UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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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 September 30, 2009
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: 001-32169
ATLAS ENERGY, INC.
(Exact name of registrant as specified in its charter)
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DELAWARE
(State or other jurisdiction of incorporation or
organization)
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51-0404430
(I.R.S. Employer Identification No.) |
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1550 Coraopolis Heights Road
Moon Township, Pennsylvania
(Address of principal executive office)
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15108
(Zip code) |
Registrants telephone number, including area code:(412) 262-2830
ATLAS AMERICA, INC.
(Former name, Former address and former fiscal year, if changed since last report)
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 has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in rule 12b-2 of the Exchange Act.
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
The number of outstanding shares of the registrants common stock on November 6, 2009 was
78,131,951 shares.
ATLAS ENERGY, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
(Unaudited)
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September 30, |
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December 31, |
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2009 |
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2008 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
35,693 |
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$ |
104,496 |
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Accounts receivable |
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145,548 |
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169,405 |
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Current portion of derivative receivable from Partnerships |
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346 |
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3,022 |
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Current portion of derivative asset |
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88,960 |
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152,726 |
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Prepaid expenses and other |
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27,900 |
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25,464 |
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Prepaid and deferred income taxes |
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881 |
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32,215 |
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Current assets of discontinued operations |
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13,441 |
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Total current assets |
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299,328 |
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500,769 |
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Property, plant and equipment, net |
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3,708,389 |
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3,744,815 |
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Intangible assets, net |
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177,539 |
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197,485 |
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Goodwill, net |
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35,166 |
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35,166 |
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Long-term derivative receivable from Partnerships |
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4,740 |
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2,719 |
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Long term derivative asset |
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42,405 |
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69,451 |
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Investment in joint venture |
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133,740 |
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Other assets, net |
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70,419 |
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53,311 |
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Long-term assets of discontinued operations |
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242,165 |
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$ |
4,471,726 |
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$ |
4,845,881 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Current portion of long-term debt |
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$ |
12,000 |
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$ |
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Accounts payable |
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105,929 |
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140,725 |
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Liabilities associated with drilling contracts |
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16,590 |
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96,883 |
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Accrued producer liabilities |
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45,539 |
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66,846 |
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Current portion of derivative payable to Partnerships |
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23,173 |
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34,933 |
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Current portion of derivative liability |
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46,570 |
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73,776 |
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Accrued liabilities |
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165,391 |
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103,383 |
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Advances from affiliate |
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219 |
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108 |
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Current liabilities of discontinued operations |
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10,572 |
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Total current liabilities |
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415,411 |
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527,226 |
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Long-term debt, less current portion |
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2,115,505 |
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2,413,082 |
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Deferred tax liability |
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51,158 |
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242,058 |
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Long-term derivative payable to Partnerships |
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17,021 |
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22,581 |
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Long-term derivative liability |
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33,847 |
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59,103 |
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Other long-term liabilities |
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54,941 |
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52,263 |
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Commitments and contingencies |
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Stockholders equity: |
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Preferred stock, $0.01 par value: 1,000,000 authorized shares |
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Common stock, $0.01 par value: 114,000,000 authorized shares |
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814 |
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426 |
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Additional paid-in capital |
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1,137,546 |
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412,869 |
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Treasury stock, at cost |
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(143,362 |
) |
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(147,621 |
) |
Accumulated other comprehensive income |
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50,351 |
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21,143 |
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Retained earnings |
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136,027 |
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124,698 |
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1,181,376 |
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411,515 |
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Non-controlling interests |
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602,467 |
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1,118,053 |
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Total stockholders equity |
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1,783,843 |
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1,529,568 |
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$ |
4,471,726 |
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$ |
4,845,881 |
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See accompanying notes to consolidated financial statements
3
ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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Revenues: |
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Well construction and completion |
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$ |
81,496 |
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$ |
116,987 |
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$ |
257,231 |
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$ |
343,466 |
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Gas and oil production |
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65,986 |
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81,235 |
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207,908 |
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236,417 |
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Transmission, gathering and processing |
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205,603 |
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410,942 |
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555,373 |
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1,218,359 |
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Administration and oversight |
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3,149 |
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5,216 |
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9,644 |
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15,370 |
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Well services |
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5,012 |
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5,299 |
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14,911 |
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15,363 |
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Gain on asset sales |
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55 |
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105,746 |
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Gain (loss) on mark-to-market derivatives |
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1,032 |
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147,505 |
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(17,245 |
) |
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(257,344 |
) |
Other, net |
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4,851 |
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3,818 |
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11,696 |
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11,842 |
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Total revenues |
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367,184 |
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771,002 |
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1,145,264 |
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1,583,473 |
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Costs and expenses: |
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Well construction and completion |
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69,138 |
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101,727 |
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218,236 |
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298,666 |
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Gas and oil production |
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12,128 |
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12,688 |
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33,217 |
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35,735 |
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Transmission, gathering and processing |
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167,862 |
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333,988 |
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470,752 |
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992,504 |
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Well services |
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2,378 |
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2,753 |
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6,922 |
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7,815 |
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General and administrative |
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31,786 |
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12,392 |
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80,777 |
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57,903 |
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Net expense reimbursement affiliate |
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280 |
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255 |
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|
842 |
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|
689 |
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Depreciation, depletion and amortization |
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46,460 |
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44,325 |
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147,427 |
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129,539 |
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Total costs and expenses |
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330,032 |
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508,128 |
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958,173 |
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1,522,851 |
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Operating income |
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37,152 |
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262,874 |
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187,091 |
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60,622 |
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Interest Expense |
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(47,754 |
) |
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(37,331 |
) |
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(124,322 |
) |
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(106,538 |
) |
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Income (loss) from continuing operations
before income taxes (benefit) |
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(10,602 |
) |
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225,543 |
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62,769 |
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(45,916 |
) |
Provision (benefit) for income taxes |
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(716 |
) |
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13,647 |
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5,555 |
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12,288 |
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Net income (loss) from continuing operations |
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(9,886 |
) |
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211,896 |
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57,214 |
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(58,204 |
) |
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Discontinued operations: |
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Gain on sale of discontinued operations (net
of income taxes of $2,228 for the nine
months ended September 30, 2009) |
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48,851 |
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Income from discontinued operations (net of
income taxes of $277 for the three months
ended September 30, 2008 and $498 and $848
for the nine months ended September 30, 2009
and 2008, respectively) |
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|
6,261 |
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|
10,918 |
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|
20,181 |
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Net income (loss) |
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(9,886 |
) |
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|
218,157 |
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|
116,983 |
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(38,023 |
) |
(Income) loss attributable to non-controlling
interests |
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|
9,172 |
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(194,054 |
) |
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(103,686 |
) |
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|
60,777 |
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Net income (loss) attributable to common
shareholders |
|
$ |
(714 |
) |
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$ |
24,103 |
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$ |
13,297 |
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$ |
22,754 |
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4
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2009 |
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2008 |
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2009 |
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|
2008 |
|
Net income (loss) attributable to common
shareholders per share basic: |
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Income (loss) from continuing
operations attributable to common
shareholders |
|
$ |
(0.02 |
) |
|
$ |
0.59 |
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$ |
0.23 |
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|
$ |
0.54 |
|
Discontinued operations attributable
to common shareholders |
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|
0.00 |
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|
|
0.01 |
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|
|
0.11 |
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|
0.03 |
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|
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|
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Net income (loss) attributable to
common shareholders |
|
$ |
(0.02 |
) |
|
$ |
0.60 |
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$ |
0.34 |
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$ |
0.57 |
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Net income (loss) attributable to common
shareholders per share diluted: |
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|
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|
Income (loss) from continuing
operations attributable to common
shareholders |
|
$ |
(0.02 |
) |
|
$ |
0.57 |
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|
$ |
0.22 |
|
|
$ |
0.51 |
|
Discontinued operations attributable
to common shareholders |
|
|
0.00 |
|
|
|
0.01 |
|
|
|
0.11 |
|
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|
0.03 |
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|
|
|
|
|
|
|
|
|
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|
Net income (loss) attributable to
common shareholders |
|
$ |
(0.02 |
) |
|
$ |
0.58 |
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|
$ |
0.33 |
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|
$ |
0.54 |
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|
|
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Weighted average common shares outstanding: |
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|
|
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|
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|
|
|
|
|
|
|
|
|
Basic |
|
|
39,780 |
|
|
|
40,093 |
|
|
|
39,460 |
|
|
|
40,251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
39,780 |
|
|
|
41,994 |
|
|
|
40,051 |
|
|
|
42,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) attributable to common
shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
(net of income taxes (benefit) of $(716)
and $13,647 for the three months ended
September 30, 2009 and 2008,
respectively, and $5,555 and $12,288 for
the nine months ended September 30, 2009
and 2008, respectively) |
|
$ |
(714 |
) |
|
$ |
23,670 |
|
|
$ |
9,044 |
|
|
$ |
21,431 |
|
Discontinued operations (net of income
taxes of $277 for the three months ended
September 30, 2008, and $2,726 and $848
for the nine months ended September 30,
2009 and 2008, respectively) |
|
|
|
|
|
|
433 |
|
|
|
4,253 |
|
|
|
1,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common
shareholders |
|
$ |
(714 |
) |
|
$ |
24,103 |
|
|
$ |
13,297 |
|
|
$ |
22,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
5
ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(in thousands, except share data)
(Unaudited)
|
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Accumulated |
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Additional |
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|
|
Other |
|
|
|
|
|
|
Non- |
|
|
Total |
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Treasury Stock |
|
|
Comprehensive |
|
|
Retained |
|
|
controlling |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Shares |
|
|
Amount |
|
|
Income |
|
|
Earnings |
|
|
Interests |
|
|
Equity |
|
Balance at January 1, 2009 |
|
|
42,503,119 |
|
|
$ |
426 |
|
|
$ |
412,869 |
|
|
|
(3,252,861 |
) |
|
$ |
(147,621 |
) |
|
$ |
21,143 |
|
|
$ |
124,698 |
|
|
$ |
1,118,053 |
|
|
$ |
1,529,568 |
|
Common stock issuance |
|
|
24,425 |
|
|
|
|
|
|
|
(2,684 |
) |
|
|
98,829 |
|
|
|
4,259 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,575 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,208 |
|
|
|
|
|
|
|
(14,230 |
) |
|
|
14,978 |
|
Stock option and unit
compensation expense |
|
|
(40,600 |
) |
|
|
|
|
|
|
2,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,550 |
|
Merger with Atlas Energy
Resources LLC |
|
|
38,776,768 |
|
|
|
388 |
|
|
|
724,811 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(556,384 |
) |
|
|
168,815 |
|
Dividends paid |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,968 |
) |
|
|
|
|
|
|
(1,968 |
) |
Distributions to
non-controlling interests |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43,799 |
) |
|
|
(43,799 |
) |
Non-controlling interests
capital contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,859 |
) |
|
|
(4,859 |
) |
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,297 |
|
|
|
103,686 |
|
|
|
116,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2009 |
|
|
81,263,712 |
|
|
$ |
814 |
|
|
$ |
1,137,546 |
|
|
|
(3,154,032 |
) |
|
$ |
(143,362 |
) |
|
$ |
50,351 |
|
|
$ |
136,027 |
|
|
$ |
602,467 |
|
|
$ |
1,783,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
6
ATLAS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
116,983 |
|
|
$ |
(38,023 |
) |
Income from discontinued operations |
|
|
59,769 |
|
|
|
20,181 |
|
|
|
|
|
|
|
|
Income (loss) from continuing operations |
|
|
57,214 |
|
|
|
(58,204 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
147,427 |
|
|
|
129,539 |
|
Amortization of deferred finance costs |
|
|
9,439 |
|
|
|
5,925 |
|
Non-cash loss (gain) on derivative value, net |
|
|
55,229 |
|
|
|
(45,872 |
) |
Non-cash compensation expense (benefit) |
|
|
6,662 |
|
|
|
(4,132 |
) |
Gain on asset sales and dispositions |
|
|
(105,442 |
) |
|
|
(32 |
) |
Distributions paid to non-controlling interests |
|
|
(43,799 |
) |
|
|
(177,934 |
) |
Equity loss in unconsolidated companies |
|
|
2,903 |
|
|
|
688 |
|
Equity income in joint venture |
|
|
(2,140 |
) |
|
|
|
|
Distributions received from joint venture |
|
|
1,657 |
|
|
|
|
|
Deferred income taxes |
|
|
1,185 |
|
|
|
15,621 |
|
Changes in operating assets and liabilities, net of effects of
acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable and prepaid expenses and other |
|
|
22,816 |
|
|
|
(3,817 |
) |
Accounts payable and accrued liabilities |
|
|
(43,322 |
) |
|
|
(40,621 |
) |
Accounts payable and accounts receivable affiliate |
|
|
111 |
|
|
|
47 |
|
Other operating assets/liabilities |
|
|
(161 |
) |
|
|
29 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations operating
activities |
|
|
109,779 |
|
|
|
(178,763 |
) |
Net cash provided by discontinued operations operating activities |
|
|
14,209 |
|
|
|
36,626 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
123,988 |
|
|
|
(142,137 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(268,395 |
) |
|
|
(448,738 |
) |
Acquisition purchase price adjustment |
|
|
|
|
|
|
31,429 |
|
Investment in Lightfoot Capital Partners, L.P. |
|
|
(26 |
) |
|
|
(437 |
) |
Proceeds from asset sales |
|
|
120,644 |
|
|
|
63 |
|
Other |
|
|
(9,003 |
) |
|
|
851 |
|
|
|
|
|
|
|
|
Net cash used in continuing operations investing activities |
|
|
(156,780 |
) |
|
|
(416,832 |
) |
Net cash provided by (used in) discontinued operations investing
activities |
|
|
290,594 |
|
|
|
(22,626 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
133,814 |
|
|
|
(439,458 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Borrowings under Atlas Energy Resources, LLC, Atlas Pipeline
Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities |
|
|
744,000 |
|
|
|
908,000 |
|
Repayments under Atlas Energy Resources, LLC, Atlas Pipeline
Partners, L.P. and Atlas Pipeline Holdings, L.P. credit facilities |
|
|
(1,235,675 |
) |
|
|
(1,110,025 |
) |
Issuance of Atlas Energy Resources, LLC long-term debt |
|
|
196,232 |
|
|
|
407,125 |
|
Issuance of Atlas Pipeline Partners, L.P. long-term debt |
|
|
|
|
|
|
244,854 |
|
Repayments on Atlas Pipeline Partners, L.P. long-term debt |
|
|
|
|
|
|
(122,847 |
) |
Costs related to Atlas Energy, Inc. and Atlas Energy Resources, LLC
Merger |
|
|
(10,571 |
) |
|
|
|
|
Net proceeds from Atlas Energy Resources equity offering |
|
|
|
|
|
|
82,514 |
|
Net proceeds from Atlas Pipeline Partners, L.P. equity offering |
|
|
16,142 |
|
|
|
206,901 |
|
7
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
Dividends paid |
|
|
(1,968 |
) |
|
|
(4,701 |
) |
APL Class A preferred unit redemption |
|
|
(15,000 |
) |
|
|
|
|
Purchase of treasury stock |
|
|
(2,643 |
) |
|
|
(34,861 |
) |
Deferred financing costs and other |
|
|
(17,122 |
) |
|
|
(16,030 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(326,605 |
) |
|
|
560,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
|
(68,803 |
) |
|
|
(20,665 |
) |
Cash and cash equivalents, beginning of period |
|
|
104,496 |
|
|
|
145,896 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
35,693 |
|
|
$ |
125,231 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
8
ATLAS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
NOTE 1 BASIS OF PRESENTATION
Atlas Energy, Inc. (the Company) is a publicly traded Delaware corporation (NASDAQ:ATLS)
which is an independent developer and producer of natural gas and oil, with operations in the
Appalachian Basin, the Michigan Basin, and the Illinois Basin. On September 29, 2009, the Company
completed its merger with Atlas Energy Resources, LLC (ATN), the Companys formerly publicly
traded subsidiary and a Delaware limited liability company (NYSE: ATN), pursuant to the definitive
merger agreement previously executed between the Company and ATN, with ATN surviving as the
Companys wholly-owned subsidiary (the Merger) (see Note 3). Additionally, Atlas America, Inc.
changed its name to Atlas Energy, Inc. upon completion of the Merger.
In addition to its natural gas development and production operations, the Company also
maintains ownership interests in the following entities:
|
|
|
Atlas Pipeline Partners, L.P. (Atlas Pipeline Partners or APL), a publicly traded
Delaware limited partnership (NYSE: APL) and midstream energy service provider engaged in
the transmission, gathering and processing of natural gas in the Mid-Continent and
Appalachia regions. At September 30, 2009, the Company had a 2.2% direct ownership
interest in APL; |
|
|
|
Atlas Pipeline Holdings, L.P. (Atlas Pipeline Holdings or AHD), a publicly traded
Delaware limited partnership (NYSE: AHD) and owner of the general partner of APL.
