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8-K - FORM 8-K - Black Elk Energy Offshore Operations, LLC | d394918d8k.htm |
Exhibit 99.1
Black Elk Energy Offshore Operations, LLC Reports Second Quarter 2012
Financial and Operational Results
Houston, August 10, 2012
Black Elk Energy Offshore Operations, LLC today announces financial and operational results for the second quarter of 2012. Some of the highlights include:
| For the second quarter 2012, production volumes averaged 14,044 barrels of oil equivalent per day, or 84,264 Mcfe gas equivalent per day, compared to 13,919 barrels of oil equivalent per day, or 83,514 Mcfe gas equivalent per day for the same quarter in 2011. The increase in production is attributable to three months of production from the properties acquired in the Merit Acquisition partially offset by production disruptions due to pipeline leaks and/or repairs. Production volumes were 47% oil and natural gas liquids (NGLs) and 53% natural gas. |
| Our average realized sales price for oil was $106.03 per barrel before the effects of hedging and $106.84 per barrel after hedging. Average realized sales price for natural gas was $2.26 per million cubic feet (Mcf) before the effects of hedging and $3.75 per Mcf after hedging. |
| Total revenues for the second quarter 2012 increased from the same period in 2011 by $7.7 million, or 8%, due to higher realized and unrealized gains on derivative financial instruments and increased oil and NGL production partially offset by decreased natural gas production and lower commodity prices. |
| For the second quarter 2012, we realized net income of $21.5 million compared to $28.0 million net income in the same quarter of 2011. |
| Adjusted EBITDA for the second quarter 2012 was $21.9 million compared to $30.1 million from the second quarter of 2011. |
Financial Results
Oil and natural gas production. Total oil, natural gas and plant product production of 1,278 MBoe and 2,828 MBoe increased 11 MBoe, or 1%, and 577 MBoe, or 26%, during the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. For the three and six months ended June 30, 2012, production increased as a result of the properties acquired in the Merit Acquisition in May 2011 (332 MBoe and 890 MBoe for the three and six months ended June 30, 2012, respectively) offset by lower production in several fields due to pipelines being shut-in and/or repaired in the second quarter of 2012.
Total revenues. Total revenues for the three and six months ended June 30, 2012 of $106.6 million and $182.8 million increased $7.7 million, or 8%, and $59.4 million, or 48%, respectively, over the comparable periods in 2011. The increase in revenues during 2012 was a result of increased production related to the properties acquired in the Merit Acquisition ($16.7 million and $45.4 million for the three and six months ended June 30, 2012, respectively) and higher hedged oil prices partially offset by lower production in the second quarter of 2012 due to shut-ins and/or repairs and lower natural gas and plant product prices.
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 $6.4 million and $7.9 million for the three and six months ended June 30, 2012, respectively, and realized losses of $2.7 million and $3.1 million for the three and six months ending June 30, 2011, respectively. We recognized unrealized gains of $30.2 million and $23.5 million for the three and six
months ended June 30, 2012, respectively, and unrealized gains (losses) of $23.8 million and ($7.2) million in the same periods of 2011. Revenues, excluding the realized and unrealized revenues from commodity hedge contracts, decreased $7.9 million, or 10%, for the three months ended June 30, 2012 compared to the same period in 2011 as a result of lower natural gas production and decreased oil, natural gas and plant product prices partially offset by the Merit Acquisition. For the six months ended June 30, 2012, revenues, excluding the realized and unrealized revenues from commodity hedge contracts, increased $17.7 million, or 13%, compared to the same period in 2011 as a result of the Merit Acquisition partially offset by lower production in several fields due to pipelines being shut-in and/or repaired and lower gas and plant product prices.
Excluding hedges, we realized average oil prices of $106.03 per barrel and $110.30 per barrel and gas prices of $2.26 per Mcf and $2.43 per Mcf for the three and six months ended June 30, 2012, respectively. For the same periods in 2011, excluding hedges, we realized average oil prices of $113.61 per barrel and $107.32 per barrel and $4.55 per Mcf and $4.53 per Mcf, respectively. Although average prices realized from the sale of oil on a year-to-date basis reflected the economic turnaround that began during 2011, oil and natural gas prices were lower in the second quarter of 2012 and economic conditions continue to remain uncertain. Oil and natural gas prices will remain unstable and we expect them to be volatile in the future.
