, which will be the focus of his efforts at our company. Mr. Barton has extensive oil and gas experience, having advised and assumed other interim management positions with various energy industry companies. Prior to joining Alvarez & Marsal, Mr. Barton was a Senior Managing Director at FTI Consulting, Inc. from August 2002 to March 2008 and held various positions at PricewaterhouseCoopers LLP, including Partner, from 1990 to 2002. Mr. Barton received his Master in Business Administration and Bachelor of Science from Texas A&M University.
Arthur Garza.Arthur Garza serves as our Chief Technical Officer, a position he has held since October 2009. Mr. Garza has over 23 years of industry experience focused on exploitation of mature oil and gas fields. Prior to joining us, Mr. Garza held leadership positions at Hilcorp Energy Company, a privately-held exploration and production company, from July 2004 to September 2009 as GOM/Terrebonne Bay Senior Reservoir Engineer & Rockies Asset Team Manager. Mr. Garza’s extensive Gulf of Mexico experience while at Devon Energy Corporation, an independent natural gas and oil exploration and production company, from June 2002 to June 2004, Texaco Inc. from June 1994 to October 2001 and Mobil Oil Corporation from May 1992 to May 1994, span inland Louisiana, through shelf/flextrend (Green Canyon) and deepwater (Shasta, Nansen/Boomvang, Zia, Merganser). Mr. Garza’s career at Texaco included executive rotations through Strategic Planning, Power & Gasification and Project Finance. Mr. Garza participated in Texaco Reservoir Management Training Program and was a Qualified Reserves Estimator. Mr. Garza also has extensive waterflood and polymer flood experience. Mr. Garza holds a B.S./M.E. Petroleum Engineering from Texas A&M University and M.B.A. from University of Oklahoma.
Tad LeBlanc.Tad LeBlanc serves as Vice President of Health, Safety, Environmental & Compliance (HSE&C), a position he has held since August 2010. With over 25 years of oilfield related experience, Mr. LeBlanc has held various management positions in Production Operations and Maintenance and HSE&C throughout his career. Mr. LeBlanc is a Certified Occupational Safety Specialist. From 1993 through 2009, Mr. LeBlanc served as Vice President of Health Safety Environmental and Compliance for Baker Energy and continued on as a consultant through 2010. While in that role, Baker Energy received two National SAFE awards and eight District SAFE Awards from the Mineral Management Service. Mr. LeBlanc was also recognized with a Corporate Leadership Award (CORLA) by the Minerals Management Service in 2006. Also at Baker Energy, Mr. LeBlanc structured and managed the company’s first OPCO project for Mobil Oil’s Main Pass 72 Field. The scope of this project consisted of a total operations package encompassing marine/air transportation, materials procurement, and maintenance of all 25,000 Horsepower rotating equipment. In the first year of this project, a 30% reduction in operating costs was realized for the client. Mr. LeBlanc also managed the Power Plant Operations for Nantucket Electric while the underwater cable was being installed. While in that role, his team developed and implemented a preventive/predictive maintenance program for the diesel powered generation equipment resulting in a significant reduction in operating maintenance costs. Prior to Baker Energy, Mr. LeBlanc was Operations Coordinator for Freeport McMoran in New Orleans, LA. Mr. LeBlanc attended Nichols State University and graduated with degrees in Petroleum Safety and Petroleum Technology. Mr. LeBlanc also received a Technology Degree in Industrial Engines at Sowela Technical Institute.
Michelle Simmons.Michelle Simmons joined Black Elk in September 2010 and serves as Chief Accounting Officer. Ms. Simmons has over twenty-five years of accounting, budgeting and planning experience in the energy industry, with the majority of experience in exploration and production. She began her career with Union Texas Petroleum Holdings, Inc. where she held positions in the accounting, financial reporting and budgeting & planning areas. She progressed her career to various accounting leadership roles at Apache Corporation and CMS Oil and Gas Company. More recently, she served as the Corporate Controller at Frank’s International, Inc. from May 2004 through July 2006. Ms. Simmons joined Montierra Minerals & Production, LP (“Montierra”) in July 2006 as Controller. In March 2007, Eagle Rock Energy Partners, LLC acquired assets from Montierra and Ms. Simmons joined Eagle Rock Energy Partners and served as Vice President-Upstream Controller. Ms. Simmons is a member of the Board of Directors of Literacy Advance of Houston. She has a Bachelor of Science in Accounting from Florida State University.
Daniel Small.Daniel Small has served as a member of our Board of Managers since July 2009. Mr. Small was appointed to our Board of Managers pursuant to the terms of our Second Amended and Restated Operating Agreement, which allows PPVA Black Elk (US) Corp. or its affiliates to appoint one manager as long as PPVA Black Elk (US) Corp. or its successor holds units in our company.
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He is also a Managing Director at Platinum Management (NY) LLC, the investment advisor to Platinum Partners Value Arbitrage Fund LP, a New York based multi-strategy investment fund, a position he has held since January 2007. Mr. Small leads the firm’s private placement group and is responsible for overseeing the day to day activities of the group including investment management, sourcing, marketing and administration. Before joining Platinum, from January 2004 to December 2006, Mr. Small was a Senior Analyst and served on the investment committee at Glenview Capital Management, a $7.0 billion hedge fund. Mr. Small is a graduate of the Wharton School, magna cum laude, with majors in finance, accounting and political science and earned a J.D. from the University of Pennsylvania Law School.
Corporate Governance
Because the registration statement filed in June 2011 registers only debt securities and because we do not have and are not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Managers has not established a separately designated standing audit committee or made any determination as to whether any of the members of our Board of Managers, or any committees thereof, would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition.
Code of Ethics
We have adopted a Code of Business Ethics and Conduct, which sets forth ethical standards for our officers and employees. This document will be provided free of charge to any unitholder requesting a copy by writing to Investor Relations, Black Elk Energy Offshore Operations, LLC, 11451 Katy Freeway, Suite 500, Houston, Texas 77079.
Item 11. Executive Compensation
Compensation Discussion and Analysis
Introduction
Our executive compensation program is overseen by our Chief Executive Officer, Chief Financial Officer, and Human Resource Manager (the “Committee”). The Committee has the ultimate responsibility for making decisions relating to the compensation of our named executive officers. Our Chief Executive Officer reviews compensation for all of our named executive officers and makes compensation recommendations to the other members of the Committee. The Committee then evaluates the initial recommendations and conducts a separate review and evaluation of the named executive officers’ compensation. Finally, the Committee makes a final determination with respect to compensation for all named executive officers based on several factors, including individual performance, performance of the business and, to the extent available, general information related to compensation of executive officers at other private companies. As a general matter, members of the Committee do not set their own compensation. Rather, the compensation for each named executive officer on the Committee is reviewed and set by the other two members of the Committee. The Committee generally approves any changes to base salary levels, bonus opportunities and other annual compensation components on May 1, 2012. The Company did not utilize a compensation consultant in 2012.
The named executive officers for our fiscal year ending December 31, 2012, and who are described in this Compensation Discussion and Analysis section, are:
• | John Hoffman—President and Chief Executive Officer |
• | James Hagemeier—Former Chief Financial Officer |
• | Michelle Simmons—Chief Accounting Officer and Acting Principal Financial Officer from October 31, 2012 through the end of the 2012 fiscal year |
• | Arthur Garza—Chief Technical Officer |
• | Doug Fehr—Former Vice President, Facilities |
• | Tad LeBlanc—Vice President, Health Safety Environmental & Compliance |
Objective of Our Executive Compensation Program
The objective of our executive compensation program is to attract and retain experienced leaders in their respective fields of expertise to work as members of our executive team, while aligning their interests with those of our investors.
We attract and retain highly talented and experienced executives in part by setting base salaries that the Committee believes, based on the Committee members’ extensive experience in the industry, are competitive with the base salaries paid to executives at other companies like ours in the energy industry. While we do not benchmark any of our compensation against compensation paid by
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any other company, the Committee considers the total compensation paid to each named executive officer over the course of each year to ensure that the total amounts paid by us are commensurate with the Committee members’ sense of the total compensation paid by other companies with which we compete for executive talent, based on their experience in the industry.
We provide our named executive officers with the opportunity to earn cash bonus awards to reward the executives’ contribution to our success, growth, and the achievement of strategic goals. We provide our named executive officers with a portion of the distributions paid to our investors through our profit sharing arrangements. We believe that by rewarding our named executive officers for the achievement of shorter-term goals through our cash bonus awards and by allowing them to receive a portion of the distributions paid to our investors, we are attracting talented executives to join us and stay with us, while also aligning their interests with those of our investors.
Components of our Compensation
Our compensation and benefits programs have historically consisted of the following components, which are described in greater detail below:
• | Base salary; |
• | Cash bonus awards based on both individual performance and our company’s performance; |
• | Profit sharing arrangements; |
• | Severance and change in control benefits; and |
• | Participation in broad-based retirement, health and welfare benefits. |
Base Salary
Each named executive officer’s base salary is a fixed component of compensation and does not vary depending on the level of performance achieved. Base salaries for our named executive officers have historically been the product of negotiations with each individual as to what level of salary is necessary to retain the executive’s services. During these negotiations, the Committee typically considers the individual’s position, experience, past performance, and responsibilities. The Committee reviews the base salaries for each named executive annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review, the Committee considers general individual and company performance over the course of that year.