Through the Companys ownership of AHDs general partner, it manages AHD. AHDs cash
generating assets currently consist solely of its interests in APL. At September 30,
2009, the Company owned approximately 64.4% of the outstanding common units of AHD. AHD
owned a 2% general partner interest, all of the incentive distribution rights, an
approximate 11.2% common limited partner interest, and 15,000 $1,000 par value 12.0%
Class B cumulative preferred limited partner units in APL; and |
|
|
|
Lightfoot Capital Partners, LP (Lightfoot LP) and Lightfoot Capital Partners GP LLC,
(Lightfoot GP), the general partner of Lightfoot (collectively, Lightfoot), entities
which incubate new master limited partnerships (MLPs) and invest in existing MLPs. The
Company has an approximate direct and indirect 18% ownership interest in Lightfoot GP and
a commitment to invest a total of $20.0 million in Lightfoot LP. The Company also has
direct and indirect ownership interest in Lightfoot LP. As of September 30, 2009, the
Company has invested $10.7 million in Lightfoot LP. |
The accompanying consolidated financial statements, which are unaudited except that the
balance sheet at December 31, 2008 is derived from audited financial statements, are presented in
accordance with the requirements of Form 10-Q and accounting principles generally accepted in the
United States for interim reporting. They do not include all disclosures normally made in
financial statements contained in Form 10-K. In managements opinion, all adjustments necessary
for a fair presentation of the Companys financial position, results of operations and cash flows
for the periods disclosed have been made. Management has evaluated subsequent events through
November 9, 2009, the date the financial statements were issued. These interim consolidated
financial statements should be read in conjunction with the audited financial statements and notes
thereto presented in the Companys Annual Report on Form 10-K for the year ended December 31, 2008.
Certain amounts in the prior years consolidated financial statements have also been reclassified
to conform to the current year presentation, including $18.8 million of pre-development costs shown
as component of Property, plant, and equipment, net which was previously combined with
9
Liabilities associated with drilling contracts on the Companys consolidated balance sheets at December
31, 2008. On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate
pipeline system (see Note 5). As such, the Company has adjusted its prior period consolidated
financial statements and related footnote disclosures presented within this Form 10-Q to reflect
the amounts related to the operations of the NOARK gas gathering and interstate pipeline system as
discontinued operations. The Companys consolidated financial statements and related footnotes as
of and for the year ended December 31, 2008 contained within its Annual Report on Form 10-K have
been restated to reflect the amounts related to the discontinued operations of the NOARK system
(see Note 5) and Financial Accounting Standards Board issued Accounting Standard Concept
810-10-65-1, Non-controlling Interests in Consolidated Financial Statements (see Note 2).The
results of operations for the three and nine month periods ended September 30, 2009 may not
necessarily be indicative of the results of operations for the full year ending December 31, 2009.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In addition to matters discussed further within this note, a more thorough discussion of the
Companys significant accounting policies is included in its audited consolidated financial
statements and notes thereto in its annual report on Form 10-K for the year ended December 31,
2008.
Principles of Consolidation and Non-controlling Interest
The consolidated financial statements include the accounts of the Company and its
subsidiaries, all of which are wholly-owned at September 30, 2009 except for AHD, which is
controlled by the Company, and APL, which is controlled by AHD. The financial statements of AHD
include its accounts and the accounts of its subsidiaries, all of which are wholly-owned except for
APL. Prior to ATNs merger with the Companys wholly-owned subsidiary on September 29, 2009, ATN
was a controlled subsidiary of the Company but was not wholly-owned (see Note 3). The
non-controlling ownership interests in the net income (loss) of ATN prior to the Merger, AHD and
APL are reflected within non-controlling interests on the Companys consolidated statements of
operations. The non-controlling interests in the assets and liabilities of AHD and APL are
reflected as a component of stockholders equity on the Companys consolidated balance sheets. The
non-controlling interests in the assets and liabilities of ATN are reflected as a component of
stockholders equity on the Companys December 31, 2008 consolidated balance sheet. All material
intercompany transactions have been eliminated.
In accordance with established practice in the oil and gas industry, the Companys financial
statements include its pro-rata share of assets, liabilities, income and lease operating and
general and administrative costs and expenses of the energy partnerships in which the Company has
an interest (the Partnerships). Such interests typically range from 15% to 35%. The Companys
financial statements do not include proportional consolidation of the depletion or impairment
expenses of the Partnerships. Rather, the Company calculates these items specific to its own
economics as further explained under the heading Oil and Gas Properties below.
The Companys consolidated financial statements also include APLs 95% ownership interest in
joint ventures which individually own a 100% ownership interest in the Chaney Dell natural gas
gathering system and processing plants and a 72.8% undivided interest in the Midkiff/Benedum
natural gas gathering system and processing plants. APL consolidates 100% of these joint ventures.
The Company reflects the non-controlling 5% ownership interest in the joint ventures as
non-controlling interests on its statements of operations. The Company also reflects the 5%
ownership interest in the net assets of the joint ventures as non-controlling interests as a
component of stockholders equity on its consolidated balance sheets. The joint ventures have a
$1.9 billion note receivable from the holder of the 5% ownership interest in the joint ventures,
which is reflected within non-controlling interests on the Companys consolidated balance sheets.
10
The Midkiff/Benedum joint venture has a 72.8% undivided joint venture interest in the
Midkiff/Benedum system, of which the remaining 27.2% interest is owned by Pioneer Natural Resources
Company (NYSE: PXD) (Pioneer). Due to the Midkiff/Benedum systems status as an undivided
joint venture, the Midkiff/Benedum joint venture proportionally consolidates its 72.8% ownership
interest in the assets and liabilities and operating results of the Midkiff/Benedum system. On
November 2, 2009, APLs agreement with Pioneer, whereby Pioneer had an option to purchase
additional interest in the Midkiff/Benedum system, expired without Pioneer exercising its option
(see Note 19.)
Use of Estimates
The preparation of the Companys consolidated financial statements in conformity with
accounting principles generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities that exist at the date of the Companys consolidated financial
statements, as well as the reported amounts of revenue and costs and expenses during the reporting
periods. The Companys consolidated financial statements are based on a number of significant
estimates, including the revenue and expense accruals, deferred tax assets and liabilities,
depletion, depreciation and amortization, asset impairments, fair value of derivative instruments,
the probability of forecasted transactions and the allocation of purchase price to the fair value
of assets acquired. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions
as much as 60 days after the month of delivery. Consequently, the most recent two months
financial results were recorded using estimated volumes and contract market prices. Differences
between estimated and actual amounts are recorded in the following months financial results.
Management believes that the operating results presented for the three and nine months ended
September 30, 2009 represent actual results in all material respects (see - Revenue
Recognition accounting policy for further description).
Impairment of Long-Lived Assets
The Company reviews its long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. If it is
determined that an assets estimated future cash flows will not be sufficient to recover its
carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset
to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Companys oil and gas properties is done on a field-by-field basis by
determining if the historical cost of proved properties less the applicable accumulated depletion,
depreciation and amortization and abandonment is less than the estimated expected undiscounted
future cash flows. The expected future cash flows are estimated based on the Companys plans to
continue to produce and develop proved reserves. Expected future cash flow from the sale of
production of reserves is calculated based on estimated future prices. The Company estimates
prices based upon current contracts in place, adjusted for basis differentials and market related
information including published futures prices. The estimated future level of production is based
on assumptions surrounding future prices and costs, field decline rates, market demand and supply
and the economic and regulatory climates. If the carrying value exceeds the expected future cash
flows, an impairment loss is recognized for the difference between the estimated fair market value
(as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process, and the
accuracy of any reserve estimate depends on the quality of available data and the application of
engineering and geological interpretation and judgment. Estimates of economically recoverable
reserves and future net cash flows depend on a number of variable factors and assumptions that are
difficult to predict and may vary considerably from actual results. In particular, the Companys
reserve estimates for its investment in the Partnerships are based on its own assumptions rather
than its proportionate share of the limited partnerships reserves. These assumptions include the
Companys actual capital contributions, an additional carried interest
(generally 7% to 10%), a disproportionate share of salvage value upon plugging of the wells
and lower operating and administrative costs.
11
The Companys lower operating and administrative costs result from the limited partners in
the Partnerships paying to the Company their proportionate share of these expenses plus a profit
margin. These assumptions could result in the Companys calculation of depletion and impairment
being different than its proportionate share of the Partnerships calculations for these items. In
addition, reserve estimates for wells with limited or no production history are less reliable than
those based on actual production. Estimated reserves are often subject to future revisions,
which could be substantial, based on the availability of additional information which could cause
the assumptions to be modified. The Company cannot predict what reserve revisions may be required
in future periods.
The Companys method of calculating its reserves may result in reserve quantities and values
which are greater than those which would be calculated by the Partnerships which the Company
sponsors and owns an interest in but does not control. The Companys reserve quantities include
reserves in excess of its proportionate share of reserves in a partnership which the Company may
be unable to recover due to the Partnership legal structure. The Company may have to pay
additional consideration in the future as a well or Partnership becomes uneconomic under the terms
of the Partnership agreement in order to recover these excess reserves and to acquire any
additional residual interests in the wells held by other Partnership investors. The acquisition of
any well interest from the Partnership by the Company is governed under the Partnership agreement
and must be at fair market value supported by an appraisal of an independent expert selected by
the Company.
Unproved properties are reviewed annually for impairment or whenever events or circumstances
indicate that the carrying amount of an asset may not be recoverable. Impairment charges are
recorded if conditions indicate the Company will not explore the acreage prior to expiration of
the applicable leases or if it is determined that the carrying value of the properties is above
their fair value. There were no impairments of oil and gas properties or unproved properties
recorded by the Company for the three and nine months ended September 30, 2009 and 2008.
Capitalized Interest
The Company and its subsidiaries capitalize interest on borrowed funds related to capital
projects only for periods that activities are in progress to bring these projects to their intended
use. The weighted average rate used to capitalize interest on borrowed funds by the Company in the
aggregate was 8.4% and 5.6% for the three months ended September 30, 2009 and 2008, respectively,
and 7.0% and 5.8% for the nine months ended September 30, 2009 and 2008, respectively. The
aggregate amount of interest capitalized by the Company was $2.2 million and $2.6 million for the
three months ended September 30, 2009 and 2008, respectively, and $7.9 million and $7.3 million for
the nine months ended September 30, 2009 and 2008, respectively.
Intangible Assets
Customer contracts and relationships. APL amortizes intangible assets with finite lives in
connection with natural gas gathering contracts and customer relationships assumed in certain
consummated acquisitions, which APL amortizes over their estimated useful lives. If an intangible
asset has a finite useful life, but the precise length of that life is not known, that intangible
asset must be amortized over the best estimate of its useful life. At a minimum, APL will assess
the useful lives of all intangible assets on an annual basis to determine if adjustments are
required. The estimated useful life for APLs customer contract intangible assets is based upon
the approximate average length of customer contracts in existence and expected renewals at the date
of acquisition. The estimated useful life for APLs customer relationship intangible assets is
based upon the estimated average length of non-contracted customer relationships in existence at
the date of acquisition,
adjusted for APLs managements estimate of whether the individual relationships will continue
in excess or less than the average length.
12
Partnership management, operating contracts and non-compete agreement. The Company has
recorded intangible assets with finite lives in connection with partnership management and
operating contracts acquired through consummated acquisitions. In addition, the Company entered
into a two-year non-compete agreement in connection with the acquisition of its Michigan
operations. The Company amortizes contracts acquired on a declining balance and straight-line
method over their respective estimated useful lives.
The following table reflects the components of intangible assets being amortized at September
30, 2009 and December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
September 30, |
|
|
December 31, |
|
|
Useful Lives |
|
|
|
2009 |
|
|
2008 |
|
|
In Years |
|
Gross Carrying Amount: |
|
|
|
|
|
|
|
|
|
|
|
|
Customer contracts and relationships |
|
$ |
235,382 |
|
|
$ |
235,382 |
|
|
|
7 - 20 |
|
Partnership management and operating contracts |
|
|
14,343 |
|
|
|
14,343 |
|
|
|
2 - 13 |
|
Non-compete agreement |
|
|
890 |
|
|
|
890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
250,615 |
|
|
$ |
250,615 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
Customer contracts and relationships |
|
$ |
(60,902 |
) |
|
$ |
(41,735 |
) |
|
|
|
|
Partnership management and operating contracts |
|
|
(11,284 |
) |
|
|
(10,728 |
) |
|
|
|
|
Non-compete agreement |
|
|
(890 |
) |
|
|
(667 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(73,076 |
) |
|
$ |
(53,130 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Carrying Amount: |
|
|
|
|
|
|
|
|
|
|
|
|
Customer contracts and relationships |
|
$ |
174,480 |
|
|
$ |
193,647 |
|
|
|
|
|
Partnership management and operating contracts |
|
|
3,059 |
|
|
|
3,615 |
|
|
|
|
|
Non-compete agreement |
|
|
|
|
|
|
223 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
177,539 |
|
|
$ |
197,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization expense on intangible assets was $6.6 million and $6.7 million for the three
months ended September 30, 2009 and 2008, respectively, and $19.9 million and $20.1 million for the
nine months ended September 30, 2009 and 2008, respectively. Aggregate estimated annual
amortization expense for all of the contracts described above for the next five years ending
December 31 is as follows: 2010-$26.3 million; 2011-$26.2 million; 2012-$25.7 million; 2013-$24.6
million; and 2014-$20.6 million.
Goodwill
At September 30, 2009 and December 31, 2008, the Company had $35.2 million of goodwill
recorded in connection with consummated acquisitions. The changes in the carrying amount of
goodwill for the nine months ended September 30, 2009 and 2008 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
Balance, beginning of period |
|
$ |
35,166 |
|
|
$ |
744,449 |
|
APL post-closing purchase price adjustment
with seller and purchase price allocation
adjustment Chaney Dell and Midkiff/Benedum
systems acquisition |
|
|
|
|
|
|
(2,217 |
) |
APL recovery of state sales tax initially
paid on transaction Chaney Dell and
Midkiff/Benedum systems acquisition |
|
|
|
|
|
|
(30,206 |
) |
|
|
|
|
|
|
|
Balance, end of period |
|
$ |
35,166 |
|
|
$ |
712,026 |
|
|
|
|
|
|
|
|
13
As a result of its impairment evaluation at December 31, 2008, the Company recognized a $676.9
million non-cash impairment charge within its consolidated statements of operations for the year
ended December 31, 2008. The goodwill impairment resulted from the reduction in APLs estimated
fair value of its reporting units in comparison to their carrying amounts at December 31, 2008.
APLs estimated fair value of its reporting units was impacted by many factors, including the
significant deterioration of commodity prices and global economic conditions during the fourth
quarter of 2008. These estimates were subjective and based upon numerous assumptions about future
operations and market conditions. There were no goodwill impairments recognized by the Company
related to ATN during the year ended December 31, 2008 and for the period ended September 30, 2009.
The Company tests its goodwill for impairment at each year end by comparing its reporting unit
estimated fair values to carrying values. Because quoted market prices for its reporting units are
not available, the Companys management must apply judgment in determining the estimated fair value
of these reporting units. The Companys management uses all available information to make these
fair value determinations, including the present values of expected future cash flows using
discount rates commensurate with the risks involved in the assets. A key component of these fair
value determinations is a reconciliation of the sum of the fair value calculations to the Companys
market capitalization. The observed market prices of individual trades of an entitys equity
securities (and thus its computed market capitalization) may not be representative of the fair
value of the entity as a whole. Substantial value may arise from the ability to take advantage of
synergies and other benefits that flow from control over another entity. Consequently, measuring
the fair value of a collection of assets and liabilities that operate together in a controlled
entity is different from measuring the fair value of that entity on a stand-alone basis. In most
industries, including the Companys, an acquiring entity typically is willing to pay more for
equity securities that give it a controlling interest than an investor would pay for a number of
equity securities representing less than a controlling interest. Therefore, once the above fair
value calculations have been determined, the Company also considers a control premium to the
calculations. This control premium is judgmental and is based on, among other items, observed
acquisitions in the Companys industry. The resultant fair values calculated for the reporting
units are then compared to observable metrics on large mergers and acquisitions in the Companys
industry to determine whether those valuations appear reasonable in managements judgment. The
Company will continue to evaluate goodwill at least annually or when impairment indicators arise.
During the nine months ended September 30, 2009, no impairment indicators arose.
In April 2008, APL received a $30.2 million cash reimbursement for sales tax initially paid on
its transaction to acquire the Chaney Dell and Midkiff/Benedum systems in July 2007. The $30.2
million was initially capitalized as an acquisition cost and allocated to the assets acquired,
including goodwill, based upon their estimated fair values at the date of acquisition. Based upon
the reimbursement of the sales tax paid in April 2008, APL reduced goodwill recognized in
connection with the acquisition at March 31, 2008.
