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8-K - FORM 8-K - Black Elk Energy Offshore Operations, LLC | d441523d8k.htm |
Exhibit 99.1
Black Elk Energy Offshore Operations, LLC Reports Third Quarter 2012
Financial and Operational Results
Houston, January 16, 2013
Black Elk Energy Offshore Operations, LLC today announces financial and operational results for the third quarter of 2012. Some of the highlights include:
| For the third quarter 2012, production volumes averaged 14,034 barrels of oil equivalent per day (Boe), or 84,204 Mcfe gas equivalent per day, compared to 16,164 barrels of oil equivalent per day, or 96,984 Mcfe gas equivalent per day, for the same quarter in 2011. The decrease in production is attributable to the relinquishment of uneconomic leases and several fields being shut-in. Production volumes were 44% oil and natural gas liquids (NGLs) and 56% natural gas. |
| Our average realized sales price for oil was $102.92 per barrel before the effects of hedging and $103.06 per barrel after hedging. Average realized sales price for natural gas was $3.06 per million cubic feet (Mcf) before the effects of hedging and $3.80 per Mcf after hedging. |
| Total revenues for the third quarter 2012 decreased from the same period in 2011 by $84.2 million, or 60%, due to lower realized and unrealized gains on derivative financial instruments, decreased oil and gas production and lower gas and plant product prices. |
| For the third quarter 2012, we realized a net loss of $32.6 million compared to $51.1 million net income in the same quarter of 2011. |
| Adjusted EBITDA for the third quarter 2012 was $15.3 million compared to $32.3 million from the third quarter of 2011. |
Financial Results
Oil and natural gas production. Total oil, natural gas and plant product production of 1,291 MBoe decreased 196 MBoe, or 13%, during the three months ended September 30, 2012 compared to the same period in 2011 as a result of the relinquishment of uneconomic leases and several fields being shut-in. For the nine months ended September 30, 2012, total oil, natural gas and plant production of 4,119 MBoe increased 381 MBoe, or 10%, compared to the nine months ended 2011 due to the properties acquired in the Merit Acquisition in May 2011 (971 MBoe for the nine months ended September 30, 2012) which was partially offset by lower production in uneconomic leases that were relinquished and several fields being shut-in during the second and third quarters of 2012.
Total revenues. Total revenues for the three and nine months ended September 30, 2012 of $57.1 million and $239.9 million, respectively, decreased $84.2 million, or 60%, and $24.8 million, or 9%, respectively, over the comparable periods in 2011.
Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $14.4 million, or 17%, for the three months ended September 30, 2012 compared to the same period in 2011 as a result of lower oil and gas production due to uneconomic leases that were relinquished and several fields being shut-in and lower natural gas and plant product prices. For the nine months ended September 30, 2012, revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $3.3 million, or 2%, compared to the same period in 2011 as a result of increased production due to properties acquired in the Merit Acquisition in May 2011 and higher oil prices partially offset by lower gas and plant product prices.
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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 $3.3 million and $11.2 million for the three and nine months ended September 30, 2012, respectively, and realized gains of $6.7 million and $3.7 million for the three and nine months ended September 30, 2011, respectively. We recognized unrealized gains (losses) of $(16.1) million and $7.4 million for the three and nine months ended September 30, 2012, respectively, and unrealized gains of $50.2 million and $43.0 million in the same periods of 2011.
Excluding hedges, we realized average oil prices of $102.92 per barrel and $107.93 per barrel and gas prices of $3.06 per Mcf and $2.63 per Mcf for the three and nine months ended September 30, 2012, respectively. For the same periods in 2011, excluding hedges, we realized average oil prices of $102.56 per barrel and $105.44 per barrel and $4.28 per Mcf and $4.43 per Mcf, respectively. Average prices realized from the sale of oil on a third quarter and year-to-date basis reflected the economic turnaround that began during 2011. Gas prices were lower on a quarter and year-to-date basis compared to 2011 but are higher than the second quarter of 2012.
Operating Expenses
Lease operating costs. Our lease operating costs for the three and nine months ended September 30, 2012 decreased to $43.8 million, or $33.95 per Boe, and increased to $131.1 million, or $31.82 per Boe, respectively. For the three and nine months ended September 30, 2011, our lease operating costs were $47.1 million, or $31.69 per Boe, and $100.0 million, or $26.75 per Boe, respectively. Lease operating expenses decreased for the three months ended September 30, 2012 compared to the same period in 2011 due to cost reduction initiatives and the unmanning of platforms as well as lower offshore insurance costs. The increase in lease operating costs for the nine months ended September 30, 2012 compared to the same period in 2011 was directly related to the additional properties acquired from the Maritech and Merit Acquisitions. The increase in cost per Boe during 2012 was primarily attributable to a mix of increased properties and certain non-recurring safety and regulatory costs on the newly acquired properties and lower production due to pipeline repairs and leaks in 2012.