We believe each named executive officer’s base salary component of compensation is set at a level that furthers the objectives of our compensation program by providing base pay that is competitive with amounts paid by companies with which we compete for executive talent. The determination as to the ultimate amount, competitiveness, and reasonableness of a named executive officer’s salary is made by the Committee based on the members’ extensive experience in the energy industry, and the Committee’s determination is subject to approval by our Board of Managers with respect to any increase in base salary. The base salary paid to each named executive officer for the 2012 fiscal year is reported in the succeeding Summary Compensation Table. In 2012, John Hoffman did not receive a salary increase. All other officers received a salary increase as reported in the table below:
Name and Principal Position | Year | Annual Salary January - April 2012 | Annual Salary May - December 2012 | 2012 Salary Adjustment | ||||||||||||
John Hoffman, CEO | 2012 | $ | 300,000 | $ | 300,000 | $ | — | |||||||||
James Hagemeier, Former CFO | 2012 | $ | 250,000 | $ | 250,000 | $ | — | |||||||||
Arthur Garza, CTO | 2012 | $ | 250,000 | $ | 287,500 | $ | 37,500 | |||||||||
Doug Fehr, Former VPF | 2012 | $ | 250,000 | $ | 287,500 | $ | 37,500 | |||||||||
Tad LeBlanc, VP HSE&C | 2012 | $ | 210,000 | $ | 235,000 | $ | 25,000 | |||||||||
Michelle Simmons, CAO & acting PFO | 2012 | $ | 200,000 | $ | 230,000 | $ | 30,000 |
Bonuses
All bonuses provided by us to our named executive officers are paid in cash in amounts and at times determined at the discretion of the Committee. We do not set or communicate predetermined goals or metrics for the payment of our bonuses to our employees. Bonuses can be paid based on any considerations the Committee deems appropriate, including our growth and success, which may be measured at any point during the year through a number of metrics, including but not limited to, production levels, reserve growth, the achievement of strategic business goals, and financial metrics such as EBITDA. After considering these and other factors, the Committee determines when our performance and the performance of our employees warrants the payment of a cash bonus. Once the Committee determines that a bonus should be paid, it sets a “bonus pool amount,” the total amount of all bonuses that will be paid to employees. The bonus pool amount is determined in the discretion of the Committee after considering the magnitude of
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the accomplishment for which the bonus is to be paid as well as our budget. The Committee members determine the amount of each individual award after considering the level of contribution made by each employee to the accomplishment of the particular achievement and the reasonableness of each employee’s total compensation for the year, as determined in the Committee’s discretion based on the Committee members’ experience in the industry. Although all bonuses are discretionary and we have no obligation to pay any amount of bonus to any named executive officer, the Committee does take into consideration each named executive officer’s target bonus, to the extent such a target was included in the executive’s offer letter. Currently, Mr. Garza is the only named executive officer whose offer letter or employment agreement includes a target bonus. Mr. Garza’s target bonus is 25% of his annual salary. Bonuses are prorated based on length of employment during the period for which the bonus was earned, to the extent applicable.
We believe our bonus program, and in particular its flexibility, helps us to achieve the objectives of our compensation program by rewarding our named executive officers for their level of contribution to our most important achievements, thus aligning their interests with those of our investors. Further, when determining the amounts of the bonus awards to each named executive officer, the Committee considers the competitiveness of the individual bonus payments as well as the competitiveness of the overall annual pay for each named executive officer, as compared to the amounts paid to executives at the companies with which we compete for executive talent. These considerations ensure that our named executive officers’ bonus compensation is both reasonable and competitive, based on the Committee members’ experience in the industry.
No bonuses were awarded to any of our employees in 2012.
Profit Sharing
We have always believed that it is important to tie the interests of our named executive officers to those of our investors. We have historically accomplished this goal by granting profits interests in Black Elk Energy, LLC (which in turn holds a portion of our Class B Units) to a select group of our executive officers. During our reorganization in 2010, we established the Black Elk Energy Offshore Operations, LLC 2010 Employee Incentive Plan (the “Incentive Plan”), a mechanism through which we can grant profits interests in Black Elk Employee Incentive, LLC (“Incentive LLC”), which in turn holds all of our Class C Units. While our named executive officers still hold previously granted profits interests in Black Elk Energy, LLC, beginning with fiscal year 2010, we have granted only, and plan in the future to only grant profits interest to our executives solely through the Incentive Plan.
The Incentive Plan provides our executives with an opportunity to share in the distributions made to our investors. The degree to which our named executive officers share in distributions is determined by the Committee based on experience, responsibility, and tenure. Generally, upon a named executive officer’s termination from employment with us for any reason, the interests held by the individual (including any capital account) will be forfeited. The named executive officers may not sell or transfer their interests in either Black Elk Energy, LLC or Incentive LLC. To date, the only distributions that have been made to our named executive officers have been distributions equivalent to the tax liability incurred by each named executive officer by holding profits interests in Black Elk Energy, LLC or Incentive LLC.
We believe this program furthers the objectives of our compensation program by providing an opportunity for each named executive officer to earn additional compensation, thus increasing the competitiveness of our compensation packages, while aligning the named executive officers’ financial interests with those of our investors.
No awards were made under the Incentive Plan in 2012.
Severance and Change in Control Benefits
Messrs. Hoffman and Garza have (and Mr. Hagemeier had) employment agreements with us that contain severance provisions. Upon termination of Messrs. Hoffman or Garza’s employment (i) by the executive due to a material breach of the employment agreement by us, uncorrected for 30 days following written notice, (ii) by the executive upon a change in control, or (iii) by us without cause, then the executive will be entitled to receive a lump-sum severance payment in an amount equal to one year’s annual base salary of the executive, plus continuation of certain employee benefits for one year.
We believe that severance protection provisions create important retention tools, as post-termination payments would allow Messrs. Hoffman and Hagemeier to leave our employment with value primarily in the event of certain terminations of employment that were beyond their control. Post-termination payments allow our senior executive management to focus their attention and energy on making objective business decisions that are in our best interest without allowing personal considerations to cloud the decision-making process. Executive officers at other companies in our industry, and the general market against which we compete for executive talent, commonly have post-termination payments and we have consistently provided this benefit to certain of our executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry. For more information please see the section entitled “Potential Payments Upon a Termination or Change in Control” below.
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Other Benefits
We pay 100% of the insurance premiums for all of our employees, including their spouses and dependents, for health, dental, vision, life, and accidental death and dismemberment insurance. We also pay 100% of health club memberships for employees. We provide Mr. Hoffman with enhanced life and disability insurance, provide Mr. Fehr with enhanced disability insurance, and provide Messrs. Hoffman and Hagemeier (during his employment with us) with kidnap and ransom insurance; otherwise, the insurance benefits provided to our named executive officers are the same as those provided to our employees generally. In addition, in 2012 we paid for the provision of tax preparation services for Messrs. Hoffman and Hagemeier.
Our 401(k) plan is designed to encourage all employees, including the participating named executive officers, to save for the future. We make a non-elective contribution equal to 3% of each employee’s total compensation for the plan year. Additionally, we match 50% of all employee contributions to the plan, up to a maximum of 3% of each employee’s total compensation for the plan year. Thus, each of our employees receives 401(k) contributions from us of at least 3% and up to 6% (depending on the level of their own contributions) of their total compensation each year. The plan increases the competitiveness of our total compensation package and aids in retaining our named executive officers. We do not have a supplemental executive retirement plan.
Risk Assessment
The Committee has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us. The components of our compensation program are base salary, cash bonuses, profit sharing opportunities (for some employees), health and welfare benefits, and participation in a 401(k) retirement plan. These compensation components are generally uniform in design and operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered. In addition, the following factors, in particular, reduce the likelihood of excessive risk-taking:
• | Our overall compensation levels are competitive with the market, both industry-wide and geographically. |
• | Our compensation mix is balanced among (i) fixed components like salary and benefits, (ii) discretionary cash incentives that reward our overall financial performance, operational measures and individual performance, and (iii) our profit sharing arrangements. |
• | The Committee has discretion to reduce or eliminate cash bonuses when it determines that such adjustments would be appropriate based on our interests. |
In summary, although a significant portion of the compensation provided to named executive officers is performance-based, we believe our compensation programs do not encourage excessive and unnecessary risk taking by executive officers (or other employees), in particular because our cash bonuses are entirely discretionary. As such, they are not based on specific pre-determined metrics that could be manipulated by particular behavior by our employees.
Retirement of James F. Hagemeier
As of October 31, 2012, Mr. Hagemeier was no longer our employee or a board member or manager of us or any of our affiliates. In connection with Mr. Hagemeier’s departure, on November 7, 2012, we entered into a Settlement and Release of All Claims (the “Hagemeier Release Agreement”) with Mr. Hagemeier, where he generally released us and our affiliates from liability with respect to any claims he may have had against us.
The non-competition and non-solicitation provisions and covenants of Mr. Hagemeier’s employment agreement, dated as of July 13, 2012, between James F. Hagemeier and us, remain in full force and effect.
For additional information regarding the Hagemeier Release Agreement and any payments made to him upon his retirement please see the section below entitled “Potential Payments Upon Termination or a Change in Control”. For additional information regarding the employment agreement between Mr. Hagemeier and us please see the section entitled “Employment Agreements” in the Narrative Description to the Summary Compensation Table.