Net Income (Loss) Per Share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted
average number of common stock outstanding during the period. Diluted net income (loss) per share
is calculated by dividing net income (loss) by the sum of the weighted average number of common
stock outstanding and the dilutive effect of potential shares issuable during the period, as
calculated by the treasury stock method. Dilutive potential shares of common stock consist of the
excess of shares issuable under the terms of the Companys stock incentive plan over the number of
such shares that could have been reacquired (at the weighted average market price of shares during
the period) with the proceeds received from the exercise of the stock options (see Note 17). The
following table sets forth the reconciliation of the Companys weighted
average number of common shares used to compute basic net income (loss) per share with those
used to compute diluted net income (loss) per share (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008(1) |
|
|
2009 |
|
|
2008(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares basic |
|
|
39,780 |
|
|
|
40,093 |
|
|
|
39,460 |
|
|
|
40,251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add: effect of dilutive incentive awards |
|
|
|
|
|
|
1,901 |
|
|
|
591 |
|
|
|
1,870 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares
diluted |
|
|
39,780 |
|
|
|
41,994 |
|
|
|
40,051 |
|
|
|
42,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For the three months ended September 30, 2009, approximately 926,000 shares were
excluded from the computation of diluted earnings attributable to common shareholders
because the inclusion of such shares would have been anti-dilutive. |
14
Revenue Recognition
Certain energy activities are conducted by the Company through, and a portion of its revenues
are attributable to, sponsored investment Partnerships. The Company contracts with the Partnerships
to drill partnership wells. The contracts require that the Partnerships must pay the Company the
full contract price upon execution. The income from a drilling contract is recognized as the
services are performed using the percentage of completion method. The contracts are typically
completed between 60 and 180 days. On an uncompleted contract, the Company classifies the
difference between the contract payments it has received and the revenue earned as a current
liability titled Liabilities Associated with Drilling Contracts on the Companys consolidated
balance sheets. The Company recognizes well services revenues at the time the services are
performed. The Company is also entitled to receive management fees according to the respective
partnership agreements and recognizes such fees as income when earned and includes them in
administration and oversight revenues.
The Company generally sells natural gas and crude oil at prevailing market prices. Revenue is
recognized when produced quantities are 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. Revenues from the production of natural gas and crude oil in which the
Company has an interest with other producers are recognized on the basis of the Companys
percentage ownership of working interest and/or overriding royalty. Generally, the Companys sales
contracts are based on pricing provisions that are tied to a market index, with certain adjustments
based on proximity to gathering and transmission lines and the quality of its natural gas.
Atlas Pipeline. APLs revenue primarily consists of the fees earned from its transmission,
gathering and processing operations. Under certain agreements, APL purchases natural gas from
producers and moves it into receipt points on its pipeline systems, and then sells the natural gas,
or produced natural gas liquids (NGLs), if any, off of delivery points on its systems. Under
other agreements, APL transports natural gas across its systems, from receipt to delivery point,
without taking title to the natural gas. Revenue associated with the physical sale of natural gas
is recognized upon physical delivery of the natural gas. In connection with its gathering and
processing operations, APL enters into the following types of contractual relationships with its
producers and shippers:
|
|
|
Fee-Based Contracts. These contracts provide for a set fee for gathering and
processing raw natural gas. APLs revenue is a function of the volume of natural gas that
it gathers and processes and is not directly dependent on the value of the natural gas. |
|
|
|
POP Contracts. These contracts provide for APL to retain a negotiated percentage of
the sale proceeds from residue natural gas and NGLs it gathers and processes, with the
remainder being remitted to the producer. In this situation, APL and the producer are
directly dependent on the volume of the commodity and its value; APL owns a percentage of
that commodity and is directly subject to its market value. |
|
|
|
Keep-Whole Contracts. These contracts require APL, as the processor, to purchase raw
natural gas from the producer at current market rates. Therefore, APL bears the economic
risk (the processing margin risk) that the aggregate proceeds from the sale of the
processed natural gas and NGLs could be less than the amount that it paid for the
unprocessed natural gas. However, because the natural gas purchases contracted under
keep-whole agreements are generally low in liquids content and meet downstream pipeline
specifications without being processed, the natural gas can be bypassed around the
processing plants and delivered directly into downstream pipelines during periods of
margin risk. Therefore, the processing margin risk associated with a portion of APLs
keep-whole contracts is minimized. |
15
The Company accrues unbilled revenue due to timing differences between the delivery of natural
gas, NGLs, crude oil, and condensate and the receipt of a delivery statement. These revenues are
recorded based upon volumetric data from the Companys and APLs records and management estimates
of the related commodity sales and transportation and compression fees which are, in turn, based
upon applicable product prices (see -Use of Estimates accounting policy for further description).
The Company had unbilled revenues at September 30, 2009 and December 31, 2008 of $66.3 million and
$87.4 million, respectively, which are included in accounts receivable within the Companys
consolidated balance sheets.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income and all other changes in the equity of a
business during a period from transactions and other events and circumstances from non-owner
sources that, under accounting principles generally accepted in the United States, have not been
recognized in the calculation of net income. These changes, other than net income, are referred to
as other comprehensive income (loss) and for the Company includes changes in the fair value of
unsettled derivative contracts accounted for as cash flow hedges and post-retirement plan
liabilities (which are presented net of income taxes). The following table sets forth the
calculation of the Companys comprehensive income (loss) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(9,886 |
) |
|
$ |
218,157 |
|
|
$ |
116,983 |
|
|
$ |
(38,023 |
) |
(Income) loss attributable to
non-controlling interests |
|
|
9,172 |
|
|
|
(194,054 |
) |
|
|
(103,686 |
) |
|
|
60,777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to
common shareholders |
|
|
(714 |
) |
|
|
24,103 |
|
|
|
13,297 |
|
|
|
22,754 |
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in fair value of derivative
instruments accounted for as cash
flow hedges, net of (tax) benefit of
($26,351) and ($53,885) for the
three months ended September 30,
2009 and 2008, respectively, and
($39,354) and $9,431 for the six
months ended September 30, 2009 and
2008, respectively |
|
|
(14,761 |
) |
|
|
242,645 |
|
|
|
45,634 |
|
|
|
(111,397 |
) |
Less: reclassification adjustment
for realized losses (gains) in net
income (loss), net of (tax) benefit
of $13,027 and ($5,633) for the
three months ended September 30,
2009 and 2008, respectively, and
$20,722 and ($6,810) for the nine
months ended September 30, 2009 and
2008, respectively |
|
|
(14,050 |
) |
|
|
30,502 |
|
|
|
(30,722 |
) |
|
|
63,398 |
|
Changes in non-controlling interest
related to items in other
comprehensive income (loss) |
|
|
49,653 |
|
|
|
(180,054 |
) |
|
|
14,231 |
|
|
|
44,256 |
|
Plus: amortization of additional
post-retirement liability recorded
upon adoption of SFAS No. 158, net
of (tax) benefit of $13 and $51 for
the three months ended September 30,
2009 and 2008, respectively, and $39
and $153 for the nine months ended
September 30, 2009 and 2008,
respectively |
|
|
22 |
|
|
|
87 |
|
|
|
65 |
|
|
|
296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive (loss) gain |
|
|
20,864 |
|
|
|
93,180 |
|
|
|
29,208 |
|
|
|
(3,447 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
attributable to common shareholders |
|
$ |
20,150 |
|
|
$ |
117,283 |
|
|
$ |
42,505 |
|
|
$ |
19,307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
Recently Adopted Accounting Standards
In August 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update 2009-05, Fair Value Measurements and Disclosures (Topic 820) Measuring Liabilities at
Fair Value (Update 2009-05). Update 2009-05 amends Subtopic 820-10, Fair Value Measurements
and Disclosures Overall and provides clarification for the fair value measurement of liabilities
in circumstances where quoted prices for an identical liability in an active market are not
available. The amendments also provide clarification for not requiring the reporting entity to
include separate inputs or adjustments to other inputs relating to the existence of a restriction
that prevents the transfer of a liability when estimating the fair value of a liability.
Additionally, these amendments clarify that both the quoted price in an active market for an
identical liability at the measurement date and the quoted price for an identical liability when
traded as an asset in an active market when no adjustments to the quoted price of the asset are
required are considered Level 1 fair value measurements. These requirements are effective for
financial statements issued after the release of Update 2009-05. The Company adopted the
requirements on September 30, 2009 and it did not have a material impact on its financial position,
results of operations or related disclosures.
In August 2009, the FASB issued Accounting Standards Update 2009-04, Accounting for
Redeemable Equity Instruments Amendment to Section 480-10-S99 (Update 2009-04). Update
2009-04 updates Section 480-10-S99, Distinguishing Liabilities from Equity, to reflect the SEC
staffs views regarding the application of Accounting Series Release No. 268, Presentation in
Financial Statements of Redeemable Preferred Stocks (ASR No. 268). ASR No. 268 requires
preferred securities that are redeemable for cash or other assets to be classified outside of
permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or
determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that
is not solely within the control of the issuer. The Company adopted the requirements of
FASB Update 2009-04 on August 1, 2009 and it did not have a material impact on its financial
position, results of operations or related disclosures.
In June 2009, the FASB issued Accounting Standards Update 2009-01, Topic 105 Generally
Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards
No. 168 The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles (Update 2009-01). Update 2009-01 establishes the FASB Accounting
Standards Codification (ASC) as the single source of authoritative U.S. generally accepted
accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC
supersedes all existing non-Securities and Exchange Commission accounting and reporting standards.
Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff
Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting
Standards Updates, which will serve only to update the ASC. The ASC is effective for financial
statements issued for interim and annual periods ending after September 15, 2009. All required
references to non-SEC accounting standards have been modified by the Company. The Company
adopted the requirements of Update 2009-01 to its financial statements on September 30, 2009
and it did not have a material impact to the Companys financial statement disclosures.
17
In May 2009, the FASB issued ASC 855-10, Subsequent Events (ASC 855-10). ASC 855-10
establishes general standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or are available to be issued. The
provisions require management of a reporting entity to evaluate events or transactions that may
occur after the balance sheet date for potential recognition or disclosure in the financial
statements and provides guidance for disclosures that an entity should make about those events.
ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and
shall be applied prospectively. The Company adopted the requirements of this standard on June 30,
2009 and it did not have a material impact to its financial position or results of operations or
related disclosures. The adoption of these provisions does not change the Companys current
practices with respect to evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued ASC 820-10-65-4, Determining Fair Value When the Volume and
Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly (ASC 820-10-65-4). ASC 820-10-65-4 applies to all fair value
measurements and provides additional clarification on estimating fair value when the market
activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to
disclose a change in valuation technique and related inputs to the valuation calculation and to
quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods
ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.
The Company adopted the requirements of ASC 820-10-65-4 on April 1, 2009 and its adoption did not
have a material impact on the Companys financial position and results of operations.
In April 2009, the FASB issued ASC 320-10-65-1, Recognition and Presentation of
Other-Than-Temporary Impairments (ASC 320-10-65-1), which changes previously existing guidance
for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1
replaces the previously existing requirement that an entitys management assess if it has both the
intent and ability to hold an impaired security until recovery with a requirement that management
assess that it does not have the intent to sell the security and that it is more likely than not
that it will not have to sell the security before recovery of its cost basis. ASC 320-10-65-1 also
requires that an entity recognize noncredit losses on held-to-maturity debt securities in other
comprehensive income and amortize that amount over the remaining life of the security and for the
entity to present the total other-than-temporary impairment in the statement of operations with an
offset for the amount recognized in other comprehensive income. ASC 320-10-65-1 is effective for
interim and annual periods ending after June 15, 2009, with early adoption permitted for periods
ending after March 15, 2009. The Company adopted these requirements on April 1, 2009 and its
adoption did not have a material impact on the Companys financial position and results of
operations.
In April 2009, the FASB issued ASC 825-10-65-1, Interim Disclosures about Fair Value of
Financial Instruments (ASC 825-10-65-1), which requires an entity to provide disclosures about
fair value of financial instruments in interim financial information. In addition, an entity shall
disclose in the body or in the accompanying notes of its summarized financial information for
interim reporting periods and in its financial statements for annual reporting periods the fair
value of all financial instruments for which it is practicable to estimate that value, whether
recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective
for interim periods ending after June 15, 2009, with early adoption permitted for periods ending
after March 15, 2009. The Company adopted these requirements on April 1, 2009 and its adoption did
not have a material impact on the Companys financial position and results of operations.
In April 2009, the FASB issued ASC 805-20-30-23, Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from Contingencies (ASC 805-20-30-23),
which requires that assets acquired and liabilities assumed in a business combination that arise
from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair
value of such an asset or liability cannot be reasonably estimated, the asset or liability would
generally be recognized in accordance with
previous requirements. ASC 805-20-30-23 eliminates the requirement to disclose an estimate of
the range of outcomes of recognized contingencies at the acquisition date. ASC 805-20-30-23 is
effective for business combinations for which the acquisition date is on or after the beginning of
the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the
Company). The Company adopted the requirements on January 1, 2009 and its adoption did not have a
material impact on the Companys financial position and results of operations.
18
In June 2008, the FASB issued ASC 260-10-45-61A, Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities (ASC 260-10-45-61A). ASC
260-10-45-61A applies to the calculation of earnings per share (EPS) described in previous
guidance, for share-based payment awards with rights to dividends or dividend equivalents. It
states that unvested share-based payment awards that contain non-forfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are participating securities and shall be included in
the computation of EPS pursuant to the two-class method. ASC 260-10-45-61A is effective for
financial statements issued for fiscal years beginning after December 15, 2008, and interim periods
within those fiscal years. Early adoption was prohibited. The Company adopted the requirements on
January 1, 2009 and its adoption did not have a material impact on the Companys financial position
and results of operations.
In April 2008, the FASB issued ASC 350-30-65-1, Determination of Useful Life of Intangible
Assets (ASC 350-30-65-1). ASC 350-30-65-1 amends the factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of a recognized
intangible asset under previous guidance. The intent of ASC 350-30-65-1 is to improve the
consistency between the useful life of a recognized intangible asset and the period of expected
cash flows used to measure the fair value of the asset. The Company adopted the requirements of ASC
350-30-65-1 on January 1, 2009 and its adoption did not have a material impact on its financial
position and results of operations.
In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, Application of the Two-Class
Method (ASC 260-10-55-103), which considers whether the incentive distributions of a master
limited partnership represent a participating security when considered in the calculation of
earnings per unit under the two-class method. ASC 260-10-55-103 considers whether the partnership
agreement contains any contractual limitations concerning distributions to the incentive
distribution rights that would impact the amount of earnings to allocate to the incentive
distribution rights for each reporting period. If distributions are contractually limited to the
incentive distribution rights share of currently designated available cash for distributions as
defined under the partnership agreement, undistributed earnings in excess of available cash should
not be allocated to the incentive distribution rights. The Companys adoption of ASC 260-10-55-103
on January 1, 2009 impacted its presentation of net income (loss) per common limited partner unit
as the Company previously presented net income (loss) per common limited partner unit as though all
earnings were distributed each quarterly period (see Net Income (Loss) Per Common Unit). The
Company adopted the requirements of ASC 260-10-55-103 on January 1, 2009 and its adoption did not
have a material impact on the Companys financial position and results of operations.
In March 2008, the FASB issued ASC 815-10-50-1, Disclosures about Derivative Instruments and
Hedging Activities (ASC 815-10-50-1), to require enhanced disclosure about how and why an entity
uses derivative instruments, how derivative instruments and related hedged items are accounted for
and how derivative instruments and related hedged items affect an entitys financial position,
financial performance and cash flows. The Company adopted the requirements of this section of ASC
815-10-50-1 on January 1, 2009 and it did not have a material impact on its financial position or
results of operations (see Note 10).
19
In December 2007, the FASB issued ASC 810-10-65-1, Non-controlling Interests in Consolidated
Financial Statements (ASC 810-10-65-1). ASC 810-10-65-1 establishes accounting and reporting
standards for the non-controlling interest (minority interest) in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity in the consolidated
financial statements. It also requires
consolidated net income to be reported and disclosed on the face of the consolidated statement
of operations at amounts that include the amounts attributable to both the parent and the
non-controlling interest. Additionally, ASC 810-10-65-1 establishes a single method of accounting
for changes in a parents ownership interest in a subsidiary that does not result in
deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is
deconsolidated and adjust its remaining investment, if any, at fair value. The Company adopted the
requirements of ASC 810-10-65-1on January 1, 2009 and adjusted its presentation of its financial
position and results of operations. Prior period financial position and results of operations have
been adjusted retrospectively to conform to these provisions.
In December 2007, the FASB issued ASC 805, Business Combinations (ASC 805). ASC 805
retains the fundamental requirements that the acquisition method of accounting be used for all
business combinations and for an acquirer to be identified for each business combination. ASC 805
requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling
interest in the acquiree at the acquisition date, at their fair values as of that date, with
specified limited exceptions. Additionally, it requires costs incurred in connection with an
acquisition be expensed as incurred. Restructuring costs, if any, are to be recognized separately
from the acquisition. The acquirer in a business combination achieved in stages must also recognize
the identifiable assets and liabilities, as well as the non-controlling interests in the acquiree,
at the full amounts of their fair values. The Company adopted these requirements on January 1, 2009
and it did not have a material impact on its financial position and results of operations.
