Linn Energy, LLC 10-Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended March 31, 2006
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
for the transition period from to
Commission File Number: 000-51719
LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)
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Delaware
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65-1177591 |
(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification Number) |
650 Washington Road
8th Floor
Pittsburgh, PA 15228
(Address of principal executive offices)
(412) 440-1400
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or
a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule
12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer o Non-accelerated filer þ
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
As of June 1, 2006, there were 27,832,500 units outstanding.
Item 1. Financial Statements.
LINN ENERGY, LLC
CONSOLIDATED BALANCE SHEETS
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March 31, |
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December 31, |
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2006 |
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2005 |
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(Unaudited) |
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(in thousands) |
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Assets |
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Current assets: |
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Cash and cash equivalents |
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$ |
15,880 |
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$ |
11,041 |
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Receivables: |
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Natural gas and oil, net of allowance for doubtful
accounts of $100,000
as of March 31, 2006 and December 31, 2005 |
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9,387 |
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17,103 |
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Other |
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241 |
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|
650 |
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Fair value of interest rate swaps |
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273 |
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202 |
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Inventory |
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68 |
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68 |
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Current portion of natural gas derivatives |
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8,831 |
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1,601 |
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Prepaid expenses and other current assets |
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1,528 |
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4,068 |
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Total current assets |
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36,208 |
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34,733 |
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Natural gas and oil properties and related equipment |
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272,048 |
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249,565 |
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Less accumulated depreciation, depletion, and amortization |
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14,254 |
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10,707 |
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257,794 |
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238,858 |
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Property and equipment, net |
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3,626 |
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2,525 |
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Other assets: |
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Prepaid drilling costs |
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418 |
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435 |
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Long-term portion of natural gas derivatives |
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3,751 |
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2,795 |
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Operating bonds |
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197 |
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198 |
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4,366 |
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3,428 |
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Total assets |
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$ |
301,994 |
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$ |
279,544 |
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The accompanying notes are an integral part of these financial statements.
3
LINN ENERGY, LLC
CONSOLIDATED BALANCE SHEETS
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March
31, |
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December 31, |
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2006 |
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2005 |
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(Unaudited) |
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(in thousands) |
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Liabilities and Unitholders Capital (Deficit) |
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Current liabilities: |
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Current portion of long-term notes payable |
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$ |
442 |
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$ |
113 |
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Subordinated term loan |
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59,501 |
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Accounts payable and accrued expenses |
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4,257 |
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5,572 |
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Current portion of natural gas derivatives |
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4,869 |
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12,094 |
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Revenue distribution |
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1,520 |
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6,082 |
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Accrued interest payable |
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958 |
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1,448 |
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Gas purchases payable |
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761 |
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1,208 |
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Other current liabilities |
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40 |
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40 |
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Total current liabilities |
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12,847 |
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86,058 |
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Long-term liabilities: |
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Long-term portion of notes payable |
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1,476 |
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|
695 |
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Credit facility |
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157,279 |
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206,119 |
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Long-term portion of interest rate swaps |
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327 |
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663 |
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Asset retirement obligation |
|
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5,555 |
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5,443 |
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Long-term portion of natural gas derivatives |
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18,955 |
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27,139 |
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Other long-term liabilities |
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368 |
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258 |
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Total long-term liabilities |
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183,960 |
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240,317 |
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Total liabilities |
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196,807 |
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326,375 |
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Unitholders capital (deficit): |
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27,812,500 Units issued and outstanding at March 31, 2006 |
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146,065 |
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16,024 |
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Accumulated loss |
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(40,878 |
) |
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(62,855 |
) |
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105,187 |
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(46,831 |
) |
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Total liabilities and unitholders capital (deficit) |
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$ |
301,994 |
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$ |
279,544 |
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The accompanying notes are an integral part of these financial statements.
4
LINN ENERGY, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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Three months ended March 31, |
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2006 |
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2005 |
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(in thousands) |
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Revenues: |
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Natural gas and oil sales |
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$ |
16,375 |
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$ |
6,146 |
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Realized gain (loss) on natural gas derivatives |
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3,323 |
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(8,575 |
) |
Unrealized gain (loss) on natural gas derivatives |
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20,923 |
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(6,580 |
) |
Natural gas marketing income |
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1,218 |
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|
814 |
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Other income |
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289 |
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74 |
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42,128 |
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(8,121 |
) |
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Expenses: |
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Operating expenses |
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2,994 |
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1,817 |
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Natural gas marketing expense |
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983 |
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790 |
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General and administrative expenses |
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9,470 |
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|
478 |
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Depreciation, depletion and amortization |
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3,700 |
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1,181 |
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17,147 |
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4,266 |
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24,981 |
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(12,387 |
) |
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Other income and (expenses): |
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Interest income |
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146 |
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Interest and financing expense |
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(2,639 |
) |
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20 |
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Write-off of deferred financing fees and other losses |
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(392 |
) |
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(32 |
) |
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(2,885 |
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(12 |
) |
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Income (loss) before income taxes |
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22,096 |
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(12,399 |
) |
Income tax (provision) |
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(119 |
) |
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Net income (loss) |
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$ |
21,977 |
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|
$ |
(12,399 |
) |
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Net income (loss) per unit basic |
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$ |
0.84 |
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$ |
(.60 |
) |
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Net income (loss) per unit diluted |
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$ |
0.84 |
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$ |
(.60 |
) |
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Weighted average units outstanding basic |
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26,272,564 |
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20,518,065 |
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Weighted average units outstanding diluted |
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26,272,564 |
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20,518,065 |
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The accompanying notes are an integral part of these financial statements.
5
LINN ENERGY, LLC
CONSOLIDATED STATEMENT OF UNITHOLDERS CAPITAL (DEFICIT)
For the Three Months Ended March 31, 2006
(Unaudited)
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Treasury |
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Total |
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Unitholders |
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Accumulated |
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Units |
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Unitholders |
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Capital |
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Loss |
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(at Cost) |
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Capital (Deficit) |
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(in thousands) |
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Balance as of December 31, 2005 |
|
$ |
16,024 |
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|
$ |
(62,855 |
) |
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|
|
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|
$ |
(46,831 |
) |
Sale of units, net of offering expense of $4,339 |
|
|
225,139 |
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|
|
|
|
|
|
13,671 |
|
|
|
238,810 |
|
Redemption
of member interests |
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|
|
|
|
|
|
|
|
(114,449 |
) |
|
|
(114,449 |
) |
Cancellation
of member interests |
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|
(100,778 |
) |
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|
100,778 |
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Unit-based
compensation expense |
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|
5,680 |
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|
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|
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|
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|
5,680 |
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Net income |
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|
21,977 |
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|
21,977 |
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|
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|
|
|
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|
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|
Balance as of March 31, 2006 |
|
$ |
146,065 |
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|
$ |
(40,878 |
) |
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|
|
|
|
$ |
105,187 |
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|
|
|
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The accompanying notes are an integral part of these financial statements.
6
LINN ENERGY, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
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Three months ended March 31, |
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2006 |
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2005 |
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(in thousands) |
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Cash flow from operating activities: |
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|
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Net income (loss) |
|
$ |
21,977 |
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|
$ |
(12,399 |
) |
Adjustments to reconcile net income (loss) to net cash provided by (used
in) operating activities: |
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|
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|
|
Depreciation, depletion and amortization |
|
|
3,700 |
|
|
|
1,181 |
|
Amortization of deferred financing fees |
|
|
190 |
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|
|
45 |
|
Write-off of deferred financing fees and other losses |
|
|
392 |
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|
32 |
|
Accretion of asset retirement obligation |
|
|
58 |
|
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|
25 |
|
Unrealized (gain) loss on natural gas and interest rate derivatives |
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|
(21,330 |
) |
|
|
5,624 |
|
Unit-based compensation |
|
|
5,680 |
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Changes in assets and liabilities: |
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Decrease in accounts receivable |
|
|
8,126 |
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|
906 |
|
(Increase) decrease in prepaid expenses and other assets |
|
|
(992 |
) |
|
|
11 |
|
(Decrease) in accounts payable and accrued expenses |
|
|
(4,344 |
) |
|
|
(1,162 |
) |
(Decrease) in natural gas derivatives |
|
|
(2,673 |
) |
|
|
(522 |
) |
(Decrease) in revenue distribution |
|
|
(4,562 |
) |
|
|
(215 |
) |
Increase in asset retirement obligation |
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|
4 |
|
|
|
11 |
|
(Decrease) in accrued interest payable |
|
|
(489 |
) |
|
|
(298 |
) |
Increase in other liabilities |
|
|
110 |
|
|
|
|
|
(Decrease) increase in gas purchases payable |
|
|
(447 |
) |
|
|
22 |
|
|
|
|
|
|
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Net cash provided by (used in) operating activities |
|
|
5,400 |
|
|
|
(6,739 |
) |
|
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|
|
|
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Cash flow from investing activities: |
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|
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|
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|
Acquisition and development of natural gas and oil properties |
|
|
(21,784 |
) |
|
|
(1,899 |
) |
Purchases of property and equipment |
|
|
(747 |
) |
|
|
(29 |
) |
Obligations related to drilling activities |
|
|
3,024 |
|
|
|
|
|
Proceeds from sale of assets |
|
|
14 |
|
|
|
24 |
|
Decrease (increase) in operating bonds |
|
|
|
|
|
|
(31 |
) |
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|
|
|
|
|
|
Net cash used in investing activities |
|
|
(19,493 |
) |
|
|
(1,935 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from sale of units |
|
|
243,149 |
|
|
|
|
|
Redemption
of members units |
|
|
(114,449 |
) |
|
|
|
|
Proceeds from notes payable |
|
|
|
|
|
|
5,000 |
|
Principal payments on notes payable |
|
|
(60,056 |
) |
|
|
(14 |
) |
Principal payment on credit facility |
|
|
(62,000 |
) |
|
|
|
|
Proceeds from credit facility |
|
|
13,000 |
|
|
|
3,000 |
|
Deferred offering costs |
|
|
(807 |
) |
|
|
(265 |
) |
Deferred financing fees |
|
|
95 |
|
|
|
(15 |
) |
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
18,932 |
|
|
|
7,706 |
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
4,839 |
|
|
|
(968 |
) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents: |
|
|
|
|
|
|
|
|
Beginning |
|
|
11,041 |
|
|
|
2,188 |
|
|
|
|
|
|
|
|
Ending |
|
$ |
15,880 |
|
|
$ |
1,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
|
|
Cash payments for interest |
|
$ |
3,336 |
|
|
$ |
1,189 |
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of non cash investing and financing activities: |
|
|
|
|
|
|
|
|
Increase in natural gas and oil properties and related asset
retirement obligation due to acquisitions and new drilling |
|
$ |
49 |
|
|
$ |
5 |
|
Acquisition
of vehicles and equipment through the issuance of notes payable |
|
|
1,172 |
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
7
LINN ENERGY, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of Presentation
The consolidated financial statements at March 31, 2006 and for the three months ended March
31, 2006 and 2005 are unaudited, but in the opinion of management include all adjustments
(consisting only of normal recurring adjustments) necessary for a fair presentation of the
results for the interim periods. Certain information and note disclosures normally included
in annual financial statements prepared in accordance with U.S.