Actions taken after the 2012 Fiscal Year
Appointment of Interim Chief Financial Officer
On January 25, 2013, we appointed Gary Barton as our interim Chief Financial Officer. We will continue our efforts to retain a Chief Financial Officer. Mr. Barton’s appointment is in connection with our engagement of Alvarez & Marsal North America, LLC (“A&M”) in accordance with an engagement letter, dated January 25, 2013, by and between us and A&M (the “January 2013 Engagement Letter”). A&M is a global professional services firm specializing in turnaround and interim management, performance improvement and business advisory services. During Mr. Barton’s service with us, in accordance with the January 2013 Engagement
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Letter, Mr. Barton will continue to be employed by A&M and will not receive any compensation directly from us or participate in any of our employee benefit plans. We will instead pay A&M for Mr. Barton’s services and any additional personnel provided by A&M. A&M will receive $100,000 per month as compensation for Mr. Barton’s services. Additionally, we will reimburse A&M for reasonable out-of-pocket expenses of Mr. Barton and any other A&M employees.
Either party may terminate the January 2013 Engagement Letter with immediate effect. A&M and Mr. Barton are subject to confidentiality and non-solicitation obligations both during, and after, the term of the January 2013 Engagement Letter. We are subject to indemnification obligations and must provide indemnification insurance to the same extent we provide indemnification and insurance to our officers and managers. In addition, we have agreed to indemnify A&M for liabilities arising from the performance of duties pursuant to the January 2013 Engagement Letter. Such indemnification obligations exist during, and after, the term of the 2013 Engagement Letter and are in addition to any other indemnification obligations we are subject to under the 2013 Engagement Letter.
Retirement of Doug Fehr
On February 13, 2013, Mr. Fehr announced his retirement from employment with us, effective March 1, 2013. The terms of Mr. Fehr’s offer letter do not include a severance payment. However, Mr. Fehr entered into a Separation Agreement and General Release (“Fehr Agreement”) with us that provides him with (i) continued payment of base salary for a period of six months following his retirement and (ii) retention of his ownership interests in Black Elk Employee Incentive, LLC following his retirement. In exchange for these benefits, the Fehr Agreement contains a general release of claims by Mr. Fehr and covenants by Mr. Fehr with respect to confidentiality and non-disparagement.
Summary Compensation Table
The table below sets forth the annual compensation earned during the 2012 Fiscal Year by our “named executive officers,” as of December 31, 2012:
Name and Principal Position | Year | Salary ($) (1) | Bonus ($) (2) | Non-Equity Incentive Plan Compensation ($)(3) | All Other Compensation ($)(4) | Total ($) | ||||||||||||||||||
John Hoffman, CEO | 2012 | 300,000 | — | 1,555,510 | 66,705 | 1,922,215 | ||||||||||||||||||
2011 | 300,000 | 270,000 | 1,722,232 | 82,327 | 2,374,559 | |||||||||||||||||||
James Hagemeier, Former CFO | 2012 | 208,493 | — | 813,999 | 295,169 | 1,317,661 | ||||||||||||||||||
2011 | 250,000 | 150,000 | 911,431 | 32,060 | 1,343,491 | |||||||||||||||||||
Arthur Garza, CTO | 2012 | 275,000 | — | 245,430 | 12,656 | 533,086 | ||||||||||||||||||
2011 | 250,000 | 120,000 | 272,959 | 24,469 | 667,428 | |||||||||||||||||||
Doug Fehr, Former VPF | 2012 | 275,000 | — | 172,925 | 23,123 | 471,048 | ||||||||||||||||||
2011 | 250,000 | 63,000 | 200,938 | 37,060 | 550,998 | |||||||||||||||||||
Tad LeBlanc, VP HSE&C | 2012 | 226,800 | — | — | 30,398 | 257,198 | ||||||||||||||||||
Michelle Simmons, CAO & acting PFO | 2012 | 220,000 | — | 47,605 | 17,705 | 285,310 |
(1) | The amounts in this column reflect the base salary actually paid to each named executive officer during the fiscal year. |
(2) | The amounts in this column reflect the total amount of bonus compensation received by each named executive officer during the applicable fiscal year. No bonuses were paid to the named executive officers in 2012. |
(3) | The amounts in this column represent tax distributions received by each of the named executive officers with regard to forfeitable interests in Incentive LLC and Black Elk Energy, LLC, described in detail in the narrative description to the Summary Compensation Table, below. The named executive officers receive tax distributions because the LLCs in which they hold interests are categorized as partnerships for federal income tax purposes and, as such, our profits flow through and become taxable to our owners, even if no distributions are made. These tax distributions are intended to cover any tax liability the named executive officers have so incurred. The named executive officers’ interests are held indirectly through 197, 175, and 125 units in Incentive LLC that Messrs. Hoffman, Garza, and Fehr were granted during 2010, respectively and 170, 10, and 40 units in Black Elk Energy, LLC that Messrs. Hoffman, Garza, and Fehr were granted prior to 2010, respectively. Ms. Simmons indirectly holds 35 units in Incentive LLC which were granted in 2010. Mr. LeBlanc does not hold any interests. Mr. Hoffman also holds interests in us through 45 units in Management Incentive Units 09 and 827 units in Black Elk Management, LLC. These interests were granted in 2009. Prior to Mr. Hagemeier’s retirement, he held 106 units in Incentive LLC, 55 units in Black Elk Energy LLC, and 24 units in Management Incentive Units 09, and 446 units in Black Elk Management, LLC. Mr. Hagemeier no longer holds any interests in us or any of our affiliates, as these ownership interests were eliminated in conjunction with his retirement. |
(4) | With respect to Mr. Hoffman the amount in this column represents the aggregate incremental cost to us of providing the following benefits: (a) our contribution to his individual account under our 401(k) plan, (b) kidnap/ransom insurance ($988), (c) supplemental life and disability insurance ($36,266), and (d) tax preparation ($8,800). With respect to Mr. Hagemeier the amount in this column represents the aggregate incremental cost to us of providing the following benefits: (a) our contribution to his individual account under our 401(k) plan, (b) kidnap/ransom insurance ($988), (c) tax preparation ($6,900) and (d) severance payment ($275,814). With respect to Mr. Garza the amount in this column represents our contribution to his individual account under our 401(k) plan. With respect to Mr. Fehr the amount in this column represents the aggregate incremental cost to us of providing the following benefits: (a) our contribution to his individual account under our 401(k) plan and (b) supplemental disability insurance ($8,810). With respect to Mr. LeBlanc the amount in this column represents our contribution to his individual account under our 401(k) plan. With respect to Ms. Simmons the amount in this column represents our contribution to her individual account under our 401(k) plan. |
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Grants of Plan-Based Awards for the 2012 Fiscal Year
We did not grant any plan-based awards to our executive officers during the 2012 fiscal year.
Narrative Description to the Summary Compensation Table for the 2012 Fiscal Year
Offer Letters
We currently have offer letters with Messrs. Fehr and LeBlanc and Ms. Simmons (the “Offer Letters”). The Offer Letters provide the following minimum levels of base salary for Messrs. Fehr, and LeBlanc and Ms. Simmons respectively: $250,000, $190,000 and $180,000. The Offer Letters also provide that each named executive officer will be eligible to participate in our benefits programs generally. Mr. Fehr’s offer letters also provide for approximate levels of interests in us that would be granted to them under programs preceding the Incentive Plan. The Offer Letters do not provide for any specified term of employment.
Mr. LeBlanc’s offer letter includes a base salary of $190,000 and a target annual bonus equal to 25% of his annual salary, but we have the discretion to pay or not pay any amount of bonus each year. Mr. LeBlanc’s offer letter also provides for four weeks of vacation each year.
Ms. Simmons’ offer letter includes a base salary of $180,000 and a target annual bonus equal to 25% of her annual salary, but we have the discretion to pay or not pay any amount of bonus each year. Ms. Simmons’ offer letter also provides for four weeks of vacation each year.
Mr. Garza was also a party to an offer letter with us prior to July 13, 2012, the date he entered into an employment agreement with us (a detailed description of which is included directly below in the section entitled “Employment Agreements”), which superseded his offer letter. Mr. Garza’s offer letter included a base salary of $235,000 and a target annual bonus equal to 25% of his annual salary, but we had the discretion to pay or not pay any amount of bonus each year. Mr. Garza’s offer letter also provided for approximate levels of interests in us that would be granted to him under programs preceding the Incentive Plan. Mr. Garza’s offer letter provided for four weeks of vacation each year.