Workover costs. Our workover costs for the three and nine months ended September 30, 2012 were $4.4 million and $10.5 million, respectively, a decrease of $1.7 million compared to the third quarter of 2011 and a decrease of $1.1 million compared to the first nine months in 2011. For the nine months ended September 30, 2012, Eugene Island 240, West Cameron 20/45, Eugene Island 156/South Marsh 22, West Delta 31/32, and Eugene Island 331 were the primary workover expense projects.
Exploration. Our exploration expenses for the three and nine months ended September 30, 2012 were $0.3 million and $1.2 million, respectively. There were no exploration costs for the same periods in 2011. Exploration costs for 2012 include expenses to drill a non-operated well, South Pelto 13, which was unsuccessful.
Depreciation, depletion, amortization and impairment. DD&A expense was $12.3 million, or $9.53 per Boe, and $36.5 million, or $8.87 per Boe, for the three and nine months ended September 30, 2012, respectively, and $14.4 million, or $9.69 per Boe, and $32.0 million, or $8.57 per Boe, for the three and nine months ended 2011, respectively. The decrease in DD&A for the three months ended September 30, 2012 was a result of lower production due to uneconomic leases and several fields being shut-in. DD&A increased for the nine months ended September 30, 2012 due to production associated with the properties acquired in 2011, 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 a $3.6 million and $7.0 million impairment for the three and nine months ended September 30, 2012, respectively, and a $1.1 million and $5.4 million impairment for the same periods in 2011, respectively.
General and administrative expenses. G&A expense was $8.3 million, or $6.43 per Boe, and $20.7 million, or $5.02 per Boe, for the three and nine months ended September 30, 2012, respectively, and $5.0 million, or $3.36 per Boe, and $16.9 million, or $4.51 per Boe, for the same periods in 2011, respectively. The increase in G&A expense for the three and nine months ended September 30, 2012 was due to an increase in staff and related administrative costs attributable to our growth, in addition to higher legal fees and insurance costs.
Accretion expense. We recognized accretion expense of $9.3 million and $27.2 million for the three and nine months ended September 30, 2012, respectively, compared to $9.1 and $18.5 million for the three and nine months ended September 30, 2011, respectively. The increase in accretion expense in 2012 was attributable to assumed asset retirement obligations related to our acquisitions in 2011.
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Miscellaneous expense. Miscellaneous expense of $0.9 million and $2.4 million increased $0.4 million and decreased $3.7 million for the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011. The higher year-to-date expense in 2011 was a result of a consent solicitation fee paid under the First Supplemental Indenture.
About Black Elk Energy Offshore
We are an oil and gas company engaged in the acquisition, exploitation, development and production of oil and natural gas properties. We seek to acquire and exploit properties with proved developed reserves, proved developed non-producing reserves and proved undeveloped reserves. Our strategy is to acquire and economically maximize properties that are currently producing or have the potential to produce given additional attention and capital resources. We are engaged in continual efforts to monitor and reduce operating expenses by finding opportunities to safely increase efficiencies related to staffing, transportation and operational procedures. Moreover, our ability to accurately estimate and manage plugging and abandonment costs associated with potential acquisitions increases the likelihood of achieving our target returns on investment. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties in both our current and planned areas of operation.
We seek to acquire assets in our areas of focus from oil and gas companies that have determined that such assets are noncore and desire to remove them from their producing property portfolio or have made strategic decisions to deemphasize their offshore operations. Prior to an acquisition, we perform stringent structural engineering tests to determine whether the reservoirs possess potential upside. Each opportunity is presented, catalogued and graded by our management and risked appropriately for the overall impact to our company.
Conference Call Information. Black Elk will hold a conference call to discuss financial and operational results on Thursday, January 17, 2013 at 10:00 a.m. Central Time. To participate, dial (800) 404-8174 in the United States or (303) 223-2685 from outside the country at least ten minutes before the call begins.
Safe Harbor Statement
This press release may contain certain forward-looking statements relating to the business of Black Elk Energy Offshore Operations, LLC and its subsidiary companies. All statements, other than statements of historical fact included herein are forward-looking statements. These forward-looking statements are often identified by the use of forward-looking terminology such as believes, expects or similar expressions, and involve known and unknown risks and uncertainties. Although Black Elk believes that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. Investors should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Black Elks actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in Black Elks periodic reports that are filed with the Securities and Exchange Commission and available on its website at www.sec.gov. All forward-looking statements attributable to Black Elk or persons acting on its behalf are expressly qualified in their entirety by these factors. Other than as required under the securities laws, Black Elk does not assume a duty to update these forward-looking statements.