generally accepted accounting principles in the United States have been condensed or omitted under the Securities and
Exchange Commissions rules and regulations. The results reported in these unaudited
condensed consolidated financial statements should not necessarily be taken as indicative of
results that may be expected for the entire year.
The financial information included herein should be read in conjunction with the financial
statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2005.
(2) Summary of Significant Accounting Policies
|
(a) |
|
Organization and Description of Business |
|
|
|
|
Linn Energy, LLC (Linn or the Company) was reorganized as a limited liability
company in April 2005 under the laws of the State of Delaware. The Company is an
independent natural gas and oil company focused on the development and acquisition of properties in the Appalachian Basin, primarily in West Virginia, Pennsylvania, New
York and Virginia. Linns wholly owned subsidiaries include Linn Energy Holdings, LLC
(Holdings), Linn Operating, Inc. (Operating), Penn West Pipeline, LLC (Penn
West), and Mid Atlantic Well Service, Inc. (Mid Atlantic). |
|
|
(b) |
|
Principles of Consolidation |
|
|
|
|
The consolidated financial statements include the accounts of the Company and its
wholly owned subsidiaries. The Company presents its financial statements in accordance
with U.S. generally accepted accounting principles. All material inter-company
transactions and balances have been eliminated upon consolidation. |
|
|
(c) |
|
Cash Equivalents |
|
|
|
|
For purposes of the statement of cash flows, the Company considers all highly liquid
debt instruments with original maturities of three months or less to be cash
equivalents. |
|
|
(d) |
|
Natural Gas and Oil Properties |
|
|
|
|
The Company accounts for natural gas and oil properties by the successful efforts
method. Leasehold acquisition costs are capitalized. If proved reserves are found on
an undeveloped property, leasehold costs are transferred to proved properties. Under
this method of accounting, costs relating to the development of proved areas are
capitalized when incurred. |
|
|
|
|
Depreciation and depletion of producing natural gas and oil properties is recorded
based on units of production. Unit rates are computed for unamortized drilling and
development costs using proved developed reserves and for unamortized leasehold costs
using all proved reserves. Statement of Financial Accounting Standards (SFAS) No. 19
requires that acquisition costs of proved properties be amortized on the basis of all
proved reserves, developed and undeveloped, and that capitalized development costs
(wells and related equipment and facilities) be amortized on the basis of proved
developed reserves. The Company follows SFAS No. 143. Under SFAS 143, estimated asset
retirement costs are recognized when the obligation is incurred, and are
amortized over proved developed reserves using the units of production method. Asset
retirement costs are estimated by the Companys engineers using existing regulatory
requirements and anticipated future inflation rates. |
|
|
|
|
Geological, geophysical and exploratory dry hole costs on natural gas and oil
properties relating to unsuccessful exploratory wells are charged to expense as
incurred. |
8
|
|
|
Upon sale or retirement of complete fields of depreciable or depleted property, the
book value thereof, less proceeds or salvage value, is charged or credited to income.
On sale or retirement of an individual well the proceeds are credited to accumulated
depreciation and depletion. |
|
|
|
|
Natural gas and oil properties are reviewed for impairment when facts and
circumstances indicate that their carrying value may not be recoverable. The Company
assesses impairment of capitalized costs of proved natural gas and oil properties by
comparing net capitalized costs to estimated undiscounted future net cash flows using
expected prices. If net capitalized costs exceed estimated undiscounted future net
cash flows, the measurement of impairment is based on estimated fair value, which
would consider estimated future discounted cash flows. No impairments were recorded
during the first three months of 2006 or 2005. |
|
|
|
|
Unproved properties that are individually insignificant are amortized. Unproved
properties that are individually significant are assessed for impairment on a
property-by-property basis. If considered impaired, costs are charged to expense when
such impairment is deemed to have occurred. |
|
|
(e) |
|
Natural Gas and Oil Reserve Quantities |
|
|
|
|
The Companys estimate of proved reserves is based on the quantities of natural gas
and oil that engineering and geological analyses demonstrate, with reasonable
certainty, to be recoverable from established reservoirs in the future under current
operating and economic parameters. Schlumberger Data and Consulting Services prepares
a reserve and economic evaluation of all the Companys properties on a well-by-well
basis annually. |
|
|
|
|
Reserves and their relation to estimated future net cash flows impact the Companys
depletion and impairment calculations. As a result, adjustments to depletion and
impairment are made concurrently with changes to reserve estimates. The Company
prepares its 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 reports.
The accuracy of the Companys reserve estimates is a function of many factors
including the following: 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. |
|
|
|
|
The Companys 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 natural gas, natural gas liquids and
oil eventually recovered. |
|
|
(f) |
|
Income Taxes |
|
|
|
|
The Company is a limited liability company treated as a partnership for federal and
state income tax purposes with all income tax liabilities and/or benefits of the
Company being passed through to the unitholders. As such, no recognition of federal
or state income taxes for the company and its subsidiaries that are organized as
limited liability companies have been provided for in the accompanying financial
statements except as described below. |
|
|
|
|
Certain subsidiaries are subchapter C-corporations subject to corporate income taxes,
which are accounted for under the asset and liability method. Deferred tax assets and
liabilities are recognized for the future tax consequences attributable to differences
between the financial statement carrying amounts of existing assets and liabilities
and their respective tax basis and operating loss and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are expected
to be recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the enactment
date. Deferred tax liabilities of approximately $193,000 and $74,000 have been
included in other long-term liabilities as of March 31, 2006 and December 31, 2005,
respectively. Deferred tax benefits of $900,000 related to net
operating losses and other carry-forwards are reflected net of a
valuation allowance of the same amount since, as of March 31,
2006, the subsidiaries generating that benefit are unlikely to
generate adequate on-going taxable income to realize those benefits. |
|
|
(g) |
|
Derivative Instruments and Hedging Activities |
|
|
|
|
The Company periodically uses derivative financial instruments to achieve a more
predictable cash flow from its natural gas production by reducing its exposure to
price fluctuations. As of March 31, 2006, these transactions were in the form of swaps
and puts. Additionally, the Company uses derivative financial instruments in the form
of interest rate swaps to mitigate its interest rate exposure. The Company accounts
for its derivatives at fair value as an asset or liability and the change in the fair
value of derivatives is included in income. |
9
|
(h) |
|
Earnings per unit |
|
|
|
|
Basic earnings per unit is computed by dividing net earnings attributable
to unitholders by the weighted average number of units outstanding during each period.
During 2006 for the period prior to the Offering, equivalent units
were calculated by adjusting pre-Offering members membership
interests by the exchange ratio to reflect the exchange of
pre-Offering membership interests for post-Offering units and cash
immediately prior to completion of the Offering (see Note 3).
Diluted earnings per unit is computed by adjusting the average number of units
outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the
treasury stock method to determine the dilutive effect. For the quarter ended March 31, 2006, unvested units granted but not issued to the CEO and all unit options outstanding were excluded in the computation of diluted EPS, because to do so would have been antidilutive for the period. |
|
|
(i) |
|
Use of Estimates |
|
|
|
|
Management of the Company has made a number of estimates and assumptions relating to
the reporting of assets and liabilities and revenues and expenses and the disclosure
of contingent assets and liabilities to prepare these financial statements in
conformity with U.S. generally accepted accounting principles. Actual results could
differ from those estimates. The estimates that are particularly significant to the
financial statements include estimates of natural gas and oil reserves, future cash
flows from natural gas and oil properties, and depreciation, depletion and
amortization, asset retirement obligations and the fair value of derivatives. |
|
|
(j) |
|
Revenue Recognition |
|
|
|
|
Sales of natural gas and oil are recognized when natural gas has been delivered to a
custody transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser upon delivery, collection of
revenue from the sale is reasonably assured, and the sales price is fixed or
determinable. Natural gas is sold by the Company on a monthly basis. Virtually all of
the Companys contracts pricing provisions are tied to a market index, with certain
adjustments based on, among other factors, whether a well delivers to a gathering or
transmission line, quality of natural gas, and prevailing supply and demand
conditions, so that the price of the natural gas fluctuates to remain competitive with
other available natural gas supplies. As a result, the Companys revenues from the
sale of natural gas will suffer if market prices decline and benefit if they increase.