Recently Issued Accounting Standards
In October 2009, the FASB issued Accounting Standards Update 2009-15, Accounting for
Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing
(Update 2009-15). Update 2009-15 includes amendments to Topic 470, Debt, and Topic 260,
Earnings per Share, to provide guidance on share-lending arrangements entered into on an entitys
own shares in contemplation of a convertible debt offering or other financing. These
requirements are effective for existing arrangements for fiscal years beginning on or after
December 15, 2009, and interim periods within those fiscal years for arrangements outstanding as of
the beginning of those years, with retrospective application required for such arrangements that
meet the criteria. These requirements are also effective for arrangements entered into on (not
outstanding) or after the beginning of the first reporting period that begins on or after June 15,
2009. The Company will apply these requirements upon its adoption on January 1, 2010 and does not
expect it to have a material impact to its financial position or results of operations or related
disclosures.
In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, Consolidation of Variable
Interest Entities (ASC 810-10-25-20), which changes how a reporting entity determines when an
entity that is insufficiently capitalized or is not controlled through voting (or similar rights)
should be consolidated. ASC 820-10-25-20 requires a reporting entity to provide additional
disclosures about its involvement with variable interest entities and any significant changes in
risk exposure due to that involvement. A reporting entity will be required to disclose how its
involvement with a variable interest entity affects the reporting entitys financial statements.
These requirements are effective at the start of a reporting entitys first fiscal year beginning
after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the
impact of these requirements upon its adoption on January 1, 2010.
Modernization of Oil and Gas Reporting
In December 2008, the Securities and Exchange Commission (SEC) announced that it had
approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of
Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are
referred to as Modernization of Oil and Gas Reporting and include provisions that:
|
|
|
Introduce a new definition of oil and gas producing activities. This new
definition allows companies to include in their reserve base volumes from
unconventional resources. Such
unconventional resources include bitumen extracted from oil sands and oil and gas
extracted from coal beds and shale formations.
|
20
|
|
|
Report oil and gas reserves using an unweighted average price using the prior
12-month period, based on the closing prices on the first day of each month, rather
than year-end pricing. This should maximize the comparability of reserve estimates
among companies and mitigate the distortion of the estimates that arises when using
a single pricing date. |
|
|
|
|
Permit companies to disclose their probable and possible reserves on a voluntary
basis. Current rules limit disclosure to only proved reserves. |
|
|
|
|
Update and revise reserve definitions to reflect changes in the oil and gas
industry and new technologies. New updated definitions include by geographic area
and reasonable certainty. |
|
|
|
|
Permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. |
|
|
|
|
Require additional disclosures regarding the qualifications of the chief
technical person who oversees the companys overall reserve estimation process.
Additionally, disclosures are required related to internal controls over reserve
estimation, as well as a report addressing the independence and qualifications of a
companys reserves preparer or auditor based on Society of Petroleum Engineers
criteria. |
The Company will begin complying with the disclosure requirements in its annual report on Form
10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in
quarterly reports prior to the first annual report in which the revised disclosures are required.
The Company is currently in the process of evaluating the new requirements.
NOTE 3 COMMON STOCK
Merger with Atlas Energy Resources, LLC
On September 29, 2009, the Company completed its merger with ATN pursuant to the definitive
merger agreement previously executed between the Company and ATN, with ATN surviving as the
Companys wholly-owned subsidiary. In the Merger, the 33.4 million Class B common units of ATN not
previously held by the Company were exchanged for 38.8 million shares of the Companys common stock
(a ratio of 1.16 shares of the Companys common stock for each Class B common unit of ATN). The
Company also changed its name from Atlas America, Inc. to Atlas Energy, Inc. Concurrent with the
Merger, the Compensation Committee of the Board of Directors approved the Atlas Energy, Inc. 2009
Stock Incentive Plan, which creates a new stock incentive plan for the combined entity. The
Company also has the legacy Atlas America stock incentive plan and the legacy ATN Long-Term
Incentive Plan (see Note 17).
Due to the Merger, the Company recognized a reduction of $556.4 million in non-controlling
interest and a decrease to deferred tax liability of $179.4 million, all of which was reflected as
an increase to additional paid-in-capital on the Companys consolidated balance sheets.
The Company also recognized the fair value of the interests exchanged in the Merger, excluding
transaction costs incurred, of $724.8 million as a non-cash item in its consolidated statement of
cash flows for the nine months ended September 30, 2009.
Authorized Shares
On July 13, 2009, the Companys stockholders approved an increase to its authorized shares
from 49,000,000 authorized shares to 114,000,000 authorized shares.
21
Stock Repurchase Plan
In September 2008, the Companys Board of Directors approved a stock repurchase program of up
to $50.0 million at a price not to exceed $36.00 per share. The daily repurchase amount was
limited to 50,000 shares. The Company purchased 595,292 of its shares during September and October
2008 for a total price of $20.0 million under this program. In addition, the Company utilized the
remaining $20.0 million of availability under a stock repurchase program approved in September 2005
to purchase 560,291 shares in August and September 2008. The average price for the shares
purchased during 2008 was $34.76 per share.
Stock Splits
On April 22, 2008, the Companys Board of Directors approved a three-for-two stock split of
the Companys common stock effected in the form of a 50% stock dividend. All shareholders of
record as of May 21, 2008 received one additional share of common stock for every two shares of
common stock held on that date. The additional shares of common stock were distributed on May 30,
2008. Information pertaining to shares and earnings per share has been restated for the three and
nine months ended September 30, 2008 in the accompanying consolidated financial statements and
notes to the consolidated financial statements to reflect this split.
The following data presents pro forma revenue, net income, net income per share and basic and
diluted weighted average shares outstanding for the Company for the three and nine months ended
September 30, 2009 and 2008, respectively, as if the Merger discussed above had occurred on January
1, 2008. The Company has prepared these unaudited pro forma financial results for comparative
purposes only. The pro forma adjustments reflect an adjustment to income previously allocated to
non-controlling interest offset by the restated tax impact. These pro forma financial results may
not be indicative of the results that would have occurred if the Merger had been completed at the
beginning of the periods shown below or the results that will be attained in the future (in
thousands, except per share data; unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Revenue |
|
$ |
367,184 |
|
|
$ |
771,002 |
|
|
$ |
1,145,264 |
|
|
$ |
1,583,473 |
|
Income attributable to common shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
562 |
|
|
$ |
36,495 |
|
|
$ |
18,591 |
|
|
$ |
59,568 |
|
Discontinued operations |
|
|
|
|
|
|
433 |
|
|
|
4,253 |
|
|
|
1,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common shareholders |
|
$ |
562 |
|
|
$ |
36,928 |
|
|
$ |
22,844 |
|
|
$ |
60,891 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common
shareholders per share basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
attributable to common shareholders |
|
$ |
0.01 |
|
|
$ |
0.46 |
|
|
$ |
0.24 |
|
|
$ |
0.75 |
|
Discontinued operations attributable to
common shareholders |
|
|
0.00 |
|
|
|
0.01 |
|
|
|
0.05 |
|
|
|
0.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common shareholders |
|
$ |
0.01 |
|
|
$ |
0.47 |
|
|
$ |
0.29 |
|
|
$ |
0.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common
shareholders per share diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
attributable to common shareholders |
|
$ |
0.01 |
|
|
$ |
0.44 |
|
|
$ |
0.24 |
|
|
$ |
0.73 |
|
Discontinued operations attributable to
common shareholders |
|
|
0.00 |
|
|
|
0.01 |
|
|
|
0.05 |
|
|
|
0.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common shareholders |
|
$ |
0.01 |
|
|
$ |
0.45 |
|
|
$ |
0.29 |
|
|
$ |
0.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
78,136 |
|
|
|
78,869 |
|
|
|
78,095 |
|
|
|
79,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
79,144 |
|
|
|
81,307 |
|
|
|
78,714 |
|
|
|
81,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
NOTE 4 APL INVESTMENT IN JOINT VENTURE
On May 31, 2009, APL and subsidiaries of The Williams Companies, Inc. (NYSE: WMB)
(Williams) completed the formation of Laurel Mountain Midstream, LLC (Laurel Mountain), a joint
venture which owns and operates APLs Appalachia Basin natural gas gathering system, excluding
APLs Northern Tennessee operations. Williams contributed cash of $100.0 million to the joint
venture (of which APL received approximately $87.8 million, net of working capital adjustments) and
a note receivable of $25.5 million. In addition, ATN sold certain assets to the joint venture for
$12.0 million. APL contributed its Appalachia Basin natural gas gathering system and retained a
49% ownership interest. APL is also entitled to preferred distribution rights relating to all
payments on the note receivable. Williams retained the remaining 51% ownership interest in Laurel
Mountain. Upon completion of the transaction, APL recognized its 49% ownership interest in Laurel
Mountain as an investment in joint venture on the Companys consolidated balance sheet at fair
value and recognized a gain on sale of $108.9 million, including $54.2 million associated with the
re-measurement of APLs investment in Laurel Mountain to fair value. APL used the net proceeds
from the transaction to reduce borrowings under its senior secured credit facility (see Note 9).
In addition, the Company sold two natural gas processing plants and associated pipelines located in
Southwestern Pennsylvania to Laurel Mountain for $10.0 million, resulting in a $5.7 million loss
which is included in gain on asset sale on the Companys consolidated statement of operations.
Upon the completion of the contribution of APLs Appalachia gathering systems to Laurel Mountain,
Laurel Mountain entered into new gas gathering agreements with the Company which superseded the
existing natural gas gathering agreements and omnibus agreement between APL and the Company. Under
the new gas gathering agreement, the Company is obligated to pay the joint venture all of the
gathering fees it collects from its investment drilling partnerships plus any excess amount over
the amount of the competitive gathering fee (which is currently defined as 13% of the gross sales
price received for the Companys investment drilling partnerships gas). APL has accounted for its
ownership interest in Laurel Mountain under the equity method of accounting, with recognition of
its ownership interest in the income of Laurel Mountain other income (loss) on the Companys
consolidated statements of operations.
The following table provides summarized statement of operations and balance sheet data on a
100% basis for Laurel Mountain for the three and nine months ended September 30, 2009 and as of
September 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended |
|
|
Ended |
|
|
|
September 30, 2009 |
|
|
September 30, 2009(1) |
|
Statement of Operations data: |
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
9,622 |
|
|
$ |
12,690 |
|
Net income |
|
|
2,386 |
|
|
|
3,664 |
|
|
|
|
|
|
|
|
September 30, 2009 |
|
Balance Sheet data: |
|
|
|
|
Current assets |
|
$ |
9,871 |
|
Long-term assets |
|
|
245,577 |
|
Current liabilities |
|
|
19,303 |
|
Long-term liabilities |
|
|
8,500 |
|
Net equity |
|
|
227,645 |
|
|
|
|
(1) |
|
Represents the period from May 31, 2009, the date of initial formation,
through September 30, 2009. |
23
NOTE 5 DISCONTINUED OPERATIONS
On May 4, 2009, APL completed the sale of its NOARK gas gathering and interstate pipeline
system to Spectra Energy Partners OLP, LP (NYSE:SEP) (Spectra) for net proceeds of $292.0 million
in cash, net of working capital adjustments. APL received an additional $2.5 million in cash in
July 2009 upon the delivery of audited financial statements for the NOARK system assets to Spectra.
APL used the net proceeds from the transaction to reduce borrowings under its senior secured term
loan and revolving credit facility (see Note 9). The Company accounted for the sale of the NOARK
system assets as discontinued operations within its consolidated financial statements and recorded
a gain of $48.8 million (net of income taxes of $2.2 million) on the sale of APLs NOARK assets
within income from discontinued operations on its consolidated financial statement of operations
for the three and nine months ended September 30, 2009. The following table summarizes the
components included within income from discontinued operations on the Companys consolidated
statements of operations (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Total revenues |
|
$ |
|
|
|
$ |
13,468 |
|
|
$ |
21,274 |
|
|
$ |
45,827 |
|
Total costs and expenses |
|
|
|
|
|
|
(6,930 |
) |
|
|
(9,858 |
) |
|
|
(24,798 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax expense |
|
|
|
|
|
|
6,538 |
|
|
|
11,416 |
|
|
|
21,029 |
|
Income tax expense |
|
|
|
|
|
|
(277 |
) |
|
|
(498 |
) |
|
|
(848 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations |
|
$ |
|
|
|
$ |
6,261 |
|
|
$ |
10,918 |
|
|
$ |
20,181 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components included within total assets and liabilities of
discontinued operations within the Companys consolidated balance sheet for the period indicated
(amounts in thousands):
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
Cash and cash equivalents |
|
$ |
75 |
|
Accounts receivable |
|
|
12,365 |
|
Prepaid expenses and other |
|
|
1,001 |
|
|
|
|
|
Total current assets of discontinued operations |
|
|
13,441 |
|
Property, plant and equipment, net |
|
|
241,926 |
|
Other assets, net |
|
|
239 |
|
|
|
|
|
Total assets of discontinued operations |
|
$ |
255,606 |
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
4,120 |
|
Accrued liabilities |
|
|
5,892 |
|
Accrued producer liabilities |
|
|
560 |
|
|
|
|
|
Total current liabilities of discontinued
operations |
|
$ |
10,572 |
|
|
|
|
|
24
NOTE 6 PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are stated at cost. Depreciation, depletion and amortization
are based on cost less estimated salvage value primarily using the unit-of-production or
straight-line methods over the assets estimated useful life. Maintenance and repairs are expensed
as incurred. Major renewals and improvements that extend the useful lives of property are
capitalized.
The following is a summary of property, plant and equipment (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
September 30, |
|
|
December 31, |
|
|
Useful Lives |
|
|
|
2009 |
|
|
2008(1) |
|
|
in Years |
|
Natural gas and oil properties: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties: |
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold interests |
|
$ |
1,237,331 |
|
|
$ |
1,214,991 |
|
|
|
|
|
Pre-development costs |
|
|
14,750 |
|
|
|
18,772 |
|
|
|
|
|
Wells and related equipment |
|
|
970,063 |
|
|
|
872,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved properties |
|
|
2,222,144 |
|
|
|
2,105,891 |
|
|
|
|
|
Unproved properties |
|
|
43,279 |
|
|
|
43,749 |
|
|
|
|
|
Support equipment |
|
|
8,605 |
|
|
|
9,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and oil properties |
|
|
2,274,028 |
|
|
|
2,159,167 |
|
|
|
|
|
Pipelines, processing and compression facilities |
|
|
1,671,863 |
|
|
|
1,728,472 |
|
|
|
15 - 40 |
|
Rights of way |
|
|
166,874 |
|
|
|
168,206 |
|
|
|
20 - 40 |
|
Land, buildings and improvements |
|
|
24,593 |
|
|
|
24,385 |
|
|
|
10 - 40 |
|
Other |
|
|
21,867 |
|
|
|
22,108 |
|
|
|
3 - 10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,159,225 |
|
|
|
4,102,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less accumulated depreciation, depletion and
amortization |
|
|
(450,836 |
) |
|
|
(357,523 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,708,389 |
|
|
$ |
3,744,815 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale of its NOARK gas
gathering and interstate pipeline system (see Note 5) |
The Company follows the successful efforts method of accounting for oil and gas producing
activities. Acquisition costs of leases and development activities are capitalized. Exploratory
drilling costs are capitalized pending determination of whether a well is successful. Exploratory
wells subsequently determined to be dry holes are charged to expense. Costs resulting in
exploratory discoveries and all development costs, whether successful or not, are capitalized.
Geological and geophysical costs and delay rentals are expensed. Oil is converted to gas equivalent
basis (Mcfe) at the rate one barrel equals 6 thousand cubic feet (Mcf). Depletion is provided
on the units-of-production method.
Depletion, depreciation and amortization expense is determined on a field-by-field basis using
the units-of-production method. Depletion, depreciation and amortization rates for leasehold
acquisition costs based on estimated proved reserves and depletion, depreciation and amortization
rates for well and related equipment costs based on proved developed reserves associated with each
field. Depletion rates are determined based on reserve quantity estimates and the capitalized
costs of undeveloped and developed producing properties. Capitalized costs of developed producing
properties in each field are aggregated to include the Companys costs of property interests in
uncontrolled, but proportionately consolidated from investment partnerships, wells drilled solely
by the Company for its interest, properties purchased and working interests with other outside
operators.
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated
from the property accounts, and the resultant gain or loss is reclassified to income. Upon the
sale of an individual well, the proceeds are credited to accumulated depreciation and depletion.
Upon the sale of an entire interest in an unproved property where the property had been assessed
for impairment individually, a gain or loss is
recognized in the statements of income. If a partial interest in an unproved property is
sold, any funds received are accounted for as a reduction of the cost in the interest retained.
25
On July 13, 2009, APL sold a natural gas processing facility and a one-third undivided
interest in other associated assets located in its Mid-Continent operating segment for
approximately $22.6 million in cash. The facility was sold to Penn Virginia Resource Partners,
L.P. (NYSE: PVR), who will provide natural gas volumes to the facility and reimburse APL for its
proportionate share of the operating expenses. APL will continue to operate the facility. APL
used the proceeds from this transaction to reduce outstanding borrowings under its senior secured
credit facility. APL recognized a gain on sale of $2.5 million, which is recorded within gain on
asset sales on the Companys consolidated statements of operations.