Contact
Michelle Simmons
IR@blackelk.com
11451 Katy Freeway, Suite 500
Houston, Texas 77079
(281) 598-8647
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
September 30, | December 31, | |||||||
2012 | 2011 | |||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS: |
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Cash and cash equivalents |
$ | 17,647 | $ | 17,260 | ||||
Accounts receivable, net |
41,785 | 52,299 | ||||||
Due from affiliates |
164 | 163 | ||||||
Prepaid expenses and other |
33,557 | 26,637 | ||||||
Derivative assets |
7,257 | 4,216 | ||||||
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TOTAL CURRENT ASSETS |
100,410 | 100,575 | ||||||
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OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $156,980 and $114,056 at September 30, 2012 and December 31, 2011, respectively |
217,385 | 238,702 | ||||||
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $1,485 and $870 at September 30, 2012 and December 31, 2011, respectively |
1,882 | 2,245 | ||||||
OTHER ASSETS |
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Debt issue costs, net |
8,293 | 8,726 | ||||||
Derivative assets |
2,218 | | ||||||
Asset retirement obligation escrow receivable |
20,348 | 20,348 | ||||||
Escrow for abandonment costs |
211,031 | 172,153 | ||||||
Other assets |
3,157 | 3,257 | ||||||
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TOTAL OTHER ASSETS |
245,047 | 204,484 | ||||||
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TOTAL ASSETS |
$ | 564,724 | $ | 546,006 | ||||
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LIABILITIES AND MEMBERS EQUITY (DEFICIT) | ||||||||
CURRENT LIABILITIES: |
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Accounts payable and accrued expenses |
$ | 75,046 | $ | 72,309 | ||||
Asset retirement obligations |
19,609 | 15,238 | ||||||
Current portion of debt and notes payable |
8,858 | 4,154 | ||||||
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TOTAL CURRENT LIABILITIES |
103,513 | 91,701 | ||||||
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LONG-TERM LIABILITIES |
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Gas imbalance payable |
1,885 | 1,362 | ||||||
Dividends payable |
10,176 | 4,200 | ||||||
Derivative liabilities |
| 2,116 | ||||||
Asset retirement obligations, net of current portion |
282,682 | 273,448 | ||||||
Debt, net of current portion, net of unamortized discount of $942 and $1,113 at September 30, 2012 and December 31, 2011, respectively |
205,558 | 172,887 | ||||||
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TOTAL LONG-TERM LIABILITIES |
500,301 | 454,013 | ||||||
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TOTAL LIABILITIES |
603,814 | 545,714 | ||||||
COMMITMENTS AND CONTINGENCIES |
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MEMBERS EQUITY (DEFICIT) |
(39,090 | ) | 292 | |||||
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TOTAL LIABILITIES AND MEMBERS EQUITY (DEFICIT) |
$ | 564,724 | $ | 546,006 | ||||
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
REVENUES: |
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Oil sales |
$ | 50,721 | $ | 56,470 | $ | 165,441 | $ | 147,038 | ||||||||
Natural gas sales |
13,289 | 22,398 | 36,754 | 57,388 | ||||||||||||
Plant product sales and other revenue |
5,960 | 5,500 | 19,141 | 13,614 | ||||||||||||
Realized gain on derivative financial instruments |
3,284 | 6,746 | 11,189 | 3,664 | ||||||||||||
Unrealized (loss) gain on derivative financial instruments |
(16,129 | ) | 50,234 | 7,375 | 43,006 | |||||||||||
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TOTAL REVENUES |
57,125 | 141,348 | 239,900 | 264,710 | ||||||||||||
OPERATING EXPENSES: |
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Lease operating |
43,840 | 47,125 | 131,055 | 100,000 | ||||||||||||
Production taxes |
192 | 231 | 744 | 439 | ||||||||||||
Workover |
4,395 | 6,053 | 10,485 | 11,599 | ||||||||||||
Exploration |
311 | | 1,249 | | ||||||||||||
Depreciation, depletion and amortization |
12,302 | 14,411 | 36,546 | 32,018 | ||||||||||||
Impairment |
3,681 | 1,096 | 6,992 | 5,419 | ||||||||||||
General and administrative |
8,301 | 4,991 | 20,668 | 16,862 | ||||||||||||
Accretion |
9,256 | 9,089 | 27,228 | 18,471 | ||||||||||||
Loss (gain) on sale of asset |
| | 120 | (142 | ) | |||||||||||
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TOTAL OPERATING EXPENSES |
82,278 | 82,996 | 235,087 | 184,666 | ||||||||||||
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(LOSS) INCOME FROM OPERATIONS |
(25,153 | ) | 58,352 | 4,813 | 80,044 | |||||||||||
OTHER INCOME (EXPENSE): |
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Interest income |
11 | 131 | 305 | 358 | ||||||||||||
Miscellaneous expense |
(919 | ) | (496 | ) | (2,408 | ) | (6,086 | ) | ||||||||
Interest expense |
(6,514 | ) | (6,873 | ) | (19,422 | ) | (19,275 | ) | ||||||||
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TOTAL OTHER EXPENSE |
(7,422 | ) | (7,238 | ) | (21,525 | ) | (25,003 | ) | ||||||||
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NET (LOSS) INCOME |
(32,575 | ) | 51,114 | (16,712 | ) | 55,041 | ||||||||||
PREFERRED UNIT DIVIDENDS |
2,232 | 1,800 | 5,976 | 2,400 | ||||||||||||
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NET (LOSS) INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS |
$ | (34,807 | ) | $ | 49,314 | $ | (22,688 | ) | $ | 52,641 | ||||||
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How We Evaluate Our Operations:
We use a variety of financial and operational measures to assess our overall performance. Among those measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) Adjusted EBITDA (as defined in the following table).