The Company believes that the pricing provisions of its natural gas contracts are
customary in the industry. |
|
|
|
|
Gas imbalances occur when the Company sells more or less than its entitled ownership
percentage of total gas production. Any amount received in excess of the Companys
share is treated as a liability. If the Company receives less than its entitled share,
the underproduction is recorded as a receivable. The Company did not have any
significant gas imbalance positions at March 31, 2006 or December 31, 2005. |
|
|
|
|
Natural gas marketing is recorded on the gross accounting method because Penn West,
the Companys marketing subsidiary, takes title to the natural gas it purchases from
the various producers and bears the risks and enjoys the benefits of that ownership.
Natural gas marketing revenues totaled $1,218,000 and $814,000 and natural gas
marketing expenses were $983,000 and $790,000 for the three months ended March 31, 2006
and 2005, respectively. |
|
|
|
|
The Company currently uses the Net-Back method of accounting for transportation
arrangements of its natural gas sales. The Company sells natural gas at the wellhead
and collects a price and recognizes revenues based on the wellhead sales price since
transportation costs downstream of the wellhead are incurred by its customers and
reflected in the wellhead price. |
|
|
|
|
The Company is paid a monthly operating fee for each well it operates for outside
owners. The fee covers monthly operating and accounting costs, insurance and other
recurring costs. As the operating fee is a reimbursement for costs incurred on behalf
of third parties, the fee has been netted against general and administrative expense.
For the three months ended March 31, 2006 and 2005 the operating fees netted against
general and administrative expense were $284,000 and $287,000, respectively. |
|
|
(k) |
|
Unit-Based Compensation |
|
|
|
|
The Company accounts for unit-based compensation pursuant to SFAS No. 123(R)
Share-Based Payment. SFAS No. 123(R), which requires an entity to recognize at the
grant date the fair value of unit options and other equity-based compensation issued
to employees in the income statement. The value of the portion of the award that is
ultimately expected to vest is recognized as expense over the requisite service
periods in the Companys consolidated income statement. Compensation expense
attributable to granted awards are recognized using the straight-line method. |
|
|
|
|
The Company utilizes a Black-Scholes option pricing model to measure the fair value of
unit options granted to employees. The Companys determination of fair value of
unit-based payment awards on the date of grant using the model is affected by the
Companys unit price as well as assumptions regarding a number of highly complex and
subjective variables. These variables include, but are not limited to, the Companys
expected unit price volatility over the term of the awards, and actual and projected
employee unit option exercise behaviors. In addition, forfeitures are required to be
estimated at the time of grant and revised, if necessary, in subsequent periods if
actual forfeitures differ from those estimates. Although the fair value of employee unit |
10
|
|
|
options is determined in accordance with SFAS No. 123R and SAB 107 using a
Black-Scholes option-pricing model, that value may not be indicative of the fair value
observed in a willing buyer/willing seller market transaction. The Company is
responsible for determining the assumptions used in estimating the fair value of its
unit-based payment awards. The Company recorded $5,680,000 of unit-based compensation
expense for the three months ended March 31, 2006. As of March 31, 2005 and December
31, 2005, there were no outstanding unit-based awards. |
|
|
(l) |
|
Recently Issued Accounting Standards |
|
|
|
|
As of January 1, 2006, the Company adopted SFAS No. 154 Accounting Changes and
Error Corrections, a replacement of APB Opinion No. 20 and SFAS No. 3 (SFAS No.
154). SFAS No. 154 requires retrospective application of voluntary changes in
accounting principles, unless it is impracticable. The implementation of this standard
did not have a material impact on the consolidated financial statements. |
(3) Initial Public Offering
During the three months ended March 31, 2006, the Company completed its initial public
offering (IPO) of 12,450,000 units representing limited
liability interests in the Company
at $21.00 per unit, for net proceeds, after underwriting discounts
and other offering costs, of $243.1 million, of
which $122.0 million was used to reduce indebtedness under the Companys revolving credit
facility and repay, in full, the subordinated term loan, approximately $114.4 million was
used to redeem a portion of the membership interests in the Company and units held by certain
affiliated and non-affiliated holders, approximately $4.3 million was used to pay offering
expenses and approximately $2.0 million was used to pay bonuses to certain executive officers
of the Company.
Subsequent
to March 31, 2006, the Companys Board of Directors
declared distributions of $0.32 per unit with respect to the first quarter
of 2006 pro-rated for the period from the closing of the offering on
January 19, 2006 to March 31, 2006. As a result, the Company paid
aggregate distributions of approximately $8.9 million
on May 15, 2006.
(4) Natural
Gas and Oil Properties:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Unproved
Properties |
|
$ |
6,181,000 |
|
|
$ |
4,562,000 |
Proved Developed Properties: |
|
|
|
|
|
|
|
|
Acquisition,
equipment and drilling |
|
|
260,267,000 |
|
|
|
239,423,000 |
|
Pipelines |
|
|
5,600,000 |
|
|
|
5,580,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
272,048,000 |
|
|
|
249,565,000 |
|
|
|
|
|
|
|
|
|
|
Less
accumulated depreciation, depletion and amortization |
|
|
(14,254,000 |
) |
|
|
(10,707,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
257,794,000 |
|
|
$ |
238,858,000 |
|
|
|
|
|
|
|
|
(5) Debt
Credit Facility
On
April 7, 2006, the Company replaced its prior credit agreement
and entered into a new $400.0
million Amended and Restated Credit Agreement (the Credit Agreement) with BNP Paribas as
administrative agent. The Credit Agreement matures on April 13, 2009. The amount available
for borrowing at any one time is limited to the borrowing base, which
as a result of this new arrangement increased from $225.0 million to
$235.0 million. The borrowing base further increased to $265.0 million in June 2006. The borrowing base will be redetermined semi-annually by the lenders in their
sole discretion, based on, among other things, reserve reports as prepared by reserve
engineers taking into account the natural gas and oil prices at such time. Our obligations
under the Credit Agreement are secured by mortgages on our natural gas and oil properties as
well as a pledge of all ownership interests in our operating subsidiaries. We are required
to maintain the mortgages on properties representing at least 80% of our natural gas and oil
properties. Additionally, the obligations under the Credit Agreement are guaranteed by all
of our operating subsidiaries and may be guaranteed by any future subsidiaries.
Borrowings under the Credit Agreement are available for acquisition and development of
natural gas and oil properties, working capital, and general corporate purposes. At our
election, interest is determined by reference to the London interbank offered rate (LIBOR)
plus an applicable margin between 1.00% and 1.75% per annum; or a domestic bank rate plus an
applicable margin between 0.00% and 0.25% per annum. Interest is generally payable quarterly
for domestic bank rate loans and at the applicable maturity date for LIBOR loans.
11
The Credit Agreement contains various covenants that limit the Companys ability to incur
additional indebtedness, make acquisitions or certain capital expenditures; make
distributions other than from available cash; merge or consolidate; and engage in certain
asset dispositions. The Credit Agreement also contains covenants that, among other things,
require us to maintain specified financial ratios. The Company
obtained a waiver through June 30, 2006 from the
covenant under its credit facility regarding the timely provision of quarterly financial
statements to the administrative agent under the facility. The Company is in compliance with
all financial and other covenants of its credit facility.
As of March 31, 2006 and December 31, 2005, the credit facility consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March, 31 |
|
|
December, 31, |
|
|
|
2006 |
|
|
2005 |
|
Outstanding balance |
|
$ |
158,000,000 |
|
|
$ |
207,000,000 |
|
Less deferred financing fees, net of amortization of $226,000 and $160,000 |
|
|
(721,000 |
) |
|
|
(881,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
157,279,000 |
|
|
$ |
206,119,000 |
|
|
|
|
|
|
|
|
Accrued
interest was $958,000 and $1,052,898 at March 31, 2006 and December 31, 2005,
respectively.
As of June 21, 2006 we had outstanding indebtedness of $193.6 million under the credit
facility and additional borrowing ability of $71.4 million.
Subordinated Term Loan
On October 27, 2005, the Company entered into a facility for a $60 million second lien senior
subordinated term loan (the subordinated term loan) with Royal Bank of Canada and Societe
Generale. The borrowings under the subordinated term loan were used to fund a portion of the
purchase price for the acquisition of natural gas and oil properties from Exploration
Partners. The outstanding balance was paid in full in January 2006 with proceeds from our initial public
offering.