NOTE 7 OTHER ASSETS
The following is a summary of other assets at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008(1) |
|
Deferred finance costs, net of accumulated
amortization of $32,544 and $23,105 at September 30,
2009 and December 31, 2008, respectively |
|
$ |
49,446 |
|
|
$ |
38,871 |
|
Investment in Lightfoot LP, Lightfoot GP and Magnetar LP |
|
|
8,442 |
|
|
|
10,779 |
|
Other investments |
|
|
5,988 |
|
|
|
1,994 |
|
Long-term pipeline lease prepayment |
|
|
2,606 |
|
|
|
|
|
Security deposits |
|
|
3,937 |
|
|
|
1,667 |
|
|
|
|
|
|
|
|
|
|
$ |
70,419 |
|
|
$ |
53,311 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system (see Note 5) |
Deferred finance costs are recorded at cost and amortized over the term of the respective
debt agreement (see Note 9). During the nine months ended September 30, 2009 and 2008, APL
recorded $2.5 million and $1.2 million, respectively, of accelerated amortization of deferred
financing costs associated with the retirement of a portion of its term loan, which is recorded
within interest expense on the Companys consolidated statement of operations.
The Company owns, directly and indirectly, approximately 13% of Lightfoot LP, an entity of
which Jonathan Cohen, Vice Chairman of the Companys Board of Directors, is the Chairman of the
Board. In addition, the Company owns, directly and indirectly, approximately 18% of Lightfoot GP,
the general partner of Lightfoot LP. The Company committed to invest a total of $20.0 million in
Lightfoot LP. The Company has certain co-investment rights until such point as Lightfoot LP raises
additional capital through a private offering to institutional investors or a public offering.
Lightfoot LP has initial equity funding commitments of approximately $160.0 million and focuses its
investments primarily on incubating new master limited partnerships and providing capital to
existing MLPs in need of additional equity or structured debt. Lightfoot LP concentrates on assets
that are MLP-qualified such as infrastructure, coal and other asset categories. The Company
accounts for its investment in Lightfoot under the equity method of accounting. For the nine
months ended September 30, 2009 and 2008, the Company recorded losses of $1.9 million and $0.7
million, respectively.
NOTE 8 ASSET RETIREMENT OBLIGATIONS
The Company recognizes an estimated liability for the plugging and abandonment of its oil and
gas wells and related facilities. It also recognizes a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be made. The
associated asset retirement costs are capitalized as
part of the carrying amount of the long-lived asset. The Company also considers the estimated
salvage value in the calculation of depreciation, depletion and amortization.
26
The estimated liability is based on the Companys historical experience in plugging and
abandoning wells, estimated remaining lives of those wells based on reserve estimates, external
estimates as to the cost to plug and abandon the wells in the future and federal and state
regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free
interest rate. Revisions to the liability could occur due to changes in estimates of plugging and
abandonment costs or remaining lives of the wells, or if federal or state regulators enact new
plugging and abandonment requirements. The Company has no assets legally restricted for purposes of
settling asset retirement obligations. Except for its oil and gas properties, the Company has
determined that there are no other material retirement obligations associated with tangible
long-lived assets.
A reconciliation of the Companys liability for well plugging and abandonment costs for the
periods indicated is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Asset retirement obligations, beginning of period |
|
$ |
50,142 |
|
|
$ |
45,334 |
|
|
$ |
48,136 |
|
|
$ |
42,358 |
|
Liabilities incurred |
|
|
125 |
|
|
|
975 |
|
|
|
721 |
|
|
|
2,615 |
|
Liabilities settled |
|
|
(113 |
) |
|
|
(36 |
) |
|
|
(198 |
) |
|
|
(38 |
) |
Accretion expense |
|
|
753 |
|
|
|
687 |
|
|
|
2,248 |
|
|
|
2,025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
50,907 |
|
|
$ |
46,960 |
|
|
$ |
50,907 |
|
|
$ |
46,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accretion expense is included in depreciation, depletion and amortization in the Companys
consolidated statements of operations.
NOTE 9 DEBT
As of September 30, 2009, the Companys debt consists entirely of instruments entered into by
ATN, AHD and APL. The Company has not guaranteed any of its subsidiaries debt obligations, with
the exception of the AHD credit facility. Total debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ATN revolving credit facility |
|
$ |
270,000 |
|
|
$ |
467,000 |
|
ATN 10.75% senior notes due 2018 |
|
|
406,105 |
|
|
|
406,655 |
|
ATN 12.125% senior notes due 2017 |
|
|
196,350 |
|
|
|
|
|
AHD credit facility |
|
|
12,000 |
|
|
|
46,000 |
|
APL revolving credit facility |
|
|
315,000 |
|
|
|
302,000 |
|
APL term loan |
|
|
433,505 |
|
|
|
707,180 |
|
APL 8.125% senior notes due 2015 |
|
|
271,495 |
|
|
|
261,197 |
|
APL 8.75% senior notes due 2018 |
|
|
223,050 |
|
|
|
223,050 |
|
|
|
|
|
|
|
|
Total debt |
|
|
2,127,505 |
|
|
|
2,413,082 |
|
Less current maturities |
|
|
(12,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
2,115,505 |
|
|
$ |
2,413,082 |
|
|
|
|
|
|
|
|
27
ATN Revolving Credit Facility
At September 30, 2009, ATN had a credit facility with a syndicate of banks with a borrowing
base of $600.0 million that matures in June 2012. The borrowing base is redetermined
semiannually on April 1 and
October 1 subject to changes in oil and gas reserves or is automatically reduced by 25% of the
stated principal of any senior unsecured notes issued by ATN. On July 13, 2009, ATN issued $200.0
million of senior unsecured notes, and the borrowing base was reduced by $50.0 million to $600.0
million. Up to $50.0 million of the credit facility may be in the form of standby letters of
credit, of which $1.2 million was outstanding at September 30, 2009, which was not reflected as
borrowings on the Companys consolidated balance sheets. The facility is secured by substantially
all of ATNs assets and is guaranteed by each of its subsidiaries and bears interest at either the
base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at
ATNs option. On April 9, 2009, the credit agreement was amended to, among other things, increase
the applicable margin on Eurodollar Loans from a range of 100 to 175 basis points to a range of 200
to 300 basis points and the applicable margin for base rate loans from a range of 0 to 75 basis
points to a range of 112.5 to 212.5 basis points. At September 30, 2009 and December 31, 2008, the
weighted average interest rate on outstanding borrowings was 2.7% and 2.8%, respectively. The base
rate for any day equals the higher of the federal funds rate plus 0.50%, the J.P. Morgan prime rate
or the adjusted LIBOR for a month interest period plus 1.0%. Adjusted LIBOR is LIBOR divided by
1.00 minus the percentage prescribed by the Federal Reserve Board for determining the reserve
requirement for Eurocurrency liabilities.
On July 10, 2009, ATNs credit agreement was amended to, among other things, permit the Merger
to allow ATN to distribute (a) amounts equal to the Companys income tax liability attributable to
ATNs net income at the highest marginal rate and (b) up to $40.0 million per year and, to the
extent that it distributes less than that amount in any year, it may carry over up to $20.0 million
for use in the next year.
The events which constitute an event of default for ATNs credit facility are also customary
for loans of this size, including payment defaults, breaches of representations or covenants
contained in the credit agreement, adverse judgments against ATN in excess of a specified amount
and a change of control. In addition, the agreement limits sales, leases or transfers of assets
and the incurrence of additional indebtedness. ATN is in compliance with these covenants as of
September 30, 2009. The credit facility also requires ATN to maintain a ratio of current assets (as
defined in the credit facility) to current liabilities (as defined in the credit facility) of not
less than 1.0 to 1.0, and a ratio of total debt (as defined in the credit facility) to earnings
before interest, taxes, depreciation, depletion and amortization (EBITDA, as defined in the
credit facility) of 3.75 to 1.0 commencing January 1, 2009, decreasing to 3.5 to 1.0 commencing
January 1, 2010 and thereafter. According to the definitions contained in ATNs credit facility,
ATNs ratio of current assets to current liabilities was 2.1 to 1.0 and its ratio of total debt to
EBITDA was 3.0 to 1.0 at September 30, 2009.
ATN Senior Notes
At September 30, 2009, ATN had $400.0 million principal amount outstanding of 10.75% senior
unsecured notes (ATN 10.75% Senior Notes) due on February 1, 2018 and $200.0 million principal
amount outstanding of 12.125% senior unsecured notes due August 1, 2017 (ATN 12.125% Senior
Notes; collectively, the ATN Senior Notes). The ATN 12.125% Senior Notes were issued on July
13, 2009 in a public offering at a price of 98.116% to par value for a yield 12.5% at maturity.
Net proceeds from the offering were used to reduce outstanding borrowings under ATNs revolving
credit facility. Interest on the ATN Senior Notes in the aggregate is payable semi-annually in
arrears on February 1 and August 1 of each year. The ATN 10.75% Senior Notes are redeemable at any
time on or after February 1, 2013, and the ATN 12.125% Senior Notes are redeemable at any time on
or after August 1, 2013, at specified redemption prices, together with accrued and unpaid interest
to the date of redemption. In addition, before February 1, 2011 for the ATN 10.75% Notes and
before August 1, 2012 for the ATN 12.125% Senior Notes, ATN may redeem up to 35% of the aggregate
principal amount of the Senior Notes with the proceeds of equity offerings at a stated redemption
price. The ATN Senior Notes are also subject to repurchase by ATN at a price equal to 101% for the
ATN 10.75% Senior Notes and ATN 12.125% Senior Notes of their principal amount, plus accrued and
unpaid interest, upon a change of control or upon certain asset sales if ATN does not reinvest the
net proceeds within 360 days. The ATN Senior Notes are junior in right of payment to ATNs secured
debt, including its obligations under its credit facility. The indentures governing the ATN Senior
Notes contain covenants,
including limitations of ATNs ability to: incur certain liens; engage in sale/leaseback
transactions; incur additional indebtedness; declare or pay distributions if an event of default
has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make
certain investments; or merge, consolidate or sell substantially all of its assets. ATN is in
compliance with these covenants as of September 30, 2009.
28
AHD Credit Facility
At September 30, 2009, AHD had $12.0 million outstanding under a revolving credit facility
with a syndicate of banks. On June 1, 2009, AHD entered into an amendment to its credit facility
agreement which, among other changes:
|
|
|
required AHD to immediately repay $30.0 million of then-outstanding $46.0 million of
borrowings under the credit facility, $15.0 million of which was borrowed from the
Company through a subordinate loan; |
|
|
|
|
required AHD to repay $4.0 million of the then-remaining $16.0 million outstanding
under the credit facility on each of July 13, 2009, October 13, 2009 and January 13,
2010, with the balance of the indebtedness being due on the original maturity date of
the credit facility of April 13, 2010. AHD repaid $4.0 million of its outstanding
credit facility borrowings on July 13, 2009 and October 13, 2009 in accordance with the
amendment through a subordinate loan with the Company. AHD may not borrow additional
amounts under the credit facility or issue letters of credit; |
|
|
|
|
requires AHD to use any of its excess cash flow, which the amendment generally
defines as cash in excess of $1.5 million as of the last business day of each month, to
repay outstanding borrowings under the credit facility. In addition, the amendment
requires AHD to repay borrowings under the credit facility with the net proceeds of any
sales of its common units in APL; |
|
|
|
|
eliminated all financial covenants in the credit agreement, including the leverage
ratio, the combined leverage ratio with APL and the interest coverage ratio (all as
defined within the credit facility agreement); |
|
|
|
|
prohibits AHD from paying any cash distributions on or redeeming any of its equity
while the credit facility is in effect and permits AHD to pay operating expenses only
to the extent incurred or paid in the ordinary course of business; and |
|
|
|
|
reduced the applicable margin above LIBOR, the federal funds rate plus 0.5% or the
Wachovia Bank, National Association prime rate to be 0.75% for LIBOR loans and 0.0% for
federal funds rate or prime rate loans. The weighted average interest rate on the
outstanding credit facility borrowings at September 30, 2009 was 3.25%. |
Borrowings under AHDs credit facility are secured by a first-priority lien on a security
interest in all of AHDs assets, including the pledge of Atlas Pipeline GPs interests in APL, and
are guaranteed by Atlas Pipeline GP and AHDs other subsidiaries (excluding APL and its
subsidiaries). AHDs credit facility contains customary covenants, including restrictions on its
ability to incur additional indebtedness; make certain acquisitions, loans or investments; or enter
into a merger or sale of substantially all of AHDs property or assets, including the sale or
transfer of interest in its subsidiaries. AHD is in compliance with these covenants as of
September 30, 2009. The events which constitute an event of default under AHDs credit
facility are also customary for loans of this size, including payment defaults, breaches of
representations or covenants contained in the credit agreements, adverse judgments against AHD in
excess of a specified amount, a change of control of the Company, AHDs general partner or any
other obligor, and termination of a material agreement and occurrence of a material adverse effect.
29
AHDs $30 million repayment was funded from the proceeds of (i) a loan from the Company in the
amount of $15 million (obtained on June 1, 2009) and (ii) the purchase by APL of $15 million of
preferred equity in a newly-formed subsidiary of AHD. Under the subordinate loan, interest accrues
quarterly on the outstanding principal amount at the rate of 12% per annum, but before the maturity
date, interest is payable entirely by increasing the principal amount of the note, and the maturity
date is generally the day following the day that AHD pays all indebtedness under the credit
facility (Termination Date). The material terms of the preferred units purchased by APL in a
newly-formed subsidiary of AHD are as follows: distributions are payable quarterly at the rate of
12% per annum, but before the Termination Date, distributions will be paid by increasing APLs
investment in the preferred units; upon the Termination Date, all preferred distributions will be
paid in cash to APL; and AHD has the option, after the Termination Date, of redeeming all of the
preferred units APL owns for an amount equal to the preferred unit capital.
On June 1, 2009, in connection with AHDs amendment of the credit facility, the Company
guaranteed the then remaining balance outstanding under the credit facility under a guarantee
agreement with the administrative agent of the credit facility. In consideration for this
guarantee, AHD issued to the Company a promissory note which requires it to pay interest to the
Company in an amount based upon the principal amount outstanding under the credit facility. The
maturity date of the promissory note is the day following the date that AHD repays all outstanding
borrowings under its credit facility. Interest on the promissory note, which is calculated on the
outstanding balance under the credit facility, accrues quarterly at the rate of 3.75% per annum.
However, prior to the maturity date of the promissory note, interest under the promissory note will
not be payable in cash, but instead the principal amount upon which interest is calculated will be
increased by the interest amount payable.
APL Term Loan and Revolving Credit Facility
At September 30, 2009, APL had a senior secured credit facility with a syndicate of banks
which consisted of a term loan which matures in July 2014 and a $380.0 million revolving credit
facility which matures in July 2013. Borrowings under APLs credit facility bear interest, at
APLs option, at either (i) adjusted LIBOR plus the applicable margin, as defined, or (ii) the
higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus the
applicable margin). The weighted average interest rate on the outstanding APL revolving credit
facility borrowings at September 30, 2009 was 6.8%, and the weighted average interest rate on the
outstanding APL term loan borrowings at September 30, 2009 was 6.8%. Up to $50.0 million of the
credit facility may be utilized for letters of credit, of which $9.1 million was outstanding at
September 30, 2009. These outstanding letter of credit amounts were not reflected as borrowings on
the Companys consolidated balance sheet.
On May 29, 2009, APL entered into an amendment to its credit facility agreement which, among
other changes:
|
|
|
increased the applicable margin above adjusted LIBOR, the federal funds rate plus
0.5% or the Wachovia Bank prime rate upon which borrowings under the credit facility
bear interest; |
|
|
|
|
for borrowings under the credit facility that bear interest at LIBOR plus the
applicable margin, set a floor for the adjusted LIBOR interest rate of 2.0% per annum; |
|
|
|
|
increased the maximum ratio of total funded debt (as defined in the credit
agreement) to consolidated EBITDA (as defined in the credit agreement; the leverage
ratio) and decreased the
ratio of interest coverage (as defined in the credit agreement) that the credit facility
requires APL to maintain;
|
30
|
|
|
instituted a maximum ratio of senior secured funded debt (as defined in the credit
agreement) to consolidated EBITDA (the senior secured leverage ratio) that the credit
facility requires APL to maintain; |
|
|
|
|
required that APL pay no cash distributions during the remainder of the year ended
December 31, 2009 and allows it to pay cash distributions beginning January 1, 2010 if
its senior secured leverage ratio is less than 2.75x and it has minimum liquidity (as
defined in the credit agreement) of at least $50.0 million; |
|
|
|
|
generally limits APLs annual capital expenditures to $95.0 million for the
remainder of fiscal 2009 and $70.0 million each year thereafter; |
|
|
|
|
permitted APL to retain (i) up to $135.0 million of net cash proceeds from
dispositions completed in fiscal 2009 for reinvestment in similar replacement assets
within 360 days, and (ii) up to $50.0 million of net cash proceeds from dispositions
completed in any subsequent fiscal year subject to certain limitations as defined
within the credit agreement; and |
|
|
|
|
instituted a mandatory repayment requirement of the outstanding senior secured term
loan from excess cash flow (as defined in the credit agreement) based upon APLs
leverage ratio. |
In June 2008, APL entered into an amendment to the credit facility agreement to revise the
definition of Consolidated EBITDA to provide for the add-back of charges relating to its early
termination of certain derivative contracts (see Note 10) in calculating Consolidated EBITDA.