Employment Agreements
We entered into employment agreements with Messrs. Hoffman and Hagemeier in 2009 (collectively, the “Prior Employment Agreements”). The Prior Employment Agreements provided for a three-year term, with no automatic renewal, and a minimum base salary for Mr. Hoffman of $300,000 and for Mr. Hagemeier of $250,000. The Prior Employment Agreements generally provided that each of the executives could participate in any welfare, benefit, or incentive plan generally available to our other executive officers. Both Messrs. Hoffman and Hagemeier were entitled to four weeks of vacation per year. The Prior Employment Agreements also provided for severance payments under certain circumstances, discussed in detail below in the section entitled “Potential Payments Upon Termination or a Change in Control.” The Prior Employment Agreements also contained provisions assigning our business opportunities and any intellectual property developed by the executives while working for us to us. The Prior Employment Agreements contained a non-compete obligation that applies throughout the executives’ employment with us and—in the event of a termination of employment by us for cause or an automatic termination of employment upon death, disability, voluntary resignation, or retirement—following employment until the earlier of (i) the repayment in full of the obligations under a credit agreement, or (ii) July 13, 2012. Messrs. Hoffman and Hagemeier also agreed not to solicit our clients or employees during their employment with us and until the later of one year from their termination date or July 13, 2012. The Prior Employment Agreements also contained non-disparagement and confidentiality obligations. The Prior Employment Agreements expired on July 13, 2012.
On July 13, 2013, we entered into employment agreements with Messrs. Hoffman, Hagemeier, and Garza (collectively the “2012 Employment Agreements”). The 2012 Employment Agreements provide for a three-year term (a two-year term with respect to Mr. Garza), with no automatic renewal, and a minimum base salary for Mr. Hoffman of $300,000, Mr. Hagemeier of $250,000, and Mr. Garza of $287,500. The 2012 Employment Agreements generally provide that each of the executives can participate in any welfare, benefit, or incentive plan generally available to our other executive officers. Each of Messrs. Hoffman, Hagemeier, and Garza are entitled to four weeks of vacation per year. The 2012 Employment Agreements also provide severance payments to the executives under certain circumstances, discussed in detail below in the section entitled “Potential Payments Upon Termination or a Change in Control.” The 2012 Employment Agreements also contain provisions assigning our business opportunities and any intellectual property developed by the executives while working for us to us. The 2012 Employment Agreements contain a non-compete obligation that applies throughout the executives’ employment with us and—in the event of a termination of employment by us for cause or an automatic termination of employment upon death, disability, voluntary resignation, or retirement—following employment until the earlier of (i) the repayment in full of the obligations under a credit agreement, or (ii) July 13, 2015 (July 13, 2014 with respect to Mr. Garza). Messrs. Hoffman, Hagemeier, and Garza also agree not to solicit our clients or employees during their employment with us and until the later of (A) one year from their termination date or (B) July 13, 2015 (July 13, 2014 with respect to Mr. Garza). The 2012 Employment Agreements also contain non-disparagement and confidentiality obligations.
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The Hagemeier Release Agreement (described in more detail in the section entitled “Termination of Employment of Named Executive Officers During 2012”) terminates all previous employment, consulting, or other agreements between Mr. Hagemeier and us or our affiliates.
Profit Sharing
The distributions enumerated in the Non-Equity Incentive Plan Compensation column to the Summary Compensation Table reflect each named executive officer’s tax distributions as described in footnote 3 in this table. These tax distributions relate to interests held indirectly through interests in Incentive LLC (which in turn owns all of our Class C Units) and/or through Black Elk Energy, LLC (which in turn holds some of our Class B Units). All interests held by our named executive officers in Incentive LLC were granted during 2010 under our Incentive Plan, and interests in Black Elk Energy, LLC were granted prior to 2010. Both interests in Black Elk Energy, LLC and Incentive LLC are intended to be “profits interests.”
Awards may be granted under our Incentive Plan to our employees, directors and consultants. Awards under the Incentive Plan represent a percentage interest of the total membership interest of Incentive LLC. If an award under the Incentive Plan terminates or is canceled then new awards can be granted. Unless we determine otherwise, and except with regard to Messrs. Hoffman and Hagemeier, the termination of a named executive officer’s employment with us for any reason will terminate the executive’s ownership of any interest in Incentive LLC and that executive will not be entitled to any outstanding balance in his or her capital account. The named executive officers may not sell or transfer their interests in Incentive LLC.
Pension Benefits
We have not maintained, and do not currently maintain, a defined benefit pension plan.
Nonqualified Deferred Compensation
We have not maintained, and do not currently maintain, a nonqualified deferred compensation plan.
Potential Payments Upon Termination or a Change in Control
Messrs. Fehr and LeBlanc and Ms. Simmons
The Offer Letters with Messrs. Fehr and LeBlanc and Ms. Simmons do not contain any severance provisions. We also do not have any formal severance policy or a change in control plan. There is no payment guaranteed to Messrs. Fehr and LeBlanc and Ms. Simmons in the event of their termination of employment or a change in control. As such, they are not reflected in the table below. However, Mr. Fehr entered into a Separation Agreement and General Release (“Fehr Agreement”) with us that provides him with (i) continued payment of base salary for a period of six months following his retirement, the total amount of all such payments being $143,750 and (ii) retention of his ownership interests in Black Elk Employee Incentive, LLC following his retirement. In exchange for these benefits, the Fehr Agreement contains a general release of claims by Mr. Fehr and covenants by Mr. Fehr with respect to confidentiality and non-disparagement.
Messrs. Hoffman and Garza
Messrs. Hoffman and Garza have (and Mr. Hagemeier had) employment agreements with us that contain severance provisions. Upon termination of Messrs. Hoffman or Garza’s employment (i) by the executive due to a material breach of the employment agreement by us, uncorrected for 30 days following written notice, (ii) by the executive upon a change in control, or (iii) by us without cause, then the executive will be entitled to receive a lump-sum severance payment in an amount equal to one year’s annual base salary of the executive, plus continuation of benefits generally provided to our executives, currently including company 401(k) contribution, plus continued medical, dental, vision, life and disability insurance coverage for one year.
The 2012 Employment Agreements provide that “cause” means generally (i) the executive’s conviction of, or plea of nolo contendere to, any felony or to any crime or offense causing substantial harm to us or involving acts of theft, fraud, or embezzlement, (ii) willful and intentional misuse or diversion of any of our funds, (iii) embezzlement, (iv) fraudulent or willful and material misrepresentations, or (v) material breach by executive of any material provision of the 2012 Employment Agreements which is not corrected within 30 days following written notice.
The 2012 Employment Agreements provide that “change of control” means generally (i) the sale or lease of substantially all of our assets, or (ii) a transaction in which the holders of our voting stock immediately prior to such transaction own, immediately after such transaction, securities representing less than 50% of the voting power of the surviving entity. A transaction solely for the purpose of effecting a change in our domicile will not constitute a “change of control.”
The following table enumerates the payments that would have been due to Messrs. Hoffman and Garza if their employment had been terminated on December 31, 2012, (i) due to a material breach of the employment agreement by us, uncorrected for 30 days following written notice, (ii) by the executive upon a change in control, or (iii) by us without cause.
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Name and Principal Position | One Year of Base Salary Paid in Lump-Sum(1) | Value of One Year of Benefits(2) | Total Value of Severance Obligation | |||||||||
John Hoffman, CEO | $ | 300,000 | $ | 68,389 | $ | 368,389 | ||||||
Arthur Garza, CTO | 287,500 | 14,317 | 301,817 |
(1) | The numbers in this column represent each executive’s base salary in effect as of December 31, 2012. |
(2) | The numbers in this column represent a lump sum payment in an amount equal to our 401(k) contribution for a year ($13,750 for Mr. Hoffman and $12,656 for Mr. Garza) as well as the value of medical, dental, vision, life and disability insurance coverage for one year ($68,389 for Mr. Hoffman and $14,317 for Mr. Garza). The lump sum amount with respect to 401(k) contribution is calculated based on our contribution to each executive’s individual 401(k) account for fiscal year 2012. Mr. Hoffman’s benefit cost is higher than Mr. Garza’s because Mr. Hoffman receives additional life and disability insurance in excess of what Mr. Garza receives. |
Mr. Hagemeier
On September 27, 2012, Mr. Hagemeier announced his retirement. As of October 31, 2012, Mr. Hagemeier was no longer our employee or a board member or manager of us or any of our affiliates.
In consideration for Mr. Hagemeier’s execution of the Hagemeier Release Agreement on November 7, 2012, and per terms in is most recent employment agreement with us, dated July 13, 2012, we (1) made a lump-sum cash payment to Mr. Hagemeier in the amount of $275,814 which is comprised of the amount of one year’s annual base salary and benefits and (2) agreed to indemnify and hold harmless Mr. Hagemeier to the fullest extent permitted by law from and against all losses, liabilities, and expenses of any nature, judgments, fines, settlements and other amounts arising from any and all claims, demands, actions, suits or proceedings in which Mr. Hagemeier was involved or threatened to be involved, as a party or otherwise, arising out of or incidental to the business activities of or relating to us or our affiliates.
James Hagemeier’s employment agreement included severance and the release followed the terms of the employment agreement with one exception: the non-solicitation term was one year in the employment agreement and two years in the release agreement.
The non-competition and non-solicitation provisions and covenants of Mr. Hagemeier’s employment agreement remain in full force and effect.
The following table enumerates the amount of severance paid to James Hagemeier:
2012 Severance Payments: | Severance | Benefits | Total | |||||||||
James Hagemeier, Former CFO | 250,000 | 25,814 | 275,814 |
Director Compensation
We do not compensate any of our managers for their service on our Board. We do, however, reimburse our managers for expenses associated with travel to and from any required board meetings.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Our membership interests are represented by Class A Units, Class B Units, Class C Units, Class D Units, and Class E Units. 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 our 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.