(6) Long-term Notes Payable
The Company has the following long-term notes payable outstanding:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Note payable to a bank with an
interest rate of 6.14%, payable in
monthly installments of $2,918,
including interest, through
September 2024. The note is secured
by an office building. |
|
$ |
384,000 |
|
|
$ |
387,000 |
|
Various notes for the purchase of
vehicles and equipment, payable in monthly
installments totaling $41,315 and
$10,806 as of March 31, 2006 and
December 31, 2005, respectively, including
interest. The interest rates range from 0-8.74%. The notes are secured by
the vehicles purchased and expire at
various dates from 2008 through 2011. |
|
|
1,534,000 |
|
|
|
421,000 |
|
|
|
|
|
|
|
|
|
|
|
1,918,000 |
|
|
|
808,000 |
|
|
|
|
|
|
|
|
|
|
Less current portion |
|
|
442,000 |
|
|
|
113,000 |
|
|
|
|
|
|
|
|
|
|
$ |
1,476,000 |
|
|
$ |
695,000 |
|
|
|
|
|
|
|
|
As of March 31, 2006, maturities on the aforementioned long-term notes payable were as
follows:
|
|
|
|
|
March 31: |
|
|
|
|
2006 |
|
$ |
442,000 |
|
2007 |
|
|
439,000 |
|
2008 |
|
|
374,000 |
|
2009 |
|
|
200,000 |
|
2010 |
|
|
146,000 |
|
Thereafter |
|
|
317,000 |
|
|
|
|
|
|
|
$ |
1,918,000 |
|
|
|
|
|
12
(7) Business and Credit Concentrations
Cash
The Company maintains its cash in bank deposit accounts, which, at times, may exceed
federally insured amounts. The Company has not experienced any losses in such accounts. The
Company believes it is not exposed to any significant credit risk on its cash.
Revenue and Trade Receivables
The Company has a concentration of customers who are engaged in natural gas and oil
production within the Appalachian region. This concentration of customers may impact the
Companys overall exposure to credit risk, either positively or negatively, in that the
customers may be similarly affected by changes in economic or other conditions. The Company
performs ongoing credit evaluations of its customers and generally does not require
collateral.
The Companys largest customers are natural gas producers and suppliers located within the
Appalachian region. For the three months ended March 31, 2006, the Companys two largest
customers represented 70% and 10% of the Companys sales. The Companys four largest
customers represented approximately 27%, 21%, 14%, and 10% of the Companys sales for the
three months ended March 31, 2005.
Trade
accounts receivable from natural gas sales from two customers accounted for more than 10% of the
Companys trade accounts receivable. As of March 31, 2006, trade accounts receivable from these
customers represented approximately 70%, and 11% of the Companys receivables. Trade accounts
receivable for the four largest customers represented approximately 27%, 23%, 14% and 10% of the
Companys receivables as of March 31, 2005.
(8) Unit-Based Compensation
The Linn Energy, LLC Long-Term Incentive Plan (the Plan) permits the granting of unit
grants, unit options, restricted units, phantom units and unit appreciation rights under the
terms of the Plan. The Plan limits the number of units that may be delivered pursuant to
awards to 3.9 million units, provided that no more than 500,000 of such units (as adjusted)
may be issued as restricted units. The plan is administered by the compensation committee of
our Board of Directors.
Our Board of Directors and the compensation committee of the Board have the right to alter or
amend the Plan or any part of the Plan from time to time, including increasing the number of
units that may be granted, subject to unitholder approval as required by the exchange upon
which the units are listed at that time. However, no change in any outstanding grant may be
made that would materially reduce the benefits to the participant without the consent of the
participant.
Upon exercise or vesting of an award of, or settled in, units the Company will issue new
units, acquire units on the open market or directly from any person or use any combination of
the foregoing, in the compensation committees discretion. If we issue new units upon
exercise or vesting of an award of, or settled in, units, the total number of units
outstanding will increase. The plan provides for following types of awards:
Unit Grants. A unit grant is a unit that vests immediately upon issuance.
Unit Options. A unit option is a right to purchase a unit at a specified price at terms
determined by the committee. Unit options will have an exercise price that will not be less
than the fair market value of the units on the date of grant, and in general, will become
exercisable over a vesting period but may accelerate upon the achievement of specified
financial objectives, or upon a change in control of the Company. If a grantees employment
or relationship terminates for any reason, the grantees unvested unit options will be
automatically forfeited unless the option agreement or the compensation committee provides
otherwise.
Restricted Units. A restricted unit is a unit that vests over a period of time and that
during such time is subject to forfeiture, and may contain such terms as the compensation
committee shall determine, including the period over which restricted units (and
distributions related to such units) will vest. The Company intends the restricted units
under the plan to serve as a means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity appreciation of our units.
Therefore, plan participants will not pay any consideration for the units they receive. If a grantees employment, consulting
relationship or membership on the Board of Directors terminates for any reason, the grantees
restricted units will be automatically forfeited unless the compensation committee or the
terms of the award agreement provide otherwise.
13
Although not initially expected to be granted, the plan also authorizes Phantom Units and
Unit Appreciation Rights, which may be settled in units, cash or a combination thereof. Such
grants will contain terms as determined by the compensation committee, including the period
or terms over which phantom units will vest. If a grantees employment or relationship
terminates for any reason, the grantees phantom units or unit appreciation rights will be
automatically forfeited unless, and to the extent, the compensation committee or the terms of
the award agreement provide otherwise. While phantom units require no payment from the
grantee, unit appreciation rights will have an exercise price that will not be less than the
fair market value of the units on the date of grant.
Accounting for unit-based
compensation. SFAS No. 123R provides specific guidance on income
tax accounting and clarifies how SFAS No. 109, Accounting for
Income Taxes, should be
applied to unit-based compensation. For example, the expense for types of option
grants is only deductible for tax purposes at the time that the
taxable event takes place. SFAS No. 123R does not allow companies to predict when these taxable
events will take place. Furthermore, it requires that the benefits associated with the tax
deductions in excess of recognized compensation cost be reported as a financing cash flow,
rather than as an operating cash flow as required under SFAS No. 123. This requirement will
reduce net operating cash flows and increase net financing cash flows in periods. These
future amounts cannot be estimated, because they depend on, among other things, when
employees exercise unit options.
For the three months ended March 31, 2006, we recorded unit-based compensation of
$5,680,000 as a charge against income before income taxes and is
included in general and
administrative expense. No related income tax benefit was recognized
due to Section 162(m) deductibility limits and recognition of a valuation
allowance for resulting net operating losses.
Restricted/Unrestricted Units
The fair value of the awards issued is determined based on the fair market value of the units
on the date of grant. This value is amortized over the vesting period, which varied between
one to two years from the date of grant for certain officers. A summary of the status of the
non-vested units as of March 31, 2006, and changes during the three months ended March 31,
2006, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
Number of |
|
|
Grant-Date |
|
|
|
Non-vested Units |
|
|
Fair Value |
|
Non-vested units as of December 31, 2005 |
|
|
|
|
|
$ |
|
|
Granted |
|
|
854,690 |
|
|
|
21.00 |
|
Vested |
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested units as of March 31, 2006 |
|
|
854,690 |
|
|
$ |
21.00 |
|
|
|
|
|
|
|
|
As of March 31, 2006,
there was $14.7 million of total unrecognized compensation cost related
to non-vested restricted units. The cost is expected to be recognized over a weighted average
period of 1.3 years.
14
Securities Authorized for Issuance Under Equity Compensation Plan. As of March 31, 2006, the
Company had 3.9 million units issuable pursuant to outstanding award agreements or reserved
for issuance under the Companys Long-Term Incentive Plan.
Changes in Unit Options and Unit Options Outstanding.
The following table provides information related to unit option activity for the three months
ended March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Average |
|
|
|
|
|
|
Weighted |
|
|
|
Units |
|
|
Exercise |
|
|
Weighted Average |
|
|
Average |
|
|
|
Underlying |
|
|
Price |
|
|
Grant Date Fair |
|
|
Contractual |
|
|
|
Options |
|
|
Per Unit |
|
|
Value |
|
|
Life in Years |
|
Outstanding at December 31, 2005 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
Granted |
|
|
456,084 |
|
|
|
20.74 |
|
|
|
3.22 |
|
|
|
10.00 |
|
Exercised |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2006 |
|
|
456,084 |
|
|
$ |
20.74 |
|
|
$ |
3.22 |
|
|
|
10.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at March 31, 2006 |
|
|
30,000 |
|
|
$ |
20.18 |
|
|
$ |
2.80 |
|
|
|
10.00 |
|
As of March 31, 2006, there was $0.7 million of total unrecognized compensation cost related
to non-vested unit options. The cost is expected to be recognized over a weighted average
period of 3 years. In addition, the exercisable options at
March 31, 2006 have an aggregate intrinsic
value of $6,600 and all outstanding options have an aggregate intrinsic value of $36,000. No options expired during the period.
Subsequent to March 31, 2006, the Company granted an aggregate 75,000 options which are
subject to both performance and service requirements and 20,000 restricted units to an
executive officer.
The fair value of unit-based compensation was estimated on the date of grant using a
Black-Scholes pricing model based on assumptions noted in the following table. The Companys
employee unit options have various restrictions including vesting provisions and restrictions
on transfers and hedging, among others, and are often exercised prior to their contractual
maturity. Expected volatilities used in the estimation of fair value
have been determined using all available volatility data for the
Company as well as an average of volatility computations of other
identified peer companies in the oil and gas industry. The Company uses historical data to estimate unit option
exercises, expected term and employee departure behavior used in the Black-Scholes pricing
model. All employees granted awards have been determined to have similar behaviors for
purposes of determining the expected term used to estimate fair value. The risk-free rate for
periods within the contractual term of the unit option is based on the U.S. Treasury yield
curve in effect at the time of grant. The fair values of the grants were based upon the
following assumptions.
|
|
|
|
|
Expected volatility |
|
|
29.70 |
% |
Expected dividends (weighted average 7.5%) |
|
|
7.2%-7.9 |
% |
Expected term (in years) |
|
|
5.00 |
|
Risk free rate |
|
|
4.31%-4.75 |
% |
Expected forfeiture rate |
|
|
23.10 |
% |
(9) Property and Equipment
Property and equipment consists of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
December 31, |
|
|
2006 |
|
2005 |
Land |
|
$ |
308,000 |
|
|
$ |
203,000 |
|
Buildings and leasehold improvements |
|
|
1,001,000 |
|
|
|
608,000 |
|
Vehicles |
|
|
1,842,000 |
|
|
|
1,317,000 |
|
Furniture and equipment |
|
|
1,099,000 |
|
|
|
888,000 |
|
|
|
|
|
|
|
4,250,000 |
|
|
|
3,016,000 |
|
Accumulated depreciation |
|
|
624,000 |
|
|
|
491,000 |
|
|
|
|
|
|
$ |
3,626,000 |
|
|
$ |
2,525,000 |
|
|
|
|
|
|
|
Depreciation expense for the three months ended March 31, 2006 and 2005 was approximately
$153,000 and $53,000, respectively.