Pursuant to this amendment, in June 2008, APL repaid $122.8 million of its outstanding term loan
and repaid $120.0 million of outstanding borrowings under the revolving credit facility with
proceeds from its issuance of $250.0 million of 10-year 8.75% senior unsecured notes.
Additionally, pursuant to this amendment, in June 2008 APLs lenders increased their commitments
for the revolving credit facility by $80.0 million to $380.0 million.
Borrowings under APLs credit facility are secured by a lien on and security interest in all
of APLs property and that of its subsidiaries, except for the assets owned by Chaney Dell and
Midkiff/Benedum joint ventures and the Laurel Mountain joint venture, and by the guaranty of each
of APLs consolidated subsidiaries other than the joint venture companies. The credit facility
contains customary covenants, including restrictions on APLs ability to incur additional
indebtedness; make certain acquisitions, loans or investments; make distribution payments to its
unitholders if an event of default exists; or enter into a merger or sale of assets, including the
sale or transfer of interests in its subsidiaries. APL is also unable to borrow under its credit
facility to pay distributions of available cash to unitholders because such borrowings would not
constitute working capital borrowings pursuant to its partnership agreement. APL is in
compliance with these covenants as of September 30, 2009.
31
The events which constitute an event of default for the credit facility are also customary for
loans of this size, including payment defaults, breaches of representations or covenants contained
in the credit agreement, adverse judgments against APL in excess of a specified amount and a change
of control of APLs General Partner. The credit facility requires APL to maintain the following
ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum |
|
|
Minimum |
|
|
|
Maximum |
|
|
Senior Secured |
|
|
Interest |
|
|
|
Leverage |
|
|
Leverage |
|
|
Coverage |
|
Fiscal quarter ending: |
|
Ratio |
|
|
Ratio |
|
|
Ratio |
|
September 30, 2009 |
|
|
6.50x |
|
|
|
3.75x |
|
|
|
2.50x |
|
December 31, 2009 |
|
|
8.50x |
|
|
|
5.25x |
|
|
|
1.70x |
|
March 31, 2010 |
|
|
9.25x |
|
|
|
5.75x |
|
|
|
1.40x |
|
June 30, 2010 |
|
|
8.00x |
|
|
|
5.00x |
|
|
|
1.65x |
|
September 30, 2010 |
|
|
7.00x |
|
|
|
4.25x |
|
|
|
1.90x |
|
December 31, 2010 |
|
|
6.00x |
|
|
|
3.75x |
|
|
|
2.20x |
|
Thereafter |
|
|
5.00x |
|
|
|
3.00x |
|
|
|
2.75x |
|
As of September 30, 2009, APLs leverage ratio was 4.2 to 1.0, its senior secured leverage
ratio was 2.5 to 1.0 and its interest coverage ratio was 3.3 to 1.0.
APL Senior Notes
At September 30, 2009, APL had $223.1 million principal amount outstanding of 8.75% senior
unsecured notes due on June 15, 2018 (APL 8.75% Senior Notes) and $275.5 million principal amount
outstanding of 8.125% senior unsecured notes due on December 15, 2015 (APL 8.125% Senior Notes;
collectively, the APL Senior Notes). The APL 8.125% Senior Notes are presented combined with a
net $4.0 million of unamortized discount as of September 30, 2009. Interest on the APL Senior
Notes in the aggregate is payable semi-annually in arrears on June 15 and December 15. The APL
8.75% Senior Notes are redeemable at any time after June 15, 2013, and the APL 8.125% Senior Notes
are redeemable at any time after December 15, 2010 at certain redemption prices, together with
accrued and unpaid interest to the date of redemption. Prior to June 15, 2011, APL may redeem up
to 35% of the aggregate principal amount of the APL 8.75% Senior Notes with the proceeds of certain
equity offerings at a stated redemption price. The APL 8.75% Senior Notes in the aggregate are also
subject to repurchase by APL at a price equal to 101% of their principal amount, plus accrued and
unpaid interest, upon a change of control or upon certain asset sales if APL does not reinvest the
net proceeds within 360 days. The APL 8.75% Senior Notes are junior in right of payment to APLs
secured debt, including APLs obligations under its credit facility.
In January 2009, APL issued Sunlight Capital $15.0 million of its 8.125% Senior Notes to
redeem 10,000 APL Class A Preferred Units. Management of APL estimated that the fair value of the
$15.0 million 8.125% Senior Notes issued was approximately $10.0 million at the date of issuance
based upon the market price of the publicly-traded Senior Notes. As such, APL recognized a $5.0
million discount on the issuance of the Senior Notes, which is presented as a reduction of
long-term debt on the Companys consolidated balance sheets. The discount recognized upon issuance
of the Senior Notes will be amortized to interest expense within the Companys consolidated
statements of operations over the term of the 8.125% Senior Notes based upon the effective interest
rate method.
Indentures governing the APL Senior Notes in the aggregate contain covenants, including
limitations of APLs ability to: incur certain liens; engage in sale/leaseback transactions; incur
additional indebtedness; declare or pay distributions if an event of default has occurred; redeem,
repurchase or retire equity interests or subordinated indebtedness; make certain investments; or
merge, consolidate or sell substantially all of its assets. APL is in compliance with these
covenants as of September 30, 2009.
32
NOTE 10 DERIVATIVE INSTRUMENTS
The Company, AHD and APL use a number of different derivative instruments, principally swaps,
collars and options, in connection with its commodity price and interest rate risk management
activities. The Company and its subsidiaries enter into financial instruments to hedge its
forecasted natural gas, NGLs, crude
oil and condensate sales against the variability in expected future cash flows attributable to
changes in market prices. Its subsidiaries also enter into financial swap instruments to hedge
certain portions of its floating interest rate debt against the variability in market interest
rates. Swap instruments are contractual agreements between counterparties to exchange obligations
of money as the underlying natural gas, NGLs, crude oil and condensate is sold or interest payments
on the underlying debt instrument is due. Under swap agreements, the Company and its subsidiaries
receives or pays a fixed price and receives or remits a floating price based on certain indices for
the relevant contract period. Commodity-based option instruments are contractual agreements that
grant the right, but not obligation, to purchase or sell natural gas, NGLs, crude oil and
condensate at a fixed price for the relevant contract period.
The Company and its subsidiaries formally document all relationships between hedging
instruments and the items being hedged, including its risk management objective and strategy for
undertaking the hedging transactions. This includes matching the commodity and interest derivative
contracts to the forecasted transactions. The Company and its subsidiaries assess, both at the
inception of the derivative and on an ongoing basis, whether the derivative is effective in
offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a
derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the
loss of adequate correlation between the hedging instrument and the underlying item being hedged,
the Company and its subsidiaries will discontinue hedge accounting for the derivative and
subsequent changes in the derivative fair value, which is determined by the Company and its
subsidiaries through the utilization of market data, will be recognized immediately within gain
(loss) on mark-to-market derivatives in the Companys consolidated statements of operations. For
derivatives qualifying as hedges, the Company and its subsidiaries recognize the effective portion
of changes in fair value in stockholders equity as accumulated other comprehensive income and
reclassifies the portion relating to commodity derivatives to gas and oil production revenues for
the Companys derivatives and gathering, transmission and processing revenues for APL derivatives,
and the portion relating to interest rate derivatives to interest expense within the Companys
consolidated statements of operations as the underlying transactions are settled. For
non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Company
and its subsidiaries recognize changes in fair value within gain (loss) on mark-to-market
derivatives in its consolidated statements of operations as they occur.
Derivatives are recorded on the Companys consolidated balance sheet as assets or liabilities
at fair value. The Company reflected net derivative assets on its consolidated balance sheets of
$50.9 million and $89.3 million at September 30, 2009 and December 31, 2008, respectively. Of the
$50.4 million of net gain in accumulated other comprehensive income within stockholders equity on
the Companys consolidated balance sheet at September 30, 2009, if the fair values of the
instruments remain at current market values, the Company will reclassify $32.9 million of gains to
the Companys consolidated statements of operations over the next twelve month period as these
contracts expire, consisting of $37.1 million of gains to gas and oil production revenues, $2.2
million of losses to gathering, transmission and processing revenues and $2.1 million of losses to
interest expense. Aggregate gains of $17.6 million will be reclassified to the Companys
consolidated statements of operations in later periods as these remaining contracts expire,
consisting of $20.3 million of gains to gas and oil production revenues, $1.5 million of losses to
gathering, transmission and processing revenues and $1.1 million of losses to interest expense.
Actual amounts that will be reclassified will vary as a result of future price changes.
The following table summarizes the fair value of the Companys derivative instruments as of
September 30, 2009 and December 31, 2008, as well as the gain or loss recognized in income for
effective derivative instruments for the nine months ended September 30, 2009 and 2008. There were
no gains or losses recognized in income for ineffective derivative instruments for the nine months
ended September 30, 2009 and 2008.
33
Fair Value of Derivative Instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
|
Liability Derivatives |
|
Derivatives in |
|
|
|
Fair Value |
|
|
|
|
Fair Value |
|
Cash Flow |
|
Balance Sheet |
|
September 30, |
|
|
December 31, |
|
|
Balance Sheet |
|
September 30, |
|
|
December 31, |
|
Hedging Relationships |
|
Location |
|
2009 |
|
|
2008 |
|
|
Location |
|
2009 |
|
|
2008 |
|
|
|
|
|
(in thousands) |
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
Current assets |
|
$ |
84,446 |
|
|
$ |
107,766 |
|
|
Current liabilities |
|
$ |
(1,273 |
) |
|
$ |
(9,348 |
) |
|
|
Long-term assets |
|
|
40,425 |
|
|
|
69,451 |
|
|
Long-term liabilities |
|
|
(23,725 |
) |
|
|
(8,410 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
124,871 |
|
|
|
177,217 |
|
|
|
|
|
(24,998 |
) |
|
|
(17,758 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts: |
|
Current assets |
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
(3,832 |
) |
|
|
(3,481 |
) |
|
|
Long-term assets |
|
|
|
|
|
|
|
|
|
Long-term liabilities |
|
|
(866 |
) |
|
|
(2,361 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,698 |
) |
|
|
(5,842 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
|
|
$ |
124,871 |
|
|
$ |
177,217 |
|
|
|
|
$ |
(29,696 |
) |
|
$ |
(23,600 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effects of Derivative Instruments on Consolidated Statements of Operations for the three months and nine months ended September 30, 2009 and 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/(Loss) |
|
|
Location of |
|
Gain/(Loss) |
|
|
|
Recognized in OCI on Derivative |
|
|
Gain/(Loss) |
|
Reclassified from OCI into Income |
|
|
|
(Effective Portion) |
|
|
Reclassified from |
|
(Effective Portion) |
|
Derivatives in |
|
For the Three Months Ended |
|
|
Accumulated |
|
For the Three Months Ended |
|
Cash Flow |
|
September 30, |
|
|
September 30, |
|
|
OCI into Income |
|
September 30, |
|
|
September 30, |
|
Hedging Relationships |
|
2009 |
|
|
2008 |
|
|
(Effective Portion) |
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
$ |
5,983 |
|
|
$ |
284,075 |
|
|
Gas and oil production |
|
$ |
35,134 |
|
|
$ |
(27,613 |
) |
Interest rate contracts |
|
|
(966 |
) |
|
|
(1,169 |
) |
|
Interest expense |
|
|
(1,083 |
) |
|
|
(312 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5,017 |
|
|
$ |
282,906 |
|
|
|
|
$ |
34,051 |
|
|
$ |
(27,925 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/(Loss) |
|
|
Location of |
|
Gain/(Loss) |
|
|
|
Recognized in OCI on Derivative |
|
|
Gain/(Loss) |
|
Reclassified from OCI into Income |
|
|
|
(Effective Portion) |
|
|
Reclassified from |
|
(Effective Portion) |
|
Derivatives in |
|
For the Nine Months Ended |
|
|
Accumulated |
|
For the Nine Months Ended |
|
Cash Flow |
|
September 30, |
|
|
September 30, |
|
|
OCI into Income |
|
September 30, |
|
|
September 30, |
|
Hedging Relationships |
|
2009 |
|
|
2008 |
|
|
(Effective Portion) |
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
$ |
70,269 |
|
|
$ |
(26,447 |
) |
|
Gas and oil production |
|
$ |
82,216 |
|
|
$ |
(25,969 |
) |
Interest rate contracts |
|
|
(1,971 |
) |
|
|
626 |
|
|
Interest expense |
|
|
(3,115 |
) |
|
|
(335 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
68,298 |
|
|
$ |
(25,821 |
) |
|
|
|
$ |
79,101 |
|
|
$ |
(26,304 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From time to time, the Company enters into natural gas and crude oil future option
contracts and collar contracts to achieve more predictable cash flows by hedging its exposure to
changes in natural gas prices and oil prices. At any point in time, such contracts may include
regulated New York Mercantile Exchange (NYMEX) futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally
settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil
contracts are based on a West Texas Intermediate (WTI) index. These contracts have qualified and
been designated as cash flow hedges and recorded at their fair values.
In May 2009, the Company received approximately $28.5 million in proceeds from the early
termination of natural gas and oil derivative positions for production periods from 2011 through
2013. In conjunction with the early termination of these derivatives, the Company entered into new
derivative positions at prevailing prices at the time of the transaction. The net proceeds from
the early termination of these derivatives were used to reduce indebtedness under ATNs credit
facility (see Note 9). The gain recognized upon the early termination of these derivative
positions will continue to be reported in accumulated other comprehensive income and will be
reclassified into the Companys consolidated statements of operations in the same periods in which
the hedged production revenues would have been recognized in earnings.
34
The Company has a $94.2 million net unrealized gain related to financial derivatives on its
gas and oil production which is shown as a component of accumulated other comprehensive income at
September 30, 2009, compared to a net unrealized gain of $106.1 million at December 31, 2008. If
the fair values of the instruments remain at current market values, the Company will reclassify $60.1 million of
unrealized gains to its consolidated statements of operations over the next twelve-month period as
these contracts settle and $34.1 million of unrealized gains will be reclassified in later periods.
The Companys commodity price risk management includes estimated future natural gas and crude
oil production of the Partnerships. Therefore, a portion of any unrealized derivative gain or loss
is allocable to the limited partners of the Partnerships based on their share of estimated gas and
oil production related to the derivatives not yet settled. At September 30, 2009 and December 31,
2008, net unrealized derivative liabilities of $35.1 million and $51.8 million, respectively, are
payable to the limited partners in the Partnerships and are included in the consolidated balance
sheets.
At September 30, 2009, ATN had $270.0 million of borrowings under its revolving credit
facility (see Note 9). At September 30, 2009, the Company had interest rate derivative contracts
having an aggregate notional principal amount of $150.0 million through January 2011, which were
designated as cash flow hedges. Under the terms of the contract, the Company will pay an interest
rate of 3.11%, plus the applicable margin as defined under the terms of its revolving credit
facility, and will receive LIBOR, plus the applicable margin, on the notional principal amounts.
This derivative effectively converts $150.0 million of ATNs floating rate debt under the revolving
credit facility to fixed-rate debt. The Company has accounted for the interest rate derivative
contracts as effective hedge instruments under prevailing accounting standards.