As of April 10, 2013, there were 1,361,300 Class A Units, 114,277,308.5 Class B Units, 12,031,250 Class C Units and 95,550,693.34 Class E Units issued and outstanding. The outstanding 30,000,000 Class D Units and 13,028,000 of paid-in-kind dividends were exchanged on January 25, 2013 for 43,028,000 of Class E Units. The Class A and Class B Units have voting rights; the Class C Units and Class E Units do not have voting rights.
None of our managers or executive officers directly owns any Class A Units, Class B Units, Class C Units, or Class E Units. All of our issued and outstanding Class A Units are owned by PPVA Black Elk (Equity) LLC (“PPVA (Equity)”), a wholly owned subsidiary of Platinum Partners Value Arbitrage Fund, L.P. PPVA (Equity) and PPVA Black Elk (Investor) LLC, additional wholly owned subsidiaries of Platinum Partners Value Arbitrage Fund, L.P., and Platinum Partners Black Elk Opportunities Fund, LLC (“PPBE”) also own Class B Units. PPVA (Equity), PPBE, and Platinum Partners Black Elk Opportunities Fund International, LLC also own our issued and outstanding Class E Units. Additional information regarding Platinum’s significant ownership interest in us is set forth below, as well as under “Item 13. Certain Relationships and Related Transactions and Director Independence” in this Form 10-K.
Our executive officers and other key employees indirectly own Class B Units through their ownership of Black Elk Energy, LLC. See “Item 11. Executive Compensation—Components of our Compensation—Profit Sharing” for additional information. Our Chief Executive Officer also indirectly owns Class B Units through his ownership of Black Elk Management, LLC.
All of our issued and outstanding Class C Units are held by Black Elk Employee Incentive, LLC. Class C Units are profits interests that are awarded from time to time to our executive officers and other key employees. See “Item 11. Executive Compensation—Components of our Compensation—Profit Sharing” for additional information regarding the Class C Units.
The following table sets forth information regarding the beneficial ownership of our total voting membership interests, consisting of our Class A and Class B Units, as of April 10, 2013 for:
• | each of our members; |
• | each of our executive officers; |
• | all our members and executive officers as a group; and |
• | each other person known by us to beneficially own more than 5% of our total voting membership interests. |
Footnote 1 to the following table provides a brief explanation of what is meant by the term “beneficial ownership.” The voting membersh
ip interests and related percentages of beneficial ownership are based on our total outstanding voting membership interests as of April 10, 2013. The amounts presented may not add due to rounding.
To our knowledge and except as indicated in the footnotes to this table and subject to applicable community property laws, the persons named in this table have the sole voting power with respect to the membership interests listed as beneficially owned by them.
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Name and Address of Beneficial Owner(1) | Number of Class A Units Beneficially Owned | Number of Class B Units Beneficially Owned | Percentage of Voting Membership Interests Beneficially Owned (2) | |||||||||
Manager and Named Executive Officers(3): | ||||||||||||
John Hoffman (4) | — | 9,030,756.94 | 7.90 | % | ||||||||
Dan Small | — | — | 0.00 | % | ||||||||
Arthur Garza(5) | — | 57,411.27 | * | |||||||||
Doug Fehr(6) | — | 229,645.09 | * | |||||||||
Tad LeBlanc | — | — | 0.00 | % | ||||||||
Michelle Simmons | — | — | 0.00 | % | ||||||||
All Managers and Executive Officers as a Group (Six persons) | — | 9,317,813.30 | 8.15 | % | ||||||||
5% Beneficial Owners: | ||||||||||||
Black Elk Management, LLC(4) (7) | — | 8,267,187.00 | 7.23 | % | ||||||||
PPVA Black Elk (Equity) LLC(8) | 1,361,300.00 | 72,808,821.50 | 63.71 | % | ||||||||
PPVA Black Elk (Investor) LLC(9) | — | 21,919,100.00 | 19.18 | % | ||||||||
Platinum Partners Black Elk Opportunities Fund, LLC(10) | — | 1,284,400.000 | 1.12 | % | ||||||||
Platinum Partners Credit Opportunities Fund International, LLC (11) | 360,000.000 | 0.32 | % |
* | Less than 1% |
(1) | “Beneficial ownership” is a term broadly defined by the SEC in Rule 13d-3 under the Exchange Act and includes more than the typical forms of stock ownership, that is, stock held in the person’s name. The term also includes what is referred to as “indirect ownership,” meaning ownership of shares as to which a person has or shares investment or voting power, or a person who, though a trust or proxy, prevents the person from having beneficial ownership. For the purpose of this table, a person or group of persons is deemed to have “beneficial ownership” of any units as of April 9, 2013, if that person or group has the right to acquire such units within 60 days after such date. |
(2) | The percentage of voting members interests in based on voting Class A Units and Class B Units. |
(3) | The address for each manager and executive officer is: c/o Black Elk Energy LLC, 11451 Katy Freeway, Houston, Texas 77079 Suite 500, Houston, Texas 77079. |
(4) | Includes (i) 8,267,187 Class B Units held indirectly through Mr. Hoffman’s 100% ownership of Black Elk Management, LLC and (ii) 763,569.94 Class B Units held indirectly through Mr. Hoffman’s 13.9% ownership of Black Elk Energy, LLC (Black Elk Energy, LLC owns less than 5% of our voting membership interests). |
(5) | These Class B Units are held indirectly through Mr. Garza’s 1.04% ownership of Black Elk Energy, LLC (Black Elk Energy, LLC less than 5% of our voting membership interests). Mr. Garza does not have any voting or dispositive power with respect to these Class B Units. Mr. Garza disclaims any beneficial ownership of these Class B Units, except to the extent of his pecuniary interest therein. |
(6) | These Class B Units are held indirectly through Mr. Fehr’s 4.18% ownership of Black Elk Energy, LLC (Black Elk Energy, LLC less than 5% of our voting membership interests). Mr. Fehr does not have any voting or dispositive power with respect to these Class B Units. Mr. Fehr disclaims any beneficial ownership of these Class B Units, except to the extent of his pecuniary interest therein. |
(7) | Black Elk Management, LLC is owned 100% by Mr. Hoffman. Mr. Hoffman has voting and dispositive power with respect to 826.72 of the Class B Units held by Black Elk Management, LLC. Mr. Hoffman disclaims any beneficial ownership of these Class B Units, except to the to the extent of his pecuniary interest therein. Black Elk Management, LLC has the following address: c/o Black Elk Energy, 11451 Katy Freeway, Suite 500, Houston, Texas 77079. |
(8) | PPVA Black Elk (Equity) LLC is wholly owned by Platinum Partners Value Arbitrage Fund, L.P. which has sole voting and dispositive power with respect to such Class A and Class B Units. PPVA Black Elk (Equity) LLC has the following address: c/o Platinum Partners Value Arbitrage Fund, L.P., 152 West 57th Street, 4th Floor, New York, New York 10019. |
(9) | PPVA Black Elk (Investor) LLC is wholly owned by Platinum Partners Value Arbitrage Fund, L.P. which has sole voting and dispositive power with respect to such Class B Units. PPVA Black Elk (Investor) LLC has the following address: c/o Platinum Partners Value Arbitrage Fund, L.P., 152 West 57th Street, 4th Floor, New York, New York 10019. |
(10) | Platinum Partners Black Elk Opportunities Fund, LLC has the sole voting and dispositive power with respect to such Class B Units. Platinum Partners Black Elk Opportunities Fund, LLC has the following address: 152 West 57th Street, 54th Floor, New York, New York 10019. |
(11) | Platinum Partners Credit Opportunities Fund International, LLC has the sole voting and dispositive power with respect to such Class B Units. Platinum Partners Platinum Partners Credit Opportunities Fund International, LLC has the following address: 152 West 57th Street, 54th Floor, New York, New York 10019. |
Through its ownership, and pursuant to the terms of our Second Amended and Restated Operating Agreement, (as amended and in effect as of the date of this Form 10-K), Platinum is able to exercise significant control over us, including the determination of
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company and management policies, our financing arrangements, the payment of dividends or other distributions, and the outcome of certain company transactions or other matters submitted to our members for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Platinum also has the ability to appoint all of the members of our Board of Managers and the Board of Managers, in turn, has the power to appoint and remove our officers. Platinum also has the ability to determine the outcome of most actions requiring approval by our members, including veto power. Specifically, without Platinum’s consent, we may not:
• | amend our Second Amended and Restated Operating Agreement or our Certification of Incorporation; |
• | approve or materially modify executive compensation; |
• | repurchase any of our units or other equity securities; |
• | enter into any merger, consolidation, reorganization or other business combination or transaction; |
• | sell, transfer, lease, license, pledge or dispose of any of our assets for a purchase price of more than $0.5 million other than capital expenditures and acquisitions contemplated by our annual budget; |
• | initiate any public offering; |
• | enter into a transaction with any of our managers or members or affiliate or member of family thereof; |
• | enter into a transaction that would have a materially disproportionate impact on Platinum over our other members; or |
• | make any distribution other than that contemplated by our Second Amended and Restated Operating Agreement. |
Additionally, if we propose to obtain additional financing through the issuance of equity or certain debt securities, Platinum is entitled to a right of first offer to provide such financing. Platinum, along with the other members, also has a right of first refusal with respect to other equity holders’ proposed transfers of our equity interests.