(10) Commitments and Contingencies
The Company would be exposed to natural gas price fluctuations on underlying sale contracts
should the counterparties to the Companys derivative instruments or the counterparties to
the Companys natural gas marketing contracts not perform. Such nonperformance is not
anticipated. There were no counterparty default losses during the three months ended March
31, 2006 or 2005.
From time to time the Company is a party to various legal proceedings in the ordinary course
of business. The Company is not currently a party to any litigation that it believes would
have a materially adverse effect on the Companys business, financial condition, results of
operations or liquidity.
15
(11) Natural Gas Derivatives
The Company sells natural gas in the normal course of its business and utilizes derivative
instruments to minimize the variability in forecasted cash flows due to price movements in
natural gas. The Company enters into derivative instruments such as swap contracts and put
options to hedge a portion of its forecasted natural gas sales.
The following table summarizes open positions as of March 31, 2006 and represents our
derivatives in place through December 31, 2009. Settled derivatives on production for the
three months ended March 31, 2006 included a volume of 2,019 MMMBtu at an average price of
$9.23. Currently, we use fixed price swaps and puts to manage commodity prices. These
transactions are settled based upon the NYMEX price of natural gas at Henry Hub on the final
trading day of the month, and settlement occurs on the 3rd day of the production
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year 2006 |
|
Year 2007 |
|
Year 2008 |
|
Year 2009 |
Fixed Price Swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (MMMBtu) |
|
|
5,573 |
|
|
|
7,168 |
|
|
|
6,904 |
|
|
|
5,125 |
|
Average Price ($/MMBtu) |
|
$ |
9.25 |
|
|
$ |
8.64 |
|
|
$ |
7.89 |
|
|
$ |
7.25 |
|
Puts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (MMMBtu) |
|
|
550 |
|
|
|
730 |
|
|
|
|
|
|
|
|
|
Average Price ($/MMBtu) |
|
$ |
8.83 |
|
|
$ |
8.24 |
|
|
$ |
|
|
|
$ |
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Volume (MMMBtu) |
|
|
6,123 |
|
|
|
7,898 |
|
|
|
6,904 |
|
|
|
5,125 |
|
Average Price ($/MMBtu) |
|
$ |
9.21 |
|
|
$ |
8.60 |
|
|
$ |
7.89 |
|
|
$ |
7.25 |
|
The natural gas derivatives are not designated as hedges and, accordingly, the changes in
fair value are recorded in current period earnings.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
December 31, |
|
|
2006 |
|
2005 |
Outstanding notional amounts of hedges (MMMBtu) |
|
|
26,050 |
|
|
|
28,069 |
|
Maximum number of months hedges outstanding |
|
|
45 |
|
|
|
48 |
|
By using derivative instruments to hedge exposures to changes in commodity prices, the
Company exposes itself to credit risk and market risk. Credit risk is the failure of the
counterparty to perform under the terms of the derivative contract. When the fair value of a
derivative contract is positive, the counterparty owes the Company, which creates credit
risk. The Company minimizes the credit risk in derivative instruments by entering into
transactions with high-quality counterparties.
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are an
independent natural gas and oil company focused on the development and acquisition of properties in the Appalachian Basin, primarily in West Virginia, Pennsylvania, New York and
Virginia. Our goal is to provide stability and growth in distributions to our unitholders through a
combination of continued successful drilling and acquisitions. Our company was formed in March
2003. In 2006, we completed our initial public offering of 12,450,000 units at a price of $21.00
per unit, for proceeds after underwriting discounts of approximately $243.1 million, of which
$122.0 million was used to reduce indebtedness under the Companys revolving credit facility and
repay, in full, the subordinated term loan, approximately $114.4 million was used to redeem a
portion of the membership interests in the Company and units held by certain affiliated and
non-affiliated holders, approximately $4.3 million was used to pay offering expenses and
approximately $2.0 million was used to pay bonuses to certain executive officers of the Company.
During the
second quarter of 2006, we closed three acquisitions of natural gas
and oil properties in West Virginia, including 207 producing wells,
and an acquisition of a natural gas gathering pipeline system in
western Pennsylvania by its Penn West subsidiary for an aggregate contract
purchase price of $30.0 million, subject to customary closing adjustments. The acquired properties,
all located in West Virginia, add 207 producing wells.
In addition, from inception through December 31, 2005, we completed nine acquisitions of
natural gas properties and related gathering and pipeline assets for an aggregate purchase price of
$201.5 million, with total proved reserves of 160.1 Bcfe, or an acquisition cost of $1.26 per Mcfe.
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase |
|
|
|
|
|
Gross |
|
|
|
|
Price |
|
Date |
|
Seller |
|
Wells |
|
|
Location |
|
(in millions) |
|
May 2003 |
|
Emax Oil Company |
|
|
34 |
|
|
West Virginia |
|
$ |
3.2 |
|
Aug 2003 |
|
Lenape Resources, Inc. |
|
|
61 |
|
|
New York |
|
|
2.2 |
|
Sep 2003 |
|
Cabot Oil & Gas Corporation |
|
|
50 |
|
|
Pennsylvania |
|
|
15.8 |
|
Oct 2003 |
|
Waco Oil & Gas Company |
|
|
353 |
|
|
West Virginia and Virginia |
|
|
31.5 |
|
May 2004 |
|
Mountain V Oil & Gas, Inc. |
|
|
251 |
|
|
Pennsylvania |
|
|
12.5 |
|
Sep 2004 |
|
Pentex Energy, Inc. |
|
|
447 |
|
|
Pennsylvania |
|
|
15.1 |
|
Apr 2005 |
|
Columbia Natural Resources, LLC |
|
|
38 |
|
|
West Virginia and Virginia |
|
|
4.4 |
|
Aug 2005 |
|
GasSearch Corporation |
|
|
130 |
|
|
West Virginia |
|
|
5.4 |
|
Oct 2005 |
|
Exploration Partners, LLC |
|
|
550 |
|
|
West Virginia and Virginia |
|
|
111.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,914 |
|
|
|
|
$ |
201.5 |
|
|
|
|
|
|
|
|
|
|
|
|
Because of our rapid growth through acquisitions and development of our properties, our historical
results of operations and period-to-period comparisons of these results and certain financial data
may not be meaningful or indicative of future results.
Our acquisitions were financed with a combination of private equity, proceeds from bank borrowings
and cash flow from operations. Our activities are focused on evaluating and developing our asset
base, increasing our acreage positions and evaluating potential acquisitions.
Our revenue, cash flow from operations and future growth depend substantially on factors beyond our
control, such as economic, political and regulatory developments and competition from other sources
of energy. Natural gas and oil prices historically have been volatile and may fluctuate widely in
the future. Sustained periods of low prices for natural gas or oil could materially and adversely
affect our financial position, our results of operations, the quantities of natural gas and oil
reserves that we can economically produce and our access to capital.
We utilize the successful efforts method of accounting for our natural gas and oil properties.
Leasehold costs are capitalized when incurred. Unproved properties
that are individually insignificant are amortized. Unproved
properties that are individually significant are assessed for
impairment on a property-by-property basis. If considered impaired,
costs are charged to expense when such impairments are deemed to have
occurred. Geological and geophysical
expenses and delay rentals are charged to expense as incurred. Drilling costs are typically
capitalized, but charged to expense if an exploratory well is determined to be unsuccessful.
Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel
and field supplies and services and have caused increases in the costs of those goods and services.
To date, the higher sales prices have more than offset the higher drilling and operating costs.
Given the inherent volatility of natural gas prices, which are influenced by many factors beyond
our control, we plan our activities and budget based on conservative sales price assumptions, which
generally are lower than the average sales prices received. We focus our efforts on increasing
natural gas reserves and production while controlling costs at a level that is appropriate for
long-term operations. Our future cash flow from operations is dependent on our ability to manage
our overall cost structure.
We face the challenge of natural production declines. As initial reservoir pressures are depleted,
natural gas production from a given well decreases. We attempt to overcome this natural decline by
drilling to find additional reserves and acquiring more reserves than we produce. Our future growth
will depend on our ability to continue to add reserves in excess of production. We will maintain
our focus on costs to add reserves through drilling and acquisitions as well as the costs necessary
to produce such reserves. Our ability to add reserves through drilling is dependent on our capital
resources and can be limited by many factors, including our ability to timely obtain drilling
permits and regulatory approvals.
Our Operations
Our revenues are highly sensitive to changes in natural gas prices and levels of production. As set
forth in Cash Flow from Operations below, we have hedged a significant portion of our expected
production using natural gas derivatives, which allows us to mitigate, but not eliminate, natural
gas price risk. Our expected increase in levels of production as a result of the anticipated
drilling of 153 wells during 2006 is dependent on our ability to quickly and efficiently bring the
newly drilled wells online. Any delays in drilling, completion or connection to gathering lines of
our new wells will negatively impact the rate of increase in our production, which may have an
adverse effect on our revenues and as a result, cash available for distribution. We continuously
conduct financial sensitivity analyses to assess the effect of changes in pricing and production.