As of September 30, 2009, the Company had the following interest rate and commodity
derivatives:
Interest Fixed Rate Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract |
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Period Ended |
|
|
Fair Value |
|
Term |
|
Amount |
|
|
Option Type |
|
|
December 31, |
|
|
Liability |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
January 2008 - January 2011 |
|
$ |
150,000,000 |
|
|
Pay 3.11% - Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(1,009 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(3,495 |
) |
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
(194 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(4,698 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset (2) |
|
|
|
(MMBtu) (1) |
|
|
(per MMBtu) (1) |
|
|
(in thousands) |
|
2009 |
|
|
10,340,000 |
|
|
$ |
8.242 |
|
|
$ |
36,116 |
|
2010 |
|
|
31,880,000 |
|
|
$ |
7.708 |
|
|
|
47,682 |
|
2011 |
|
|
20,720,000 |
|
|
$ |
7.040 |
|
|
|
3,403 |
|
2012 |
|
|
19,680,000 |
|
|
$ |
7.223 |
|
|
|
4,119 |
|
2013 |
|
|
13,260,000 |
|
|
$ |
7.082 |
|
|
|
235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
91,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Natural Gas Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Option Type |
|
Volumes |
|
|
Floor and Cap |
|
|
Asset/(Liability) (1) |
|
|
|
|
|
(MMBtu) (1) |
|
|
(per MMBtu) (1) |
|
|
(in thousands) |
|
2009 |
|
Puts purchased |
|
|
60,000 |
|
|
$ |
11.000 |
|
|
$ |
370 |
|
2009 |
|
Calls sold |
|
|
60,000 |
|
|
$ |
15.350 |
|
|
|
|
|
2010 |
|
Puts purchased |
|
|
3,360,000 |
|
|
$ |
7.839 |
|
|
|
6,021 |
|
2010 |
|
Calls sold |
|
|
3,360,000 |
|
|
$ |
9.007 |
|
|
|
|
|
2011 |
|
Puts purchased |
|
|
9,540,000 |
|
|
$ |
6.523 |
|
|
|
808 |
|
2011 |
|
Calls sold |
|
|
9,540,000 |
|
|
$ |
7.666 |
|
|
|
|
|
2012 |
|
Puts purchased |
|
|
4,020,000 |
|
|
$ |
6.514 |
|
|
|
|
|
2012 |
|
Calls sold |
|
|
4,020,000 |
|
|
$ |
7.718 |
|
|
|
(249 |
) |
2013 |
|
Puts purchased |
|
|
5,340,000 |
|
|
$ |
6.516 |
|
|
|
|
|
2013 |
|
Calls sold |
|
|
5,340,000 |
|
|
$ |
7.811 |
|
|
|
(579 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6,371 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset/(Liability) (3) |
|
|
|
(Bbl) (1) |
|
|
(per Bbl) (1) |
|
|
(in thousands) |
|
2009 |
|
|
14,600 |
|
|
$ |
99.319 |
|
|
$ |
424 |
|
2010 |
|
|
48,900 |
|
|
$ |
97.400 |
|
|
|
1,134 |
|
2011 |
|
|
42,600 |
|
|
$ |
77.460 |
|
|
|
11 |
|
2012 |
|
|
33,500 |
|
|
$ |
76.855 |
|
|
|
(74 |
) |
2013 |
|
|
10,000 |
|
|
$ |
77.360 |
|
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Option Type |
|
Volumes |
|
|
Floor and Cap |
|
|
Asset/(Liability) (3) |
|
|
|
|
|
(Bbl) (1) |
|
|
(per Bbl) (1) |
|
|
(in thousands) |
|
2009 |
|
Puts purchased |
|
|
9,000 |
|
|
$ |
85.000 |
|
|
$ |
134 |
|
2009 |
|
Calls sold |
|
|
9,000 |
|
|
$ |
116.561 |
|
|
|
|
|
2010 |
|
Puts purchased |
|
|
31,000 |
|
|
$ |
85.000 |
|
|
|
468 |
|
2010 |
|
Calls sold |
|
|
31,000 |
|
|
$ |
112.918 |
|
|
|
|
|
2011 |
|
Puts purchased |
|
|
27,000 |
|
|
$ |
67.223 |
|
|
|
|
|
2011 |
|
Calls sold |
|
|
27,000 |
|
|
$ |
89.436 |
|
|
|
(27 |
) |
2012 |
|
Puts purchased |
|
|
21,500 |
|
|
$ |
65.506 |
|
|
|
|
|
2012 |
|
Calls sold |
|
|
21,500 |
|
|
$ |
91.448 |
|
|
|
(70 |
) |
2013 |
|
Puts purchased |
|
|
6,000 |
|
|
$ |
65.358 |
|
|
|
|
|
2013 |
|
Calls sold |
|
|
6,000 |
|
|
$ |
93.442 |
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ATN asset |
|
|
$ |
95,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Mmbtu represents million British Thermal Units; Bbl represents barrels. |
|
(2) |
|
Fair value based on forward NYMEX natural gas prices, as applicable. |
|
(3) |
|
Fair value based on forward WTI crude oil prices, as applicable. |
36
Atlas Pipeline Holdings and Atlas Pipeline Partners
Beginning July 1, 2008, APL discontinued hedge accounting for its existing commodity
derivatives which were qualified as hedges under prevailing accounting literature. As such,
subsequent changes in fair value of these derivatives are recognized immediately within gain (loss)
on mark-to-market derivatives in the Companys consolidated statements of operations. The fair
value of these commodity derivative instruments at June 30, 2008, which was recognized in
accumulated other comprehensive income within stockholders equity on the Companys consolidated
balance sheet, will be reclassified to the Companys consolidated statements of operations in the
future at the time the originally hedged physical transactions affect earnings.
During the nine months ended September 30, 2009 and year ended December 31, 2008, APL made net
payments of $5.0 million and $274.0 million, respectively, related to the early termination of
derivative contracts. Substantially all of these derivative contracts were put into place
simultaneously with the APLs acquisition of the Chaney Dell and Midkiff/Benedum systems in July
2007 and related to production periods ranging from the end of the second quarter of 2008 through
the fourth quarter of 2009. During the three and nine months ended September 30, 2009 and 2008,
the Company recognized the following derivative activity related to the termination of these
derivative instruments within its consolidated statements of operations (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Early Termination of Derivative Contracts |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net cash derivative
expense included
within gain (loss)
on mark-to-market
derivatives |
|
$ |
|
|
|
$ |
(70,258 |
) |
|
$ |
(5,000 |
) |
|
$ |
(186,068 |
) |
Net cash derivative
expense included
within
transmission,
gathering and
processing revenue |
|
|
|
|
|
|
(1,258 |
) |
|
|
|
|
|
|
(1,573 |
) |
Net non-cash
derivative income
(expense) included
within gain (loss)
on mark-to-market
derivatives |
|
|
15,488 |
|
|
|
6,488 |
|
|
|
34,708 |
|
|
|
(39,857 |
) |
Net non-cash
derivative expense
included within
transmission,
gathering and
processing revenue |
|
|
(19,976 |
) |
|
|
(19,514 |
) |
|
|
(54,043 |
) |
|
|
(19,514 |
) |
At September 30, 2009, AHD had an interest rate derivative contract having an aggregate
notional principal amount of $25.0 million. Under the terms of the agreement, AHD will pay an
interest rate of 3.01%, plus the applicable margin as defined under the terms of its revolving
credit facility (see Note 9), and will receive LIBOR, plus the applicable margin, on the notional
principal amounts. The interest rate swap agreement is effective at September 30, 2009 and expires
on May 28, 2010. In June 2009, AHD repaid a portion of its borrowings under the credit facility,
with a resulting balance of $12.0 million outstanding under the credit facility at September 30,
2009. In addition, in accordance with the June 2009 amendment to its credit facility (see Note 9),
AHD is prohibited from borrowing additional amounts under its credit facility once the amounts have
been repaid. In accordance with prevailing accounting literature, the portion of any gain or loss
in other comprehensive income related to forecasted hedge transactions that are no longer expected
to occur are to be removed from other comprehensive income and recognized within the Companys
statements of operations. As a result of this reduction in borrowings under the credit facility
below the notional amount of the interest rate derivative contract, the Company recognized an
expense of $0.1 million and $0.3 million within gain (loss) on mark-to-market derivatives in its
consolidated statements of operations for the three and nine months ended September 30, 2009,
respectively.
37
At September 30, 2009, APL had interest rate derivative contracts having aggregate notional
principal amounts of $450.0 million. Under the terms of these agreements, APL will pay weighted
average interest rates of 3.02%, plus the applicable margin as defined under the terms of its
credit facility (see Note 9), and will
receive LIBOR, plus the applicable margin, on the notional principal amounts. The APL
interest rate swap agreements were in effect as of September 30, 2009 and expire during periods
ranging from January 30, 2010 through April 30, 2010. Beginning May 29, 2009, APL discontinued
hedge accounting for its interest rate derivatives which were qualified as hedges under prevailing
accounting literature. As such, subsequent changes in fair value of these derivatives will be
recognized immediately within gain (loss) on mark-to-market derivatives in the Companys
consolidated statements of operations. The fair value of these derivative instruments at May 29,
2009, which was recognized within accumulated other comprehensive income within stockholders
equity on the Companys consolidated balance sheet, will be reclassified to the Companys
consolidated statements of operations in the future at the time the originally hedged physical
transactions affect earnings.
The following table summarizes AHD and APLs derivative activity, including the early
termination of derivative contracts disclosed above, for the periods indicated (amounts in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from cash settlement and
non-cash recognition of
qualifying hedge
instruments(1) |
|
$ |
(9,779 |
) |
|
$ |
(27,419 |
) |
|
$ |
(37,281 |
) |
|
$ |
(78,214 |
) |
Gain (loss) from change in
market value of non-
qualifying
derivatives(2) |
|
|
12,021 |
|
|
|
190,013 |
|
|
|
(30,460 |
) |
|
|
(17,919 |
) |
Gain (loss) from change in
market value of ineffective
portion of qualifying
derivatives(2) |
|
|
|
|
|
|
44,997 |
|
|
|
10,813 |
|
|
|
41,271 |
|
Gain (loss) from cash
settlement and non-cash
recognition of non-qualifying
derivatives(2) |
|
|
(10,321 |
) |
|
|
(84,207 |
) |
|
|
3,500 |
|
|
|
(280,696 |
) |
Loss from cash settlement of
interest rate
derivatives(3) |
|
|
(3,164 |
) |
|
|
(708 |
) |
|
|
(9,343 |
) |
|
|
(915 |
) |
Loss from change in market
value of non-qualifying
interest rate derivatives(2) |
|
|
(861 |
) |
|
|
|
|
|
|
(891 |
) |
|
|
|
|
Loss from reclassification of
loss from Other Comprehensive
Income to Other
Loss(2) |
|
|
(60 |
) |
|
|
|
|
|
|
(256 |
) |
|
|
|
|
|
|
|
(1) |
|
Included within transmission, gathering and processing revenue on the Companys
consolidated statements of operations. |
|
(2) |
|
Included within gain (loss) on mark-to-market derivatives on the Companys consolidated
statements of operations. |
|
(3) |
|
Included within interest expense on the Companys consolidated statements of operations. |
The following table summarizes AHDs and APLs gross fair values of cumulative derivative
instruments for the period indicated (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
|
|
Asset Derivatives |
|
|
Liability Derivatives |
|
|
|
Balance Sheet |
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
Location |
|
Fair Value |
|
|
Location |
|
Fair Value |
|
Derivatives not
designated as hedging
instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts |
|
N/A |
|
$ |
|
|
|
Current portion of derivative liability |
|
$ |
(6,352 |
) |
Commodity contracts |
|
Current portion of derivative asset |
|
|
4,514 |
|
|
|
|
|
|
|
Commodity contracts |
|
Long-term derivative asset |
|
|
1,980 |
|
|
|
|
|
|
|
Commodity contracts |
|
Current portion of derivative liability |
|
|
10,050 |
|
|
Current portion of derivative liability |
|
|
(45,162 |
) |
Commodity contracts |
|
Long-term derivative liability |
|
|
3,341 |
|
|
Long-term derivative liability |
|
|
(12,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,885 |
|
|
|
|
$ |
(64,111 |
) |
|
|
|
|
|
|
|
|
|
|
|
38
The following table summarizes the gross effect of AHDs and APLs derivative instruments on
the Companys consolidated statement of operations for the period indicated (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
Three months ended September 30, 2009 |
|
|
Gain (Loss) |
|
|
Gain (Loss) Reclassified from |
|
Gain (Loss) Recognized in Income |
|
|
Recognized in |
|
|
Accumulated OCI into Income |
|
(Ineffective Portion and Amount |
|
|
Accumulated |
|
|
(Effective Portion) |
|
Excluded from Effectiveness Testing) |
|
|
OCI |
|
|
Amount |
|
|
Location |
|
Amount |
|
|
Location |
Interest rate contracts(1) |
|
$ |
30 |
|
|
$ |
(3,419 |
) |
|
Interest expense |
|
$ |
(951 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(1) |
|
|
|
|
|
|
(10,294 |
) |
|
Transmission, gathering and processing revenue |
|
|
(13,671 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(2) |
|
|
|
|
|
|
|
|
|
N/A |
|
|
16,036 |
|
|
Gain (loss) on mark-to-market derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
30 |
|
|
$ |
(13,713 |
) |
|
|
|
$ |
1,414 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Hedges previously designated as cash flow hedges. |
|
(2) |
|
Dedesignated cash flow hedges and non-designated hedges. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
Nine months ended September 30, 2009 |
|
|
Gain (Loss) |
|
|
Gain (Loss) Reclassified from |
|
Gain (Loss) Recognized in Income |
|
|
Recognized in |
|
|
Accumulated OCI into Income |
|
(Ineffective Portion and Amount |
|
|
Accumulated |
|
|
(Effective Portion) |
|
Excluded from Effectiveness Testing) |
|
|
OCI |
|
|
Amount |
|
|
Location |
|
Amount |
|
|
Location |
Interest rate contracts(1) |
|
$ |
(2,411 |
) |
|
$ |
(9,599 |
) |
|
Interest expense |
|
$ |
(1,147 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(1) |
|
|
|
|
|
|
(37,158 |
) |
|
Transmission, gathering and processing revenue |
|
|
(36,579 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(2) |
|
|
|
|
|
|
|
|
|
N/A |
|
|
20,155 |
|
|
Gain (loss) on mark-to-market derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(2,411 |
) |
|
$ |
(46,757 |
) |
|
|
|
$ |
(17,571 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
|
|
|
(1) |
|
Hedges previously designated as cash flow hedges. |
|
(2) |
|
Dedesignated cash flow hedges and non-designated hedges. |
As of September 30, 2009, AHD had the following interest rate derivatives, including
derivatives that do not qualify for hedge accounting:
Interest Fixed-Rate Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Contract Period |
|
|
Fair Value |
|
Term |
|
Amount |
|
|
Type |
|
|
Ended December 31, |
|
|
Liability(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
May 2008 - May 2010 |
|
$ |
25,000,000 |
|
|
Pay 3.01% Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(174 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total AHD net liability |
|
$ |
(445 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Fair value based on independent, third-party
statements, supported by observable levels at which transactions are executed in the
marketplace. |
As of September 30, 2009, APL had the following interest rate and commodity derivatives,
including derivatives that do not qualify for hedge accounting:
Interest Fixed-Rate Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Contract Period |
|
|
Fair Value |
|
Term |
|
Amount |
|
|
Type |
|
|
Ended December 31, |
|
|
Liability(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
January 2008 - January 2010 |
|
$ |
200,000,000 |
|
|
Pay 2.88% Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(1,335 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(426 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,761 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 - April 2010 |
|
$ |
250,000,000 |
|
|
Pay 3.14% Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(1,832 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(2,314 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(4,146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset (3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
120,000 |
|
|
$ |
8.000 |
|
|
$ |
390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
1,230,000 |
|
|
$ |
(0.558 |
) |
|
$ |
(386 |
) |
2010 |
|
|
2,220,000 |
|
|
$ |
(0.607 |
) |
|
|
(401 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(787 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
40
Natural Gas Purchases Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability (3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
2,580,000 |
|
|
$ |
8.687 |
|
|
$ |
(10,162 |
) |
2010 |
|
|
4,380,000 |
|
|
$ |
8.635 |
|
|
|
(11,718 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(21,880 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset(3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
3,690,000 |
|
|
$ |
(0.659 |
) |
|
$ |
1,508 |
|
2010 |
|
|
6,600,000 |
|
|
$ |
(0.590 |
) |
|
|
1,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Fixed Price Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(2) |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
2009 |
|
|
5,544,000 |
|
|
$ |
0.754 |
|
|
$ |
(762 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Ethane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Liability(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
2009 |
|
|
630,000 |
|
|
$ |
0.340 |
|
|
$ |
(57 |
) |
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Asset(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
2009 |
|
|
15,246,000 |
|
|
$ |
0.820 |
|
|
$ |
579 |
|
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Isobutane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Liability(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
2009 |
|
|
126,000 |
|
|
$ |
0.589 |
|
|
$ |
(20 |
) |
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Normal Butane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Asset(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
2009 |
|
|
3,654,000 |
|
|
$ |
0.943 |
|
|
$ |
98 |
|
|
Puts purchased |
2010 |
|
|
3,654,000 |
|
|
$ |
1.038 |
|
|
$ |
544 |
|
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
Natural Gasoline Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Asset(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
2009 |
|
|
3,906,000 |
|
|
$ |
1.341 |
|
|
$ |
549 |
|
|
Puts purchased |
2010 |
|
|
3,906,000 |
|
|
$ |
1.345 |
|
|
$ |
902 |
|
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales Options (associated with NGL volume)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
Average |
|
|
|
|
|
|
Production Period |
|
Crude |
|
|
NGL |
|
|
Crude |
|
|
Fair Value |
|
|
|
Ended December 31, |
|
Volume |
|
|
Volume |
|
|
Price (4) |
|
|
Asset/(Liability)(3) |
|
|
Option Type |
|
|
(barrels) |
|
|
(gallons) |
|
|
(per barrel) |
|
|
(in thousands) |
|
|
|
|
2009 |
|
|
165,000 |
|
|
|
9,321,900 |
|
|
$ |
63.53 |
|
|
$ |
856 |
|
|
Puts purchased |
2009 |
|
|
527,700 |
|
|
|
29,874,978 |
|
|
$ |
84.80 |
|
|
|
(647 |
) |
|
Calls sold |
2010 |
|
|
486,000 |
|
|
|
27,356,700 |
|
|
$ |
61.24 |
|
|
|
4,111 |
|
|
Puts purchased |
2010 |
|
|
3,127,500 |
|
|
|
213,088,050 |
|
|
$ |
86.20 |
|
|
|
(20,462 |
) |
|
Calls sold |
2010 |
|
|
714,000 |
|
|
|
45,415,440 |
|
|
$ |
132.17 |
|
|
|
705 |
|
|
Calls purchased(5) |
2011 |
|
|
606,000 |
|
|
|
33,145,560 |
|
|
$ |
100.70 |
|
|
|
(4,517 |
) |
|
Calls sold |
2011 |
|
|
252,000 |
|
|
|
13,547,520 |
|
|
$ |
133.16 |
|
|
|
920 |
|
|
Calls purchased(5) |
2012 |
|
|
450,000 |
|
|
|
25,893,000 |
|
|
$ |
102.71 |
|
|
|
(4,038 |
) |
|
Calls sold |
2012 |
|
|
180,000 |
|
|
|
9,676,800 |
|
|
$ |
134.27 |
|
|
|
919 |
|
|
Calls purchased(5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(22,153 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(3) |