Platinum may transfer all or a portion of its ownership interests to a third party without the consent of the other members. The new owner of the Platinum ownership interest may then be in a position to replace our Board of Managers and officers with its own designees and thereby exert significant control over the decisions made by our Board of Managers and officers.
For additional information regarding the risk associated with Platinum’s significant ownership interest in us, see “Item 1A. Risk Factors—Platinum owns approximately 84% of our outstanding voting membership interests, giving it influence and control in corporate transactions and other matters, which may conflict with noteholders’ interests.”
Item 13. Certain Relationships and Related Transactions and Director Independence
Director Independence
For a description of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”
Certain Relationships and Related Transactions
Platinum
On May 31, 2011, Platinum entered into a contribution agreement with us, whereby Platinum made a capital contribution of $10 million in cash and $20 million of financial instruments deemed by us to be a cash equivalent, collateralized by certain accounts receivables, in exchange for 30 million of our Class D Units, having such rights, preferences and privileges as set forth in our Second Amendment and Restated Operating Agreement, as amended. The Class D Units were issued in the name of Platinum’s wholly owned subsidiary, PPVA Black Elk (Equity) LLC.
On January 25, 2013, we entered into a contribution agreement with PPVA (Equity), whereby PPVA (Equity) made a capital contribution of $10 million in exchange for 10 million of our Class E Units and 76 Class B Units, having such rights, preferences and privileges as set forth in our Third Amendment to Second Amended and Restated Limited Liability Operating Agreement. 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 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).
In the first quarter of 2013, we entered into contribution agreements with PPBE or the Platinum Group pursuant to which we have issued, or expect to issue 40 million additional Class E Units and 3 million additional Class B Units to the Platinum Group for an aggregate offering price of $40.0 million. As of April 10, 2013, we have issued an aggregate $50.0 million of Class E Units and 3.8 million Class B Units. On March 31, 2013, we issued an additional 2,522,693.340 Class E Units as paid-in-kind dividends to the holders of Class E Units on such date.
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.
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Platinum also guarantees our obligations under the W&T Escrow Accounts and the surety bonds in favor of Nippon and the BOEMRE with respect to our future P&A obligations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Other Indebtedness—W&T Escrow Accounts”.
Freedom Logistics LLC
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 member of our management), 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. As of December 31, 2011, the balance of the loan was $3.0 million. On August 1, 2012, Freedom entered into a purchase agreement with Gulf State Aviation, whereby Gulf State Aviation purchased certain aircraft equipment from Freedom, including the two helicopters. The proceeds of the sale were applied to the balance of the guaranteed loan when the sale was finalized in December 2012 and there was no remaining balance due on the loan as of December 31, 2012. 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 and there was no remaining balance as of February 28, 2013.
Freedom Well Services, LLC
In April 2011, Freedom Well Services, (“FWS”) was formed by us, certain members of our management, Freedom Well Services Employee Incentive, LLC and Platinum, our majority equity holder, to provide well P&A, slick line and electronic line services as well as consulting services around platform decommissioning and removal. Although we did not contribute capital for start-up costs, we funded the purchase of equipment as a prepayment for services rendered with the expectation that the prepayment will be reimbursed as the business continues to grow and generate cash flows. The entry into this arrangement and related matters was approved by our full Board of Managers. As of December 31, 2012 and February 28, 2013, we have advanced $8.7 million to FWS which is included in “Prepaid expenses and other” on our balance sheet. FWS also leased office space from us until February 2013. The amount due for rent at December 31, 2012 and February 28, 2013 was $0.1 million for each period, respectively. FWS also provided us well P&A and other services. As of December 31, 2012 and February 28, 2013, we owed FWS $0.3 million and $38,862, respectively.
Black Elk Energy Expenses
We pay expenses for certain general and administrative and operating costs on behalf of Black Elk Energy, LLC, the parent company of Black Elk Energy Land Operations, LLC and Black Elk Energy Finance Corp. At December 31, 2012 and February 28, 2013, we had receivables from Black Elk Energy, LLC in the amount of $23,430.
For the years ended December 31, 2012, 2011 and 2010, we paid $0.2 million, $1.0 million and $0.5 million, respectively, to Up and Running Solutions, LLC, for IT consulting services. Up and Running Solutions, LLC is owned by the wife of an employee, David Cantu (a member of our management). There were no amounts due to the related party at December 31, 2012 or at February 28, 2013.
Policies and Procedures
In the ordinary course of business, we may enter into a related person transaction (as such is defined by the SEC). The policies and procedures relating to the approval of related person transactions are not in writing. Given the relatively small size of our organization, any material related person transactions entered into would be discussed with management and require approval by our Board prior to entering into the transaction.
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Item 14. Principal Accounting Fees and Services
UHY LLP has been retained since 2010 and has performed audit services for the years ended December 31, 2012 and 2011. The following table sets forth the aggregate fees and costs paid to UHY LLP during the last two fiscal years for professional services rendered to us:
Years Ended December 31, | ||||||||
2012 | 2011 | |||||||
Audit Fees(1) | $ | 282,083 | $ | 399,999 | ||||
Audit-Related Fees (2) | — | — | ||||||
Tax Fees(3) | — | — | ||||||
All Other Fees(4) | — | — | ||||||
|
|
|
| |||||
$ | 282,083 | $ | 399,999 | |||||
|
|
|
|
(1) | Reflects fees for services rendered for the audit of our annual financial statements, review of our quarterly financial statements, fees for the review and issuance of consents and comfort letters related to our registration statements, and other SEC filings. |
(2) | No fees were paid to UHY LLP for audit-related services. |
(3) | No fees were paid to UHY LLP for tax services. |
(4) | No other fees were paid to UHY LLP. |
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Item 15. Exhibits, Financial Statement Schedules
(a) | The following documents are filed as a part of this Form 10-K: |
(1) | Financial Statements—See “Item 8. Financial Statements and Supplementary Data” of this Form 10-K. |
(2) | Financial Statement Schedules—All schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the Consolidated Financial Statements and notes thereto. |
(3) | Exhibits—The following is a list of exhibits filed as part of this Form 10-K including those incorporated by reference. |
Exhibit | Description | |
3.1 | Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.2 | Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.3 | Certificate of Formation of Black Elk Energy Finance Corporation, dated as of October 26, 2010 (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.4 | Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226). | |
3.5 | First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.6 | Bylaws of Black Elk Energy Finance Corp., dated as of October 26, 2010 (incorporated by reference to Exhibit 3.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.7 | Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
3.8 | Third Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of January 25, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on January 31, 2013). | |
3.9 | Fourth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of February 12, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on February 19, 2013). | |
*3.10 | Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013. | |
4.1 | Indenture, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., as Issuers, the Guarantor party named therein, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). |
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Exhibit | Description | |
4.2 | First Supplemental Indenture, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. as issuers, Black Elk Energy Land Operations, LLC as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
4.3 | Registration Rights Agreement, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., the Guarantor party named therein and the Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.4 | Security Agreement, dated as of November 23, 2010, by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC in favor of The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.5 | Credit Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, each of the Lenders from time to time party thereto, and Capital One, N.A. as administrative agent for the Lenders (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.6 | First Amendment to Credit Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
4.7 | Security Agreement, dated as of December 24, 2010, made by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC, and The Other Grantors Party Thereto, in favor of Capital One, N.A, not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.8 | Pledge and Security Agreement, dated as of December 24, 2010, by Black Elk Offshore Operations, LLC as Pledgor in favor of Capital One, N.A. as Collateral Agent (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.9 | Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to the certain Credit Agreement dated as of even date therewith by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.10 | Letter of Credit Facility Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, as Borrower, Capital One, N.A., as Administrative Agent and the Lenders Party Thereto (incorporated by reference to Exhibit 4.8 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.11 | First Amendment to Letter of Credit Facility Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
4.12 | Security and Pledge Agreement, dated as of December 24, 2010, between Black Elk Energy Offshore Operations, LLC and Capital One N.A., not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.9 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). |
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Exhibit | Description | |
4.13 | Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower, in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders pursuant to that certain Letter of Credit Facility Agreement dated as of even date herewith, by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.10 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.14 | Intercreditor Agreement, entered into as of December 24, 2010, by and among BP Corporation North America Inc., Black Elk Offshore Operations, LLC, and Capital One, National Association, as Administrative Agent for itself and the Lenders party to the Credit Agreement referred to therein (incorporated by reference to Exhibit 4.11 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.15 | Amended and Restated Second Lien Intercreditor Agreement, dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as First Lien Agent for the First Lien Creditors, The Bank of New York Mellow Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Second Lien Creditors, Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.12 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)). | |
4.16 | Amended and Restated Intercreditor Agreement (Escrow Agreements), dated as of December 24, 2010, by and among W&T Offshore, Inc., Capital One, N.A., in its capacity as agent for the Second Lien Creditors, and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.13 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.17 | Amended and Restated Intercreditor Agreement (Non-Operated Properties), dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as Facility/Swap Agent for the Facility/ Swap Creditors, The Bank of New York Mellon Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Notes Creditors, W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each of the other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.14 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.18 | Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated October 29, 2009, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc (incorporated by reference to Exhibit 4.15 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.19 | First Amendment to Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated November 23, 2010, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc. (incorporated by reference to Exhibit 4.16 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.20 | Partial Release by Obligee of Record, effective November 23, 2010, of that certain Mortgage, Deed of Trust, Collateral Assignment and Security Agreement, dated as of October 29, 2009, by Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.17 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.21 | Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.18 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.22 | First Amendment to Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.19 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). |