These analyses allow us to determine how changes in natural gas prices will affect the ability to
drill additional wells and to meet future financial obligations. Further, the financial analyses
allow us to monitor any impact such changes in natural gas prices may have on the value of our
proved reserves and their impact, if any, on any redetermination of the borrowing base under our
credit facility.
17
Production and Operating Costs Reporting
We strive to increase our production levels to maximize our revenue and cash available for
distribution. Additionally, we continuously monitor our operations to ensure that we are incurring
operating costs at the lowest possible level. Accordingly, we continuously monitor our production
and operating costs per well to determine if any wells should be shut in or sold.
Land and Lease Tracking System
As a significant amount of our growth is dependent on drilling new wells, we continuously monitor
our lease agreements and our drilling locations to avoid delays. Our monitoring system matches our
lease agreements to existing wells and sites for future development allowing management to make
real time decisions on which acreage to develop and at what point in time. We continually seek to
acquire new lease positions to increase potential drilling locations.
Results of Operations
The following table sets forth selected financial and operating data for the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands, except for per unit data) |
|
|
|
(Unaudited) |
|
Revenues: |
|
|
|
|
|
|
|
|
Natural gas and oil sales |
|
$ |
16,375 |
|
|
$ |
6,146 |
|
Realized gain (loss) on natural gas derivatives |
|
|
3,323 |
|
|
|
(8,575 |
) |
Unrealized gain (loss) on natural gas derivatives |
|
|
20,923 |
|
|
|
(6,580 |
) |
Natural gas marketing income |
|
|
1,218 |
|
|
|
814 |
|
Other income |
|
|
289 |
|
|
|
74 |
|
|
|
|
|
|
|
|
Total revenue |
|
|
42,128 |
|
|
|
(8,121 |
) |
Expenses: |
|
|
|
|
|
|
|
|
Operating expenses |
|
$ |
2,994 |
|
|
$ |
1,817 |
|
Natural gas marketing expense |
|
|
983 |
|
|
|
790 |
|
General and administrative expenses |
|
|
9,470 |
|
|
|
478 |
|
Depreciation, depletion and amortization |
|
|
3,700 |
|
|
|
1,181 |
|
|
|
|
|
|
|
|
Total expenses |
|
|
17,147 |
|
|
|
4,266 |
|
Other Income and (Expenses): |
|
|
|
|
|
|
|
|
Interest and financing expense |
|
$ |
(2,639 |
) |
|
$ |
20 |
|
|
|
|
|
|
|
|
|
|
Net Production: |
|
|
|
|
|
|
|
|
Total production (MMcfe) |
|
|
1,836 |
|
|
|
972 |
|
Average daily production (Mcfe/d) |
|
|
20,400 |
|
|
|
10,800 |
|
|
|
|
|
|
|
|
|
|
Average Sales Prices: |
|
|
|
|
|
|
|
|
Weighted average realized natural gas price (Mcf) |
|
$ |
9.74 |
|
|
$ |
5.84 |
|
Weighted average realized price (Mcfe) |
|
|
9.72 |
|
|
|
5.85 |
|
|
|
|
|
|
|
|
|
|
Average
Unit Costs per Mcfe (Non-GAAP): |
|
|
|
|
|
|
|
|
Operating expenses |
|
$ |
1.63 |
|
|
$ |
1.87 |
|
General and
administrative expenses (1) |
|
|
0.97 |
|
|
|
0.49 |
|
Depreciation, depletion and amortization |
|
|
2.02 |
|
|
|
1.22 |
|
|
|
|
(1) |
|
This is a non-GAAP performance measure used by our management
and is a quantitative measure used in the oil and gas industry. The
measure for the three months ended March 31, 2006 excludes
approximately $2.0 million of bonuses paid and $5.7 million
of unit- based compensation awarded to certain executive officers in
connection with our IPO. General and administrative expenses per Mcfe
including these amounts were $5.16 and $.49 for the three months
ended March 31, 2006 and 2005, respectively. |
18
Three Months Ended March 31, 2006 Compared to the Three Months Ended March 31, 2005
Revenue
Natural gas and oil sales, before realized and unrealized gains and losses on natural gas
derivatives, increased to approximately $16.4 million from $6.1 million during the three months
ended March 31, 2006 as compared to the three months ended March 31, 2005. The key revenue
measurements were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
Percentage |
|
|
|
March 31, |
|
|
Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
Net Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Total production (MMcfe) |
|
|
1,836 |
|
|
|
972 |
|
|
|
89 |
% |
Average daily production (Mcfe/d) |
|
|
20,400 |
|
|
|
10,800 |
|
|
|
89 |
% |
Average Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average realized natural gas price (Mcf) |
|
$ |
9.74 |
|
|
$ |
5.84 |
|
|
|
67 |
% |
Weighted average realized price (Mcfe) |
|
|
9.72 |
|
|
|
5.85 |
|
|
|
66 |
% |
The
increase in natural gas and oil revenue was attributable primarily to the increase
in production to 1,836 MMcfe during the three months ended March 31, 2006 from 972 MMcfe during the
period ended March 31, 2005, the three acquisitions completed in 2005, and the drilling of 29 wells
during the three months ended March 31, 2006 and 110 wells in 2005. In addition to the increase in
production, the average natural gas sales price increased during the three months ended March 31,
2006 as compared to the three months ended March 31, 2005.
Hedging Activities
During the three months ended March 31, 2006, we hedged 100% of our natural gas production, which
resulted in revenues that were $3.3 million greater than we would have achieved at unhedged prices.
During the three months ended March 31, 2005, we hedged approximately 89% of our natural gas
production, which resulted in revenues that were $0.6 million less than we would have achieved at
unhedged prices. During the three months ended March 31, 2005, we cancelled (before their original
settlement date) a portion of out-of-the- money natural gas derivatives and realized a loss of $8.0
million. We subsequently hedged similar volumes at higher prices. Unrealized gain on hedges in the
amount of $21.0 million for the three months ended March 31, 2006 and unrealized loss on hedges in
the amount of $6.6 million for the three months ended March 31, 2005 were also recorded.
Expenses
Operating expenses consist of lease operating expenses, labor, field office rent, vehicle expenses,
supervision, transportation, minor maintenance, tools and supplies, severance and ad valorem taxes
and other customary charges. Severance taxes are a function of volumes and revenues generated from
production. Ad valorem taxes vary by state/county and are based on the value of our reserves. We
assess our operating expenses by monitoring the expenses in relation to the amount of production
and the number of wells operated. Operating expenses increased to $3.0 million for the three months
ended March 31, 2006 from $1.8 million for the three months ended March 31, 2005, due to the
increase in the number of wells as a result of the three acquisitions completed in 2005 and the
drilling of 29 wells during the three months ended March 31, 2006 and 110 wells in 2005. Operating
expenses per Mcfe of production were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
Percentage |
|
|
|
March 31, |
|
|
Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
Operating expenses per Mcfe |
|
$ |
1.63 |
|
|
$ |
1.87 |
|
|
|
(13 |
)% |
General and administrative expenses include the costs of our employees and executive officers,
related benefits, office leases, professional fees and other costs not directly associated with
field operations. We monitor general and administrative expenses in relation to the amount of
production and the number of wells operated. General and administrative expenses increased to $9.5
million from $0.5 million during the three months ended March 31, 2006 as compared to the three
months ended March 31, 2005. During the three months ended March 31, 2006 and 2005, the Company
capitalized approximately $0.3 million and $18,000, respectively, of internal costs related to
drilling. Additionally, general and administrative expenses are presented net of approximately $0.3
million during each of the three month periods ended March 31, 2006 and 2005, respectively, which
represents operating expense reimbursements from other working interest owners. In 2006, we
recognized expense of approximately $2.0 million for bonuses paid to executives in connection with
our IPO and $5.7 million for unit-based compensation related to
restricted units issued in connection with the IPO and unit options
issued for performance. The increase in general and administrative expenses was also due to our rapidly growing
operations and increasing our staffing level to
manage the additional wells acquired and drilled in 2006 and 2005, as
well as to perform the functions
associated with being a public company. General and administrative expenses per Mcfe of production
were as follows:
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended |
|
|
Percentage |
|
|
|
March 31, |
|
|
Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
General and administrative expenses per Mcfe |
|
$ |
0.97 |
(1) |
|
$ |
0.49 |
|
|
|
98 |
% |
(1) See
note (1) on page 18.
Depreciation,
depletion and amortization increased to $3.7 million for the three months ended March
31, 2006 from $1.2 million for the three months ended March 31, 2005, due to the increase in the
number of wells as a result of the three acquisitions completed in
2005 and the drilling of 29
wells during the three months ended March 31, 2006 and 110 wells in 2005.
Interest and financing income (expense) was $(2.6) million for the three months ended March 31,
2006 compared to $20,000 for the three months ended March 31, 2005. Our interest rate swaps were
not specifically designated as hedges under SFAS No. 133, even though they reduce our exposure to
changes in interest rates. Therefore, the mark to market of these instruments was recorded as a
$0.4 million gain and a $1.0 million gain in our current earnings for the three months ended March
31, 2006 and 2005, respectively. Further, these amounts represent non-cash charges. Cash payments
for interest expense increased to $3.3 million for the three months ended March 31, 2006 from $1.2
million for the three months ended March 31, 2005, primarily due to increased debt levels associated with
the three acquisitions completed in 2005 and the drilling of 29 wells during the three months ended
March 31, 2006 and 110 wells in 2005.