Operating Expenses
Lease operating costs. Our lease operating costs for the three and six months ended June 30, 2012 increased to $44.0 million, or $34.41 per Boe, and $87.2 million, or $30.84 per Boe, respectively. For the three and six months ended June 30, 2011, our lease operating costs were $29.8 million, or $23.54 per Boe, and $52.9 million, or $23.49 per Boe, respectively. The increase in lease operating costs during 2012 is directly related to the increase in properties from the Maritech and the Merit Acquisitions. The increase in cost per Boe during 2012 is 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 six months ended June 30, 2012 were $3.5 million and $6.1 million, respectively, an increase of $1.1 million compared to the second quarter of 2011 and an increase of $0.5 million compared to the first six months in 2011. For the six months ended June 30, 2012, Eugene Island 240, High Island A443, West Cameron 20, West Delta 31/32, Ship Shoal 198 and Eugene Island 331 were the primary workover expense projects.
Depreciation, depletion, amortization and impairment. DD&A expense was $11.9 million, or $9.29 per Boe, and $24.2 million, or $8.57 per Boe, for the three and six months ended June 30, 2012, respectively, and $9.6 million, or $7.59 per Boe, and $17.6 million, or $7.82 per Boe, for the three and six months ended 2011, respectively. In 2012, the increase in DD&A was a result of increased production associated with the properties acquired in 2011. Depletion is recorded based on units of production and DD&A expense includes depletion of future asset retirement obligations. We recorded a $3.3 million impairment for the three and six months ended June 30, 2012 and a $4.3 million impairment for the same periods in 2011.
General and administrative expenses. G&A expense was $5.9 million, or $4.64 per Boe, and $12.4 million, or $4.37 per Boe, for the three and six months ended June 30, 2012, respectively and $7.3 million, or $5.80 per Boe, and $11.9 million, or $5.27 per Boe, for the same periods in 2011. The decrease in G&A expense for the three months ended June 30, 2012 was due to bonuses paid in 2011 and not in 2012. For the three months ended June 30, 2011, we also incurred higher consultant fees for the Merit Acquisition and for the registration filing partially offset by an increase in staff and related administrative costs attributable to our growth. The increase in G&A expense for the six months ended June 30, 2012 was due to an increase in staff and related administrative costs attributable to our growth in February and May of 2011.
Accretion expense. We recognized accretion expense of $8.9 million and $18.0 million for the three and six months ended June 30, 2012, respectively, compared to $5.4 million and $9.4 million for the three and six months ended June 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 $0.8 million and $1.5 million decreased $4.6 million and $4.1 million for the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. The higher expense in 2011 was a result of the 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.