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Exhibit | Description | |
4.23 | Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.20 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.24 | Operated Deposit Account Control Agreement, executed and delivered October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association (incorporated by reference to Exhibit 4.21 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.25 | Non-Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.22 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.26 | First Amendment to Non-Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.23 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011(SEC File No. 333-174226)). | |
4.27 | Non-Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.24 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.28 | Non-Operated Deposit Account Control Agreement, executed and delivered as of October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, and Amegy Bank National Association (incorporated by reference to Exhibit 4.25 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.29 | Second Amendment to Letter of Credit Facility Agreement, dated as of December 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012). | |
4.30 | Third Amendment to Letter of Credit Facility Agreement, dated as of May 24, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012). | |
4.31 | Limited Waiver and Third Amendment to Credit Agreement, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012). | |
4.32 | Fourth Amendment to Letter of Credit Facility Agreement and Waiver, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012). | |
4.33 | Fourth Amendment to Credit Agreement and Other Loan Documents, effective as of December 21, 2012, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). |
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Exhibit | Description | |
4.34 | Sixth Amendment to Credit Agreement, effective as of January 31, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.35 | Limited Waiver and Seventh Amendment to Credit Agreement, effective as of February 22, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.36 | Fifth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of December 21, 2012, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.4 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.37 | Sixth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of February 22, 2013, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.5 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.38 | Eighth Amendment to Credit Agreement, effective as of March 26, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013). | |
*4.39 | Limited Waiver and Ninth Amendment to Credit Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto. | |
*4.40 | Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders, and the Lenders signatory thereto. | |
10.1 | Purchase and Sale Agreement, dated September 14, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.2 | First Amendment to Purchase and Sale Agreement, dated as of October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.3 | Second Amendment to Purchase and Sale Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc. and Black Elk Offshore Operations, LLC (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.4 | Purchase and Sale Agreement between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC, dated as of August 5, 2010 (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.5 | Amendment to Purchase and Sale Agreement, entered into as of September 30, 2010, by and between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.6 | Purchase and Sale Agreement, executed on March 17, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)). |
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Exhibit | Description | |
10.7 | Amendment to Purchase and Sale Agreement, executed on March 30, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
10.8 | Second Amendment to Purchase and Sale Agreement, executed on May 18, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
10.9 | Third Amendment to Purchase and Sale Agreement, executed on May 31, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.7 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
†10.10 | Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and John G. Hoffman (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013). | |
†10.11 | Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and Arthur Garza III (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013). | |
†10.12 | Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and James F. Hagemeier (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2012). | |
†*10.13 | Engagement Letter, dated January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and Alvarez & Marsal North America, LLC. | |
10.14 | Waiver and Second Amendment to Credit Agreement, dated as of June 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.6 to the Form 10-Q for the period ended June 30, 2011 as filed with the Securities and Exchange Commission on August 10, 2011 (SEC File No. 333-174226)). | |
10.15 | Waiver, dated as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Form 10-Q for the period ended September 30, 2011 as filed with the Securities and Exchange Commission on November 10, 2011 (SEC File No. 333-174226)). | |
†10.16 | Amended and Restated Company Agreement of Black Elk Employee Incentive, LLC, dated as of August 20, 2010 (incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 26, 2012. | |
10.17 | Third Amendment to Purchase and Sale Agreement, dated December 19, 2012, by and between W&T Offshore, Inc. and the Company (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
*10.18 | Contribution Agreement, dated as of January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and PPVA Black Elk Energy (Equity) LLC. | |
*10.19 | Letter Agreement, dated February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Value Arbitrage Fund LP. | |
*10.20 | Contribution Agreement, dated as of February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. |
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Exhibit | Description | |
*10.21 | Contribution Agreement, dated as of February 13, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
*10.22 | Contribution Agreement, dated as of February 14, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
*10.23 | Contribution Agreement, dated as of February 22, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
10.24 | Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of March 1, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013). | |
10.25 | First Amendment to Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of March 22, 2013 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013). | |
*10.26 | Offer and Separation Agreement and General Release Offer, dated as of April 1, 2013, by and between Black Elk Energy Offshore Operations, LLC and Douglas W. Fehr. | |
*12.1 | Computation of Ratio of Earnings to Fixed Charges. | |
*21.1 | Subsidiary List of Black Elk Energy Offshore Operations, LLC. | |
*23.1 | Consent of Netherland, Sewell & Associates, Inc. | |
*31.1 | Certification of Principal Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
*31.2 | Certification of Principal Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
*32.1 | Section 1350 Certifications of Principal Executive Officer and Principal Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
*99.1 | Summary Report of Netherland, Sewell & Associates, Inc. | |
101.INS§ | XBRL Instance Document | |
101.SCH§ | XBRL Taxonomy Extension Schema Document | |
101.CAL§ | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF§ | XBRL Taxonomy Extension Definition Presentation Linkbase Document | |
101.LAB§ | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE§ | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. |
† | Management contract or compensatory plan or arrangement. |
§ | Furnished with this Form 10-K. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing. |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC | ||
By: | /s/ Gary Barton | |
Gary Barton | ||
Interim Chief Financial Officer |
April 15, 2013
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ John Hoffman John Hoffman | President, Chief Executive Officer and Manager (Principal Executive Officer) | April 15, 2013 | ||
/s/ Gary Barton Gary Barton | Interim Chief Financial Officer (Principal Financial Officer) | April 15, 2013 | ||
/s/ Daniel Small Daniel Small | Manager | April 15, 2013 |
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EXHIBIT INDEX
Exhibit | Description | |
3.1 | Certificate of Formation of Black Elk Energy Offshore Operations, LLC, dated as of November 20, 2007 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.2 | Certificate of Amendment of Black Elk Energy Offshore Operations, LLC, dated as of January 29, 2008 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.3 | Certificate of Formation of Black Elk Energy Finance Corporation, dated as of October 26, 2010 (incorporated by reference to Exhibit 3.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.4 | Second Amended and Restated Limited Liability Company Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated as of July 13, 2009 (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226). | |
3.5 | First Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC, dated August 19, 2010 (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.6 | Bylaws of Black Elk Energy Finance Corp., dated as of October 26, 2010 (incorporated by reference to Exhibit 3.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
3.7 | Second Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of May 31, 2011 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
3.8 | Third Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of January 25, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on January 31, 2013). | |
3.9 | Fourth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of February 12, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed with the Securities and Exchange Commission on February 19, 2013). | |
*3.10 | Fifth Amendment to Second Amended and Restated Operating Agreement of Black Elk Energy Offshore Operations, LLC dated as of April 9, 2013. | |
4.1 | Indenture, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., as Issuers, the Guarantor party named therein, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.2 | First Supplemental Indenture, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. as issuers, Black Elk Energy Land Operations, LLC as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
4.3 | Registration Rights Agreement, dated as of November 23, 2010, among Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp., the Guarantor party named therein and the Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). |
Table of Contents
Index to Financial Statements
Exhibit | Description | |
4.4 | Security Agreement, dated as of November 23, 2010, by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC in favor of The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.5 | Credit Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, each of the Lenders from time to time party thereto, and Capital One, N.A. as administrative agent for the Lenders (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.6 | First Amendment to Credit Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
4.7 | Security Agreement, dated as of December 24, 2010, made by Black Elk Energy Offshore Operations, LLC, Black Elk Energy Finance Corp., Black Elk Energy Land Operations, LLC, and The Other Grantors Party Thereto, in favor of Capital One, N.A, not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.8 | Pledge and Security Agreement, dated as of December 24, 2010, by Black Elk Offshore Operations, LLC as Pledgor in favor of Capital One, N.A. as Collateral Agent (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.9 | Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders to the certain Credit Agreement dated as of even date therewith by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.10 | Letter of Credit Facility Agreement, dated as of December 24, 2010, among Black Elk Energy Offshore Operations, LLC, as Borrower, Capital One, N.A., as Administrative Agent and the Lenders Party Thereto (incorporated by reference to Exhibit 4.8 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.11 | First Amendment to Letter of Credit Facility Agreement, dated as of May 31, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