Income tax expense was approximately $119,000 for the three months ended March 31, 2006 compared to
$0 for the three months ended March 31, 2005. Because we were structured as a limited liability
company through May 31, 2005, no tax provision was recorded because all of our taxable income or
loss was included in the income tax returns of the members. On June 1, 2005, Linn Operating, LLC
(predecessor to Linn Operating, Inc.) converted to subchapter C-corporation status and on November
1, 2005 Mid Atlantic Well Service, Inc., one of our subsidiaries, commenced operations. Income tax
expense relates to the income attributable to those entities.
Deferred tax benefits arising from net operating losses have been
offset by an increase in the valuation allowance.
Liquidity and Capital Resources
Sales and Issuances of Securities. In the first quarter of 2006, we completed our initial public
offering of an aggregate of 12,450,000 units representing limited liability company interests
(consisting of 11,750,000 units purchased by the underwriters on January 19, 2006 and 700,000 units
purchased by the underwriters on February 15, 2006 pursuant to their option to purchase additional
units) at an initial public offering price of $21.00 per unit in a firm commitment underwritten
initial public offering pursuant to an S-1 Registration Statement (File No. 333-125501) declared
effective by the Securities and Exchange Commission on January 12, 2006. RBC Capital Markets
Corporation and Lehman Brothers Inc. acted as joint lead-managing underwriters of the offering.
The aggregate initial public offering price for the units issued in our initial public offering was
approximately $261.4 million. Net proceeds to the Company (after underwriting discounts of
approximately $18.3 million and estimated offering expenses of approximately $4.3 million) were
approximately $238.8 million, of which $122.0 million was used to reduce the Companys then-existing
indebtedness, an aggregate of $111.6 million was used to redeem a portion of the limited liability
company membership interests and units held by certain affiliates, and an aggregate of $2.8 million
was used to redeem a portion of the limited liability company interests and units held by certain
non-affiliates of the Company.
Subsequent
to March 31, 2006, the Companys Board of Directors
declared distributions of $0.32 per unit with respect to the first
quarter of 2006 pro-rated for the period from the closing of the
offering on January 19, 2006 to March 31, 2006. As a
result, the Company paid aggregate distributions of approximately $8.9 million on May 15, 2006.
Management currently anticipates that it will recommend to the Board of Directors an increase in
the annualized cash distribution of $0.12 per unit, or a 7.5% increase, to an annual rate of $1.72
per unit from the current annual rate of $1.60 per unit beginning with the cash distribution
expected to be paid on or about November 14, 2006 with respect to the third fiscal quarter.
Credit Facility. On April 7, 2006, we entered into a new $400.0 million Amended and Restated
Credit Agreement (the Credit Agreement) with BNP Paribas, as administrative agent, Royal Bank of
Canada and Societe Generale, as syndication agents, Bank of America, N.A. and Comerica Bank, as
documentation agents, and Bank of Scotland, Fortis Capital Corp. and Lehman commercial Paper Inc.
The Credit Agreement matures on April 13, 2009. The amount available for borrowing at any one time
is limited to the borrowing base, which as a result of this new
arrangement increased from $225.0 million to $235.0 million. The
borrowing base further increased to $265.0 million in June 2006.
The borrowing base will be redetermined semi-annually by the lenders in their sole discretion,
based on, among other things, reserve reports as prepared by reserve engineers taking into account
the natural gas and oil prices at such time. Our obligations under the Credit Agreement are
secured by mortgages on our natural gas and oil properties as well as a pledge of all ownership
interests in our operating subsidiaries. We are required to maintain the mortgages on properties
representing at least 80% of our natural gas and oil properties. Additionally, the obligations
under the Credit Agreement are guaranteed by all of our operating subsidiaries and may be
guaranteed by any future subsidiaries.
20
Borrowings under the Credit Agreement are available for acquisition and development of natural gas
and oil properties, working capital, and general corporate purposes. At our election, interest is
determined by reference to LIBOR plus an applicable margin between 1.00% and 1.75% per annum; or a
domestic bank rate plus an applicable margin between 0% and .25% per annum.
As of
June 21, 2006 we had outstanding indebtedness of $193.6 million under the credit facility and
additional borrowing ability of $71.4 million.
Off Balance Sheet Arrangements
The Company did not have any off-balance sheet arrangements as of March 31, 2006.
21
NON-GAAP FINANCIAL MEASURE
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss) plus:
|
|
|
Interest expense; |
|
|
|
|
Depreciation, depletion and amortization; |
|
|
|
|
Write-off of deferred financing fees; |
|
|
|
|
(Gain) loss on sale of assets; |
|
|
|
|
(Gain) loss from equity investment; |
|
|
|
|
Accretion of asset retirement obligation; |
|
|
|
|
Unrealized (gain) loss on natural gas derivatives; |
|
|
|
|
Realized (gain) loss on cancelled natural gas derivatives; |
|
|
|
|
Unit-based compensation expense; |
|
|
|
|
IPO bonuses; and |
|
|
|
|
Income tax provision. |
The costs of cancelling natural gas swaps before their original settlement date are the only
adjustments to Adjusted EBITDA that require expenditure of cash. These costs were financed with
borrowings under our credit facility, and such long term debt is recognized as an increase in cash
from financing activities.
Adjusted EBITDA is a significant performance metric used by our management to indicate (prior
to the establishment of any reserves by our Board of Directors) the cash distributions we expect to
pay our unitholders. Adjusted EBITDA is also a quantitative standard used throughout the investment
community with respect to publicly-traded partnerships and limited liability companies.
The following table presents a reconciliation of our consolidated net income (loss) to
Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(Unaudited) |
|
|
|
(in
thousands) |
|
Net income (loss) |
|
$ |
21,977 |
|
|
$ |
(12,399 |
) |
Plus: |
|
|
|
|
|
|
|
|
Interest expense |
|
|
2,639 |
|
|
|
(20 |
) |
Depreciation, depletion and amortization |
|
|
3,700 |
|
|
|
1,181 |
|
Write-off of deferred financing fees |
|
|
374 |
|
|
|
|
|
Loss on sale of assets |
|
|
18 |
|
|
|
22 |
|
Loss from equity investment |
|
|
|
|
|
|
10 |
|
Accretion of asset retirement obligation |
|
|
58 |
|
|
|
25 |
|
Unrealized (gain) loss on natural gas derivatives |
|
|
(20,923 |
) |
|
|
6,580 |
|
Realized (gain) loss on cancelled natural gas
derivatives(1) |
|
|
|
|
|
|
7,977 |
|
Unit-based compensation expense |
|
|
5,680 |
|
|
|
|
|
IPO bonuses |
|
|
2,039 |
|
|
|
|
|
Income tax provision(2) |
|
|
119 |
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
15,681 |
|
|
$ |
3,376 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the three months ended March 31, 2005, we cancelled (before their original settlement date) a portion of
out-of-the-money natural gas swaps and realized a loss of $8.0 million. We subsequently hedged
similar volumes at higher prices. |
|
(2) |
|
Linn Operating, LLC was not subject to federal income tax
before converting to a subchapter C-corporation on June 1, 2005. Prior to the conversion, there was no tax provision included in
our consolidated financial statements because all of our taxable income or loss was included
in the income tax returns of the individual members. |
22
Cautionary Statement
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of
federal securities laws that are subject to a number of risks and uncertainties, many of which are
beyond our control. These statements may include statements about our:
|
|
|
business strategy; |
|
|
|
|
financial strategy; |
|
|
|
|
drilling locations; |
|
|
|
|
natural gas and oil reserves; |
|
|
|
|
realized natural gas and oil prices; |
|
|
|
|
production volumes; |
|
|
|
|
lease operating expenses, general and administrative expenses and finding and development costs; |
|
|
|
|
future operating results; and |
|
|
|
|
plans, objectives, expectations and intentions. |
All of these types of statements, other than statements of historical fact included in this
Quarterly Report on Form 10-Q, are forward looking statements. These forward-looking statements may
be found in Item 2. In some cases, you can identify forward-looking statements by terminology such
as may, will, could, should, expect, plan, project, intend, anticipate,
believe, estimate, predict, potential, pursue, target, continue, the negative of such
terms or other comparable terminology.
The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on
our expectations, which reflect estimates and assumptions made by our management. These estimates
and assumptions reflect our best judgment based on currently known market conditions and other
factors. Although we believe such estimates to be reasonable, they are inherently uncertain and
involve a number of risks and uncertainties beyond our control. In addition, managements
assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in
this Quarterly Report on Form 10-Q are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not
occur. Actual results may differ materially from those anticipated or implied in forward looking
statements due to factors listed in the Risk Factors section of our Annual Report on Form 10-K
and throughout this Quarterly Report of Form 10-Q. These forward-looking statements speak only as
of the date made, and other than as required by law, we undertake no obligation to publicly update
or revise any forward-looking statement, whether as a result of new information, future events or
otherwise.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and
qualitative information about our potential exposure to market risks. The term market risk refers
to the risk of loss arising from adverse changes in natural gas prices and interest rates. The
disclosures are not meant to be precise indicators of expected future losses, but rather indicators
of reasonably possible losses. This forward-looking information provides indicators of how we view
and manage our ongoing market risk exposures. All of our market risk sensitive instruments were
entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our natural gas production. Realized
pricing is primarily driven by the spot market prices applicable to our natural gas production and
the prevailing price for crude oil. Pricing for 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.