The following table contains certain financial and operational data for each of the three and nine months ended September 30, 2012 and December 31, 2011:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Average daily sales: |
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Oil (Boepd) |
5,357 | 5,985 | 5,595 | 5,108 | ||||||||||||
Natural gas (Mcfpd) |
47,177 | 56,917 | 51,075 | 47,451 | ||||||||||||
Plant products (Galpd) |
34,206 | 29,090 | 38,900 | 28,393 | ||||||||||||
Oil equivalents (Boepd) |
14,034 | 16,164 | 15,033 | 13,693 | ||||||||||||
Average realized prices(1) : |
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Oil ($/Bbl) |
$ | 103.06 | $ | 107.64 | $ | 105.99 | $ | 102.51 | ||||||||
Natural gas ($/Mcf) |
3.80 | 5.03 | 3.64 | 5.03 | ||||||||||||
Plant products ($/Gallon) |
0.91 | 1.40 | 1.04 | 1.25 | ||||||||||||
Oil equivalents ($/Boe) |
54.35 | 60.09 | 54.49 | 58.26 | ||||||||||||
Costs and Expenses: |
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Lease operating expense ($/Boe) |
33.95 | 31.69 | 31.82 | 26.75 | ||||||||||||
Production tax expense ($/Boe) |
0.15 | 0.16 | 0.18 | 0.12 | ||||||||||||
General and administrative expense ($/Boe) |
6.43 | 3.36 | 5.02 | 4.51 | ||||||||||||
Net (loss) income (in thousands) |
(32,575 | ) | 51,114 | (16,712 | ) | 55,041 | ||||||||||
Adjusted EBITDA(2) (in thousands) |
15,307 | 32,349 | 66,221 | 87,076 |
(1) | Average realized prices presented give effect to our hedging. |
(2) | Adjusted EBITDA is defined as net (loss) income before interest expense, unrealized loss/gain on derivative instruments, accretion, depreciation, depletion, amortization and impairment and loss/gain on the sale of an asset. Adjusted EBITDA is not a measure of net (loss) income or cash flows as determined by GAAP, and should not be considered as an alternative to net (loss) income, operating income or any other performance measures derived in accordance with GAAP or as an alternative to cash flows from operating activities as a measure of our liquidity. We present Adjusted EBITDA because it is frequently used by securities analysts, investors and other interested parties in the evaluation of high-yield issuers, many of whom present Adjusted EBITDA when reporting their results. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results or cash flows as reported under GAAP. Because of these limitations, Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. Our presentation of Adjusted EBITDA should not be construed as an inference that our future results will be unaffected by unusual or nonrecurring items. A reconciliation table is provided below to illustrate how we derive Adjusted EBITDA. |
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Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | ||||||||||||||||
Net (loss) income |
$ | (32,575 | ) | $ | 51,114 | $ | (16,712 | ) | $ | 55,041 | ||||||
Adjusted EBITDA |
$ | 15,307 | $ | 32,349 | $ | 66,221 | $ | 87,076 | ||||||||
Reconciliation of Net loss (income) to Adjusted EBITDA |
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Net (loss) income |
$ | (32,575 | ) | $ | 51,114 | $ | (16,712 | ) | $ | 55,041 | ||||||
Interest expense |
6,514 | 6,873 | 19,422 | 19,275 | ||||||||||||
Unrealized loss (gain) on derivative instruments |
16,129 | (50,234 | ) | (7,375 | ) | (43,006 | ) | |||||||||
Accretion |
9,256 | 9,089 | 27,228 | 18,471 | ||||||||||||
Depreciation, depletion, amortization and impairment |
15,983 | 15,507 | 43,538 | 37,437 | ||||||||||||
Loss (gain) on sale of asset |
| | 120 | (142 | ) | |||||||||||
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Adjusted EBITDA |
$ | 15,307 | $ | 32,349 | $ | 66,221 | $ | 87,076 | ||||||||
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