4.12 | Security and Pledge Agreement, dated as of December 24, 2010, between Black Elk Energy Offshore Operations, LLC and Capital One N.A., not in its individual capacity, but solely as Administrative Agent (incorporated by reference to Exhibit 4.9 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.13 | Guaranty Agreement, dated as of December 24, 2010, by each of the Subsidiaries of the Borrower, in favor of Capital One, N.A., as Administrative Agent for the benefit of the Lenders pursuant to that certain Letter of Credit Facility Agreement dated as of even date herewith, by and among the Borrower, the Agent and the Lenders (incorporated by reference to Exhibit 4.10 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.14 | Intercreditor Agreement, entered into as of December 24, 2010, by and among BP Corporation North America Inc., Black Elk Offshore Operations, LLC, and Capital One, National Association, as Administrative Agent for itself and the Lenders party to the Credit Agreement referred to therein (incorporated by reference to Exhibit 4.11 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). |
Table of Contents
Index to Financial Statements
Exhibit | Description | |
4.15 | Amended and Restated Second Lien Intercreditor Agreement, dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as First Lien Agent for the First Lien Creditors, The Bank of New York Mellow Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Second Lien Creditors, Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.12 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)). | |
4.16 | Amended and Restated Intercreditor Agreement (Escrow Agreements), dated as of December 24, 2010, by and among W&T Offshore, Inc., Capital One, N.A., in its capacity as agent for the Second Lien Creditors, and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.13 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.17 | Amended and Restated Intercreditor Agreement (Non-Operated Properties), dated as of December 24, 2010, by and among Capital One, N.A., in its capacity as Facility/Swap Agent for the Facility/ Swap Creditors, The Bank of New York Mellon Trust Company, N.A., in its capacity as Indenture Trustee and in its capacity as Collateral Agent for, on behalf of and in the stead of, the Notes Creditors, W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Black Elk Energy Finance Corp. and each of the other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 4.14 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.18 | Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated October 29, 2009, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc (incorporated by reference to Exhibit 4.15 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.19 | First Amendment to Mortgage, Deed of Trust, Collateral Assignment, Security Agreement and Financing Statement, dated November 23, 2010, by and between Black Elk Energy Offshore Operations, LLC and W&T Offshore, Inc. and W. Reid Lea, as Trustee for the benefit of W&T Offshore, Inc. (incorporated by reference to Exhibit 4.16 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.20 | Partial Release by Obligee of Record, effective November 23, 2010, of that certain Mortgage, Deed of Trust, Collateral Assignment and Security Agreement, dated as of October 29, 2009, by Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.17 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.21 | Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.18 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.22 | First Amendment to Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.19 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.23 | Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.20 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.24 | Operated Deposit Account Control Agreement, executed and delivered October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association (incorporated by reference to Exhibit 4.21 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.25 | Non-Operated Escrow Agreement, dated as of October 29, 2009, but effective as of August 1, 2009, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.22 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). |
Table of Contents
Index to Financial Statements
Exhibit | Description | |
4.26 | First Amendment to Non-Operated Escrow Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc., Black Elk Energy Offshore Operations, LLC and Amegy Bank National Association, as escrow agent (incorporated by reference to Exhibit 4.23 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011(SEC File No. 333-174226)). | |
4.27 | Non-Operated Deposit Account Security Agreement, dated October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 4.24 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.28 | Non-Operated Deposit Account Control Agreement, executed and delivered as of October 29, 2009, among W&T Offshore, Inc., Black Elk Energy Offshore Operations, and Amegy Bank National Association (incorporated by reference to Exhibit 4.25 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
4.29 | Second Amendment to Letter of Credit Facility Agreement, dated as of December 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012). | |
4.30 | Third Amendment to Letter of Credit Facility Agreement, dated as of May 24, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on August 10, 2012). | |
4.31 | Limited Waiver and Third Amendment to Credit Agreement, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.1 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012). | |
4.32 | Fourth Amendment to Letter of Credit Facility Agreement and Waiver, dated as of November 8, 2012, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party hereto, the Lenders party hereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 4.2 to the Form 10-Q filed with the Securities and Exchange Commission on November 13, 2012). | |
4.33 | Fourth Amendment to Credit Agreement and Other Loan Documents, effective as of December 21, 2012, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.34 | Sixth Amendment to Credit Agreement, effective as of January 31, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.35 | Limited Waiver and Seventh Amendment to Credit Agreement, effective as of February 22, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders signatory thereto, and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.36 | Fifth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of December 21, 2012, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.4 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). |
Table of Contents
Index to Financial Statements
Exhibit | Description | |
4.37 | Sixth Amendment to Letter of Credit Facility Agreement and Amendment to Other Loan Documents, effective as of February 22, 2013, by and among the Company, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.5 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
4.38 | Eighth Amendment to Credit Agreement, effective as of March 26, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013). | |
*4.39 | Limited Waiver and Ninth Amendment to Credit Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders and the Lenders signatory thereto. | |
*4.40 | Limited Waiver and Seventh Amendment to Letter of Credit Facility Agreement, effective as of April 10, 2013, by and among the Company, the Guarantors party thereto, Capital One, N.A., as Administrative Agent for the Lenders, and the Lenders signatory thereto. | |
10.1 | Purchase and Sale Agreement, dated September 14, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.2 | First Amendment to Purchase and Sale Agreement, dated as of October 29, 2009, by and between W&T Offshore, Inc. and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.3 | Second Amendment to Purchase and Sale Agreement, dated as of November 23, 2010, by and between W&T Offshore, Inc. and Black Elk Offshore Operations, LLC (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.4 | Purchase and Sale Agreement between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC, dated as of August 5, 2010 (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.5 | Amendment to Purchase and Sale Agreement, entered into as of September 30, 2010, by and between Nippon Oil Exploration USA Limited and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333-174226)). | |
10.6 | Purchase and Sale Agreement, executed on March 17, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on May 16, 2011 (SEC File No. 333174226)). | |
10.7 | Amendment to Purchase and Sale Agreement, executed on March 30, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
10.8 | Second Amendment to Purchase and Sale Agreement, executed on May 18, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). | |
10.9 | Third Amendment to Purchase and Sale Agreement, executed on May 31, 2011, by and between Merit Management Partners I, L.P., Merit Management Partners II, L.P., Merit Management Partners III, L.P., Merit Energy Partners III, L.P., MEP III GOM, LLC, Merit Energy Partners D-III, L.P., Merit Energy Partners E-III, L.P., and Merit Energy Partners F-III, L.P., and Black Elk Energy Offshore Operations, LLC (incorporated by reference to Exhibit 10.7 to the Form 8-K filed with the Securities and Exchange Commission on June 3, 2011). |
Table of Contents
Index to Financial Statements
Exhibit | Description | |
†10.10 | Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and John G. Hoffman (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013). | |
†10.11 | Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and Arthur Garza III (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on October 4, 2013). | |
†10.12 | Employment Agreement, dated as of July 13, 2012, by and between Black Elk Energy Offshore Operations, LLC and James F. Hagemeier (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on October 3, 2012). | |
†*10.13 | Engagement Letter, dated January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and Alvarez & Marsal North America, LLC. | |
10.14 | Waiver and Second Amendment to Credit Agreement, dated as of June 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.6 to the Form 10-Q for the period ended June 30, 2011 as filed with the Securities and Exchange Commission on August 10, 2011 (SEC File No. 333-174226)). | |
10.15 | Waiver, dated as of September 30, 2011, by and among Black Elk Energy Offshore Operations, LLC, the Guarantors party thereto, the Lenders party thereto and Capital One, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to the Form 10-Q for the period ended September 30, 2011 as filed with the Securities and Exchange Commission on November 10, 2011 (SEC File No. 333-174226)). | |
†10.16 | Amended and Restated Company Agreement of Black Elk Employee Incentive, LLC, dated as of August 20, 2010 (incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 26, 2012. | |
10.17 | Third Amendment to Purchase and Sale Agreement, dated December 19, 2012, by and between W&T Offshore, Inc. and the Company (incorporated by reference to Exhibit 10.6 to the Form 8-K filed with the Securities and Exchange Commission on March 11, 2013). | |
*10.18 | Contribution Agreement, dated as of January 25, 2013, by and between Black Elk Energy Offshore Operations, LLC and PPVA Black Elk Energy (Equity) LLC. | |
*10.19 | Letter Agreement, dated February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Value Arbitrage Fund LP. | |
*10.20 | Contribution Agreement, dated as of February 12, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
*10.21 | Contribution Agreement, dated as of February 13, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
*10.22 | Contribution Agreement, dated as of February 14, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
*10.23 | Contribution Agreement, dated as of February 22, 2013, by and between Black Elk Energy Offshore Operations, LLC and Platinum Partners Black Elk Opportunities Fund LLC. | |
10.24 | Purchase and Sale Agreement by and between Black Elk Energy Offshore Operations, LLC as Seller and Renaissance Offshore, LLC as Purchaser, dated as of March 1, 2013 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013). | |
10.25 | First Amendment to Purchase and Sale Agreement by and between Black Elk Offshore Operations, LLC and Renaissance Offshore, LLC, effective as of March 22, 2013 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed with the Securities and Exchange Commission on April 2, 2013). | |
*10.26 | Offer and Separation Agreement and General Release Offer, dated as of April 1, 2013, by and between Black Elk Energy Offshore Operations, LLC and Douglas W. Fehr. | |
*12.1 | Computation of Ratio of Earnings to Fixed Charges. | |
*21.1 | Subsidiary List of Black Elk Energy Offshore Operations, LLC. |
Table of Contents
Index to Financial Statements
Exhibit | Description | |
*23.1 | Consent of Netherland, Sewell & Associates, Inc. | |
*31.1 | Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer. | |
*31.2 | Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer. | |
*32.1 | Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer. | |
*99.1 | Summary Report of Netherland, Sewell & Associates, Inc. | |
101.INS§ | XBRL Instance Document | |
101.SCH§ | XBRL Taxonomy Extension Schema Document | |
101.CAL§ | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF§ | XBRL Taxonomy Extension Definition Presentation Linkbase Document | |
101.LAB§ | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE§ | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. |
† | Management contract or compensatory plan or arrangement. |
§ | Furnished with this Form 10-K. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing. |