23
We periodically have entered into and anticipate entering into hedging arrangements with respect to
a portion of our projected natural gas production through various transactions that hedge the
future prices received. These transactions may include price swaps whereby we will receive a fixed
price for our production and pay a variable market price to the contract counterparty. At the
settlement date, we receive the excess, if any, of the fixed floor over the floating rate.
Additionally, we have put options for which we pay the counterparty the fair value at the purchase
date. These hedging activities are intended to support natural gas prices at targeted levels and to
manage our exposure to natural gas price fluctuations. We do not hold or issue derivative
instruments for speculative trading purposes.
Based on natural gas prices as of March 31, 2006, the fair value of our hedges which settle during
the next twelve months was an asset of $7.5 million and a liability of $4.9 for a net asset of $2.6
million, which we are owed from the counterparty. A 10% increase in the index natural gas price
above the March 31, 2006 price for the next twelve months would result in a change of $5.7 million
for a liability of $3.1 million; conversely, a 10% decrease in the index natural gas price would
increase the asset by approximately $5.7 million.
Our hedges for 2006 through 2009 are summarized in the table presented above under Item 2,
Managements Discussion and Analysis of Financial Condition and Results of Operations Cash Flow
from Operations in this Quarterly Report on Form 10-Q.
Interest Rate Risks
At March 31, 2006, we had debt outstanding of $158.0 million, which incurred interest at floating
rates in accordance with our revolving credit facility. As of March 31, 2006, the one-month LIBOR
was approximately 4.8%. A 1% increase in LIBOR as of March 31, 2006 would result in an estimated
$1.6 million increase in annual interest expense.
In 2003, we entered into two interest rate swap agreements to minimize the effect of fluctuation in
interest rates. The agreements have a notional amount of $30.0 million each. One of the interest
rate swap agreements settled quarterly in 2005 and the second settles quarterly in 2006, and we are
required to pay a rate of 3.2% and 4.3%, respectively, while receiving a floating rate. In 2004, we
entered into two additional interest rate swap agreements with a notional amount of $50.0 million
each. These interest rate swap agreements settle quarterly in 2007 and 2008, and we are required to
pay a rate of 5.2% and 5.7%, respectively, while receiving a floating rate. In 2005, in connection
with entering into a new credit facility, we transferred these four interest rate swap agreements
to a different third party financial institution. As a consequence of the transfer of these four
agreements, the fixed interest rate we pay on each agreement increased by seven basis points.
Also in 2004, we entered into two additional interest rate swap agreements with a notional amount
of $20.0 million each. One of the agreements settled quarterly in 2005 and the second settles
quarterly in 2006. We are required to pay a rate of 3.1% and 4.4%, respectively, while receiving a
floating rate.
A 1% change in LIBOR as of March 31, 2006 would result in an estimated $1.5 million change in 2006
interest expense associated with our interest swap agreements.
Under the terms of the swap agreements, we receive quarterly interest payments at the three month
LIBOR rate.
We did not specifically designate the interest rate swap agreements we entered into as hedges under
SFAS No. 133, even though they protect us from changes in interest rates. Therefore, the mark to
market of these instruments was recorded in our current earnings. Further, these amounts represent
non-cash charges.
Item 4. Controls and Procedures.
(a) Evaluation of disclosure controls and procedures
The Company maintains disclosure controls and procedures that are designed to ensure that
information required to be disclosed in the Companys reports under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the SECs rules and forms,
and that such information is accumulated and communicated to management, including the Companys
Chief Executive Officer and Chief Financial Officer, and the Companys Audit Committee, as
appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating
the disclosure controls and procedures, management recognizes that any controls and procedures, no
matter how well designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and management is required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
24
In connection with the preparation of the Companys Annual Report on Form 10-K for the year ended
December 31, 2005 (2005 10-K), an evaluation was performed under the supervision and with the
participation of the Companys management, including the Chief Executive Officer and the Chief
Financial Officer, of the effectiveness of the design and operation of the Companys disclosure
controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act). The
Company concluded that the disclosure controls and procedures were not effective as of December 31, 2005.
We carried out an evaluation under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our
disclosure controls and procedures as of the end of the period covered by this report. Based on the
evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of
March 31, 2006, the Companys disclosure controls and procedures were not effective as a result of
the previously identified material weaknesses. As reported in the 2005 10-K, management is in the
process of taking remedial steps to correct the weaknesses.
Material weaknesses in internal control. Specifically, the Company lacked (i) personnel with
sufficient technical accounting and financial reporting expertise, (ii) adequate review controls
over account reconciliations and account analyses, (iii) policies and procedures in place to
determine and document the appropriate application of accounting principles and (iv) policies and
procedures requiring a detailed and comprehensive review of the underlying information supporting
the amounts included in the annual and interim consolidated financial statements and disclosures.
(b) Changes and Remediation in the Companys Internal Control over Financial Reporting
Remediation activities. During the first quarter of 2006, management identified the above material
weaknesses in our internal control over financial reporting and management has taken and is taking
the following steps to strengthen our internal control over financial reporting:
|
1. |
|
We engaged outside consultants with extensive natural gas and oil financial reporting
experience to augment our current accounting resources to assist with the 2005 10-K, this
quarterly report and future filings. |
|
|
2. |
|
We performed additional analysis and other post closing procedures to enable the
preparation of accurate consolidated financial statements, including all required
disclosures. |
Further as previously reported, we expect to continue to make changes in our internal control over
financial reporting during the periods prior to December 31, 2007 in connection with our Section
404 compliance efforts. As such, we will continue to assess the adequacy of our internal control
over financial reporting, remediate any control weaknesses that may be identified, validate through
testing that controls are functioning as designed and implement a continuous reporting and
improvement process for internal control over financial reporting.
The Company believes the measures taken to date and planned for the future will address the
reported material weakness and intends to complete the remediation efforts during 2006.
Changes in internal control over financial reporting. There have been no changes in our internal
control
over financial reporting (as defined in Rule 13(a) 15(f) under
the Exchange Act) during the three months ended March 31, 2006 that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
25
PART IIOTHER INFORMATION
Item 1. Legal Proceedings.
Not applicable.
Item 1A. Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial
condition, operating results or liquidity and the trading price of our units are described under
Risk Factors in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2005.
This information should be considered carefully, together with other information in this report and
other reports and materials we file with the Securities and Exchange Commission.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not applicable.
Item 3. Defaults Upon Senior Securities
Not applicable.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
Item 5. Other Information
Not applicable.
Item 6. Exhibits
|
|
|
10.1
|
|
Form of Unit Option Agreement pursuant to the Linn Energy, LLC Long-Term Incentive Plan (incorporated
herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Linn Energy, LLC on February
21, 2006) |
|
10.2
|
|
Memorandum of Understanding Regarding Compensation Arrangements for Members of the Linn Energy, LLC Board of
Directors (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Linn
Energy, LLC on February 21, 2006) |
|
10.3
|
|
Employment Agreement, dated effective as of April 3, 2006 between Linn Operating, Inc. and Thomas A. Lopus
(incorporation herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Linn Energy,
LLC on April 18, 2006 ( the April 18, 2006 Form 8-K) |
|
10.4
|
|
Linn Energy, LLC Long-Term Incentive Plan Restricted Unit Agreement, dated effective as of April 13, 2006
between Linn Energy, LLC and Thomas A. Lopus (incorporated herein by reference to Exhibit 10.2 to the April
18, 2006 Form 8-K) |
|
10.5
|
|
Linn Energy, LLC Long-Term Incentive Plan Option Agreement, dated effective as of April 13, 2006 between
Linn Energy, LLC and Thomas A. Lopus (incorporated herein by reference to Exhibit 10.3 to the April 18, 2006
Form 8-K) |
|
10.6
|
|
Separation Agreement and General Release, dated effective as of April 7, 2006 between Linn Energy, LLC and
its subsidiaries and Gerald Merriam (incorporated herein by reference to Exhibit 10.4 to the April 18, 2006
Form 8-K) |
|
10.7
|
|
Separation Agreement and General Release, dated effective as of April 7, 2006 between Linn Energy, LLC and
its subsidiaries and Gerald Merriam (incorporated herein by reference to Exhibit 10.4 to the April 18, 2006
Form 8-K) |
|
10.8
|
|
First Amendment to Amended and Restated Credit Agreement among Linn Energy, LLC as Borrower, BNP Paribas, as
Administrative Agent, and the Lender signatory thereto, effective as of May 5, 2006 (incorporated herein by
reference to Exhibit 10.23 to the Annual Report on Form 10-K filed by Linn Energy, LLC on May 31, 2006) |
|
31.1
|
|
Certification of Michael C. Linn, Chairman, President and Chief Executive Officer of Linn Energy, LLC. |
|
31.2
|
|
Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC. |
|
32.1
|
|
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, of Michael C. Linn, Chairman, President and Chief Executive Officer of Linn
Energy, LLC. |
|
32.2
|
|
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn
Energy, LLC. |
|
|
|
|
|
Management contract or compensatory plan or arrangement. |
26
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, in the City of Pittsburgh, State of Pennsylvania, on
June 30, 2006.
|
|
|
|
|
|
LINN ENERGY, LLC
|
|
|
By: |
/s/ Michael C. Linn
|
|
|
|
Michael C. Linn |
|
|
|
Chairman, President and Chief Executive Officer |
|
|
|
|
|
|
By: |
/s/ Kolja Rockov |
|
|
|
Kolja Rockov |
|
|
|
Executive Vice President and Chief Financial Officer |
|
27