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
James Hagemeier
IR@blackelk.com
11451 Katy Freeway, Suite 500
Houston, Texas 77079
(281) 598-8600
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
June 30, 2012 |
December 31, 2011 |
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(Unaudited) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS: |
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Cash and cash equivalents |
$ | 16,946 | $ | 17,260 | ||||
Accounts receivable, net |
40,418 | 52,439 | ||||||
Due from affiliates |
23 | 23 | ||||||
Prepaid expenses and other |
39,830 | 26,637 | ||||||
Derivative assets |
17,121 | 4,216 | ||||||
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TOTAL CURRENT ASSETS |
114,338 | 100,575 | ||||||
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OIL AND GAS PROPERTIES, successful efforts method of accounting, net of accumulated depreciation, depletion, amortization and impairment of $141,210 and $114,056 at June 30, 2012 and December 31, 2011, respectively |
225,968 | 238,702 | ||||||
OTHER PROPERTY AND EQUIPMENT, net of accumulated depreciation of $1,271 and $870 at June 30, 2012 and December 31, 2011, respectively |
1,975 | 2,245 | ||||||
OTHER ASSETS |
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Debt issue costs, net |
8,570 | 8,726 | ||||||
Derivative assets |
8,482 | | ||||||
Asset retirement obligation escrow receivable |
20,348 | 20,348 | ||||||
Escrow for abandonment costs |
202,869 | 172,153 | ||||||
Other assets |
2,111 | 3,257 | ||||||
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TOTAL OTHER ASSETS |
242,380 | 204,484 | ||||||
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TOTAL ASSETS |
$ | 584,661 | $ | 546,006 | ||||
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LIABILITIES AND MEMBERS EQUITY (DEFICIT) | ||||||||
CURRENT LIABILITIES: |
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Accounts payable and accrued expenses |
$ | 65,266 | $ | 72,309 | ||||
Asset retirement obligations |
16,233 | 15,238 | ||||||
Current portion of debt and notes payable |
14,139 | 4,154 | ||||||
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TOTAL CURRENT LIABILITIES |
95,638 | 91,701 | ||||||
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LONG-TERM LIABILITIES |
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Gas imbalance payable |
935 | 1,362 | ||||||
Dividends payable |
7,944 | 4,200 | ||||||
Derivative liabilities |
| 2,116 | ||||||
Asset retirement obligations, net of current portion |
283,855 | 273,448 | ||||||
Debt, net of current portion, net of unamortized discount of $1,002 and $1,113 at June 30, 2012 and December 31, 2011, respectively |
196,998 | 172,887 | ||||||
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TOTAL LONG-TERM LIABILITIES |
489,732 | 454,013 | ||||||
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TOTAL LIABILITIES |
585,370 | 545,714 | ||||||
COMMITMENTS AND CONTINGENCIES |
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MEMBERS EQUITY (DEFICIT) |
(709 | ) | 292 | |||||
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TOTAL LIABILITIES AND MEMBERS EQUITY (DEFICIT) |
$ | 584,661 | $ | 546,006 | ||||
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BLACK ELK ENERGY OFFSHORE OPERATIONS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands)
Three Months Ended June 30, |
Six Months Ended June 30, |
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2012 | 2011 | 2012 | 2011 | |||||||||||||
REVENUES: |
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Oil sales |
$ | 54,202 | $ | 53,156 | $ | 114,720 | $ | 90,568 | ||||||||
Natural gas sales |
9,149 | 19,883 | 23,465 | 34,990 | ||||||||||||
Plant product sales and other revenue |
6,577 | 4,806 | 13,181 | 8,114 | ||||||||||||
Realized gain (loss) on derivative financial instruments |
6,436 | (2,746 | ) | 7,905 | (3,082 | ) | ||||||||||
Unrealized gain (loss) on derivative financial instruments |
30,230 | 23,750 | 23,504 | (7,228 | ) | |||||||||||
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TOTAL REVENUES |
106,594 | 98,849 | 182,775 | 123,362 | ||||||||||||
OPERATING EXPENSES: |
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Lease operating |
43,973 | 29,815 | 87,215 | 52,875 | ||||||||||||
Production taxes |
209 | 179 | 552 | 208 | ||||||||||||
Workover |
3,521 | 2,383 | 6,090 | 5,546 | ||||||||||||
Exploration |
41 | | 938 | | ||||||||||||
Depreciation, depletion and amortization |
11,873 | 9,613 | 24,244 | 17,607 | ||||||||||||
Impairment |
3,311 | 4,323 | 3,311 | 4,323 | ||||||||||||
General and administrative |
5,933 | 7,346 | 12,367 | 11,871 | ||||||||||||
Accretion |
8,892 | 5,444 | 17,972 | 9,382 | ||||||||||||
Loss (gain) on sale of asset |
120 | (142 | ) | 120 | (142 | ) | ||||||||||
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TOTAL OPERATING EXPENSES |
77,873 | 58,961 | 152,809 | 101,670 | ||||||||||||
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INCOME FROM OPERATIONS |
28,721 | 39,888 | 29,966 | 21,692 | ||||||||||||
OTHER INCOME (EXPENSE): |
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Interest income |
13 | 220 | 294 | 227 | ||||||||||||
Miscellaneous expense |
(844 | ) | (5,453 | ) | (1,489 | ) | (5,590 | ) | ||||||||
Interest expense |
(6,373 | ) | (6,609 | ) | (12,908 | ) | (12,402 | ) | ||||||||
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TOTAL OTHER EXPENSE |
(7,204 | ) | (11,842 | ) | (14,103 | ) | (17,765 | ) | ||||||||
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NET INCOME |
21,517 | 28,046 | 15,863 | 3,927 | ||||||||||||
PREFERRED UNIT DIVIDENDS |
1,944 | 600 | 3,744 | 600 | ||||||||||||
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NET INCOME ATTRIBUTABLE TO COMMON UNIT HOLDERS |
$ | 19,573 | $ | 27,446 | $ | 12,119 | $ | 3,327 | ||||||||
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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 months ended June 30, 2012 and December 31, 2011:
Three Months Ended June 30, |
Six Months Ended June 30, |
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2012 | 2011 | 2012 | 2011 | |||||||||||||
Average daily sales: |
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Oil (Boepd) |
5,617 | 5,141 | 5,715 | 4,663 | ||||||||||||
Natural gas (Mcfpd) |
44,410 | 48,055 | 53,046 | 42,640 | ||||||||||||
Plant products (Galpd) |
43,055 | 32,271 | 41,273 | 28,039 | ||||||||||||
Oil equivalents (Boepd) |
14,044 | 13,919 | 15,538 | 12,437 | ||||||||||||
Average realized prices(1): |
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Oil ($/Bbl) |
$ | 106.84 | $ | 104.00 | $ | 107.38 | $ | 99.16 | ||||||||
Natural gas ($/Mcf) |
3.75 | 4.95 | 3.56 | 5.03 | ||||||||||||
Plant products ($/Gallon) |
1.00 | 1.29 | 1.09 | 1.17 | ||||||||||||
Oil equivalents ($/Boe) |
57.67 | 58.49 | 54.56 | 57.05 | ||||||||||||
Costs and Expenses: |
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Lease operating expense ($/Boe) |
34.41 | 23.54 | 30.84 | 23.49 | ||||||||||||
Production tax expense ($/Boe) |
0.16 | 0.14 | 0.20 | 0.09 | ||||||||||||
General and administrative expense ($/Boe) |
4.64 | 5.80 | 4.37 | 5.27 | ||||||||||||
Net income (in thousands) |
21,517 | 28,046 | 15,863 | 3,927 | ||||||||||||
Adjusted EBITDA(2) (in thousands) |
21,856 | 30,143 | 50,914 | 54,727 |
(1) | Average realized prices presented give effect to our hedging. |
(2) | Adjusted EBITDA is defined as net income before interest expense, unrealized gain/loss 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 income or cash flows as determined by GAAP, and should not be considered as an alternative to net 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. |
Three Months Ended June 30, |
Six Months Ended June 30, |
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2012 | 2011 | 2012 | 2011 | |||||||||||||
(in thousands) | ||||||||||||||||
Net income |
$ | 21,517 | $ | 28,046 | $ | 15,863 | $ | 3,927 | ||||||||
Adjusted EBITDA |
$ | 21,856 | $ | 30,143 | $ | 50,914 | $ | 54,727 | ||||||||
Reconciliation of Net income (loss) to Adjusted EBITDA |
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Net income |
$ | 21,517 | $ | 28,046 | $ | 15,863 | $ | 3,927 | ||||||||
Interest expense |
6,373 | 6,609 | 12,908 | 12,402 | ||||||||||||
Unrealized (gain) loss on derivative instruments |
(30,230 | ) | (23,750 | ) | (23,504 | ) | 7,228 | |||||||||
Accretion |
8,892 | 5,444 | 17,972 | 9,382 | ||||||||||||
Depreciation, depletion, amortization and impairment |
15,184 | 13,936 | 27,555 | 21,930 | ||||||||||||
Loss (gain) on sale of asset |
120 | (142 | ) | 120 | (142 | ) | ||||||||||
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Adjusted EBITDA |
$ | 21,856 | $ | 30,143 | $ | 50,914 | $ | 54,727 | ||||||||
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