|
|
|
(barrels) |
|
|
(per barrel) |
|
|
(in thousands) |
|
2009 |
|
|
6,000 |
|
|
$ |
62.700 |
|
|
$ |
(48 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volumes |
|
|
Crude Price(4) |
|
|
Asset/(Liability)(3) |
|
|
Option Type |
|
|
|
(barrels) |
|
|
(per barrel) |
|
|
(in thousands) |
|
|
|
|
2009 |
|
|
117,000 |
|
|
$ |
64.151 |
|
|
$ |
604 |
|
|
Puts purchased |
2009 |
|
|
76,500 |
|
|
$ |
84.956 |
|
|
|
(116 |
) |
|
Calls sold |
2010 |
|
|
411,000 |
|
|
$ |
64.732 |
|
|
|
4,450 |
|
|
Puts purchased |
2010 |
|
|
234,000 |
|
|
$ |
88.088 |
|
|
|
(1,475 |
) |
|
Calls sold |
2011 |
|
|
72,000 |
|
|
$ |
93.109 |
|
|
|
(746 |
) |
|
Calls sold |
2012 |
|
|
48,000 |
|
|
$ |
90.314 |
|
|
|
(648 |
) |
|
Calls sold |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net APL liability |
|
|
$ |
(43,782 |
) |
|
|
|
|
|
|
|
|
|
|
Total net AHD liability |
|
|
|
(445 |
) |
|
|
|
|
|
|
|
|
|
|
Total net Company asset |
|
|
|
95,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated net asset |
|
|
$ |
50,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
(1) |
|
Fair value based on independent, third-party statements, supported by
observable levels at which transactions are executed in the marketplace. |
|
(2) |
|
Fair value based upon management estimates, including forecasted forward NGL
prices. |
|
(3) |
|
Fair value based on forward NYMEX natural gas and light crude prices,
as applicable. |
|
(4) |
|
Average price of options based upon average strike price adjusted by average
premium paid or received. |
|
(5) |
|
Calls purchased for 2010 through 2012 represent offsetting positions for
calls sold. These offsetting positions were entered into by APL to limit the loss which
could be incurred if crude oil prices continued to rise. |
|
(6) |
|
Mmbtu represents million British Thermal Units. |
The fair value of the derivatives included in the Companys consolidated balance sheets is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Current portion of derivative asset |
|
$ |
88,960 |
|
|
$ |
152,727 |
|
Long-term derivative asset |
|
|
42,405 |
|
|
|
69,451 |
|
Current portion of derivative liability |
|
|
(46,570 |
) |
|
|
(73,776 |
) |
Long-term derivative liability |
|
|
(33,847 |
) |
|
|
(59,103 |
) |
|
|
|
|
|
|
|
Total Company net asset |
|
$ |
50,948 |
|
|
$ |
89,299 |
|
|
|
|
|
|
|
|
NOTE 11 FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company has established a hierarchy to measure its financial instruments at fair value
which requires it to maximize the use of observable inputs and minimize the use of unobservable
inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to
measure fair value:
|
Level 1 |
|
Unadjusted quoted prices in active markets for identical, unrestricted assets and
liabilities that the reporting entity has the ability to access at the measurement date. |
|
Level 2 |
|
Inputs other than quoted prices included within Level 1 that are observable for the
asset and liability or can be corroborated with observable market data for substantially the
entire contractual term of the asset or liability. |
|
Level 3 |
|
Unobservable inputs that reflect the entitys own assumptions about the assumption
market participants would use in the pricing of the asset or liability and are consequently
not based on market activity but rather through particular valuation techniques. |
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company uses a fair value methodology to value the assets and liabilities for its, AHDs
and APLs outstanding derivative contracts (see Note 10) and the Companys Supplemental Employment
Retirement Plan (SERP see Note 17). The Companys and APLs commodity hedges, with the
exception of APLs NGL fixed price swaps and NGL options, are calculated based on observable market
data related to the change in price of the underlying commodity and are therefore defined as Level
2 fair value measurements. The Companys, AHDs and APLs interest rate derivative contracts are
valued using a LIBOR rate-based forward price curve model and are therefore defined as Level 2 fair
value measurements. The Companys SERP is calculated based on observable actuarial inputs
developed by a third-party actuary and therefore is defined as a Level 2 fair value measurement,
while the asset related to the funding of the SERP is based on third-party financial statements and
is therefore also defined as a Level 2 fair value measurement. Valuations for APLs NGL fixed
price swaps are based on a forward price curve modeled on a regression analysis of
quoted price curves for NGLs for similar locations, and therefore are defined as Level 3 fair
value measurements. Valuations for APLs NGL options are based on forward price curves developed
by the related financial institution, and therefore are defined as Level 3 fair value measurements.
43
On June 30, 2009, APL changed the basis for its valuation of crude oil options. Previously,
APL utilized forward price curves developed by its derivative counterparties. Effective June 30,
2009, APL utilized crude oil option prices quoted from a public commodity exchange. With this
change in valuation basis, APL reclassified the inputs for the valuation of its crude oil options
from a Level 3 input to a Level 2 input. The change in valuation basis did not materially impact
the fair value of its derivative instruments on its consolidated statements of operations.
The following table represents the Companys assets and liabilities recorded at fair value as
of September 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
SERP liability
|
|
$ |
|
|
|
$ |
(3,587 |
) |
|
$ |
|
|
|
$ |
(3,587 |
) |
SERP asset funded in rabbi trust |
|
|
|
|
|
|
3,655 |
|
|
|
|
|
|
|
3,655 |
|
ATN commodity-based derivatives |
|
|
|
|
|
|
99,873 |
|
|
|
|
|
|
|
99,873 |
|
APL commodity-based derivatives |
|
|
|
|
|
|
(39,708 |
) |
|
|
1,834 |
|
|
|
(37,874 |
) |
Interest rate derivatives |
|
|
|
|
|
|
(11,051 |
) |
|
|
|
|
|
|
(11,051 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
49,182 |
|
|
$ |
1,834 |
|
|
$ |
51,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
APLs Level 3 fair value amount relates to its derivative contracts on NGL fixed price swaps
and crude oil options. The following table provides a summary of changes in fair value of APLs
Level 3 derivative instruments as of September 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed |
|
|
|
|
|
|
|
|
|
|
|
|
Price |
|
|
NGL Sales |
|
|
Crude Oil |
|
|
|
|
|
|
Swaps |
|
|
Options |
|
|
Options |
|
|
Total |
|
Balance December 31, 2008 |
|
$ |
1,509 |
|
|
$ |
12,316 |
|
|
$ |
(23,436 |
) |
|
$ |
(9,611 |
) |
New options contracts |
|
|
|
|
|
|
(2,896 |
) |
|
|
|
|
|
|
(2,896 |
) |
Cash settlements from unrealized gain
(loss)(1) |
|
|
(5,459 |
) |
|
|
(9,866 |
) |
|
|
(37,671 |
) |
|
|
(52,996 |
) |
Cash settlements from other
comprehensive income(1) |
|
|
5,453 |
|
|
|
|
|
|
|
11,618 |
|
|
|
17,071 |
|
Net change in unrealized gain (loss)(2) |
|
|
(2,265 |
) |
|
|
(1,084 |
) |
|
|
14,886 |
|
|
|
11,537 |
|
Deferred option premium recognition |
|
|
|
|
|
|
4,126 |
|
|
|
2,239 |
|
|
|
6,365 |
|
Net change in other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transfer to Level 2 |
|
|
|
|
|
|
|
|
|
|
32,364 |
|
|
|
32,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance September 30, 2009 |
|
$ |
(762 |
) |
|
$ |
2,596 |
|
|
$ |
|
|
|
$ |
1,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included within transmission, gathering and processing revenue on the Companys consolidated
statements of operations. |
|
(2) |
|
Included within loss on mark-to-market derivatives on the Companys consolidated statements
of operations. |
Other Financial Instruments
The estimated fair value of the Companys other financial instruments has been determined
based upon its assessment of available market information and valuation methodologies. However,
these estimates may
not necessarily be indicative of the amounts that the Company could realize upon the sale or
refinancing of such financial instruments.
44
The Companys other current assets and liabilities on its consolidated balance sheets are
financial instruments. The estimated fair values of these instruments approximate their carrying
amounts due to their short-term nature. The estimated fair values of the Companys debt at
September 30, 2009 and December 31, 2008, which consists principally of APLs term loan, ATN and
APLs Senior Notes and borrowings under the ATNs, AHDs and APLs credit facilities, were $2,047.9
million and $1,911.4 million, respectively, compared with the carrying amounts of $2,127.5 million
and $2,413.1 million, respectively. The Senior Notes were valued based upon recent trading
activity. The carrying value of outstanding borrowings under the credit facilities, which bear
interest at a variable interest rate, approximates their estimated fair value.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Company estimates the fair value of asset retirement obligations based on discounted cash
flow projections using numerous estimates, assumptions and judgments regarding such factors at the
date of establishment of an asset retirement obligation such as: amounts and timing of
settlements; the credit-adjusted risk-free rate of the Company; and estimated inflation rates (see
Note 8).
Information for assets that are measured at fair value on a nonrecurring basis for the three
and nine months ended September 30, 2009 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, 2009 |
|
|
September 30, 2009 |
|
|
|
Level 3 |
|
|
Total |
|
|
Level 3 |
|
|
Total |
|
Asset retirement obligations |
|
$ |
125 |
|
|
$ |
125 |
|
|
$ |
721 |
|
|
$ |
721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
125 |
|
|
$ |
125 |
|
|
$ |
721 |
|
|
$ |
721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 12 CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
In the ordinary course of its business operations, the Company has ongoing relationships with
several related entities:
Relationship with the Companys Sponsored Investment Partnerships. The Company conducts
certain activities through, and a substantial portion of its revenues are attributable to, the
Partnerships. The Company serves as general partner of the Partnerships and assumes customary
rights and obligations for the Partnerships. As the general partner, the Company is liable for the
Partnerships liabilities and can be liable to limited partners if it breaches its responsibilities
with respect to the operations of the Partnerships. The Company is entitled to receive management
fees, reimbursement for administrative costs incurred, and to share in the Partnerships revenue,
and costs and expenses according to the respective Partnership agreements.
Relationship with Resource America, Inc. The Company has two agreements that govern its
ongoing relationship with Resource America, Inc. (RAI), its former parent, that are still in
effect at September 30, 2009. These agreements are the tax matters agreement and the transition
services agreement. The tax matters agreement governs the respective rights, responsibilities and
obligations of the Company and RAI with respect to tax liabilities and benefits, tax attributes,
tax contests and other matters regarding income taxes, non-income taxes and related tax matters.
The transition services agreement governs the provision of support services by the Company to RAI
and by RAI to the Company, such general and administrative functions. The Company reimburses RAI
for various costs and expenses it incurs for these services on behalf of the Company, primarily
payroll and rent. For the three months ended September 30, 2009 and 2008, the Companys
reimbursements to RAI totaled $0.3 million and $0.3 million, respectively, and $0.8 million and
$0.7 million for the nine months ended September 30, 2009 and 2008, respectively. At September 30,
2009 and December 31, 2008, reimbursements to RAI totaling $0.2 million and $0.1 million,
respectively, which
remain to be settled between the parties, were reflected in the Companys consolidated balance
sheets as advances to/from affiliate.
45
Relationship with Laurel Mountain. Upon completion of the transaction with Laurel Mountain,
the Company entered into new gas gathering agreements with Laurel Mountain which superseded the
existing master natural gas gathering agreement and omnibus agreement between the Company and APL.
Under the new gas gathering agreements, the Company is obligated to pay Laurel Mountain all of the
gathering fees it collects from the Partnerships, which generally ranges from $0.35 per Mcf to the
amount of the competitive gathering fee (which is currently defined as 13% of the gross sales price
received for the partnerships gas) plus any excess amount of the gathering fees collected up to an
amount equal to approximately 16% of the natural gas sales price. The new gathering agreements
contain additional provisions which define certain obligations and options of each party to build
and connect newly drilled wells to any Laurel Mountain gathering system.
NOTE 13 COMMITMENTS AND CONTINGENCIES
General Commitments
The Company is the managing general partner of the Partnerships, and has agreed to indemnify
each investor partner from any liability that exceeds such partners share of Partnership assets.
Subject to certain conditions, investor partners in certain Partnerships have the right to present
their interests for purchase by the Company, as managing general partner. The Company is not
obligated to purchase more than 5% to 10% of the units in any calendar year. Based on past
experience, the management of the Company believes that any liability incurred would not be
material. The Company may be required to subordinate a part of its net partnership revenues from
the Partnerships to the benefit of the investor partners for an amount equal to at least 10% of
their subscriptions, determined on a cumulative basis, in accordance with the terms of the
partnership agreements. For the three and nine months ended September 30, 2009, $1.4 million and
$2.3 million, respectively, of the Companys net revenues were subordinated, which reduced its cash
distributions received from the investment partnerships for the respective periods. No
subordination of the Companys net revenues was required for the three and nine months ended
September 30, 2008 with regard to the Partnerships.
The Company is party to employment agreements with certain executives that provide
compensation and certain other benefits. The agreements also provide for severance payments under
certain circumstances.
As of September 30, 2009, the Company and its subsidiaries are committed to expend
approximately $17.8 million on pipeline extensions, compressor station upgrades, and processing
facility upgrades.
Legal Proceedings
The Company is a party to various routine legal proceedings arising out of the ordinary course
of its business. Management believes that none of these actions, individually or in the aggregate,
will have a material adverse effect on the Companys financial condition or results of operations.
Following the announcement of the merger agreement on April 27, 2009 between the Company and
Atlas Energy Resources, the following actions were filed in Delaware Chancery Court purporting to
challenge the Merger:
|
|
|
Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09); |
|
|
|
|
Operating Engineers Constructions Industry and Miscellaneous Pension
Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed
5/13/09); |
46
|
|
|
Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09); |
|
|
|
|
Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and |
|
|
|
|
Montgomery County Employees Retirement Fund v. Atlas Energy
Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09). |
On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits,
renaming the action In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and
appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous
Pension Fund and Montgomery County Employees Retirement Fund. Plaintiffs filed a Verified
Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On
July 27, 2009, the Chancery Court granted the parties scheduling stipulation, setting a
preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of
fiduciary duty in connection with the Merger agreement, including allegations of inadequate
disclosures in connection with the unitholder vote on the Merger, and seeks monetary damages or
injunctive relief, or both. On August 7, 2009, plaintiffs advised the court by letter that they are
not pursuing their motion for preliminary injunction and requested that the preliminary injunction
hearing date be removed from the courts calendar. Around that time, plaintiffs advised counsel
for the defendants that they intended to continue to pursue the case after the Merger as a claim
for monetary damages. The Chancery Court approved the briefing schedule in mid-September and the
defendants filed a brief in support of their motion to dismiss on October 16, 2009. Predicting the
outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a
material adverse effect on the operations of the combined company. Based on the facts known to
date, the defendants believe that the claims asserted against them in this lawsuit are without
merit, and intend to defend themselves vigorously against the claims.
In June 2008, the Companys wholly-owned subsidiary, Atlas America, LLC, was named as a
co-defendant in the matter captioned CNX Gas Company, LLC (CNX) v. Miller Petroleum, Inc.
(Miller), et al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX
alleges that Miller breached a contract to assign to CNX certain leasehold rights (Leases)
representing approximately 30,000 acres in Campbell County, Tennessee and that Atlas America, LLC
and another defendant, Wind City Oil & Gas, LLC, interfered with the closing of this assignment on
June 6, 2008. ATN purchased the Leases from Miller for approximately $19.1 million. On December
15, 2008, the Chancery Court dismissed the matter in its entirety, holding that there had been no
breach of the contract by Miller and, therefore, that Atlas America, LLC could not have tortuously
interfered with the contract. The Chancery Court dismissed all claims against Atlas America, LLC;
however, CNX has appealed this decision.
NOTE 14 INCOME TAXES
The Company accounts for income taxes under the asset and liability method pursuant to
prevailing accounting literature. Under such literature, deferred income taxes 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 net operating loss
and 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 of any tax rate change on deferred taxes is recognized in
the period that includes the enactment date of the tax rate change. Realization of deferred tax
assets is assessed and, if not more likely than not, a valuation allowance is recorded to write
down the deferred tax assets to their net realizable value. As of September 30, 2009 and December
31, 2008, the Company determined that no valuation allowance was necessary. In conjunction with
the Merger, the Company recognized a reduction of its deferred tax liability of $179.4 million,
related to book and tax basis differences in the Companys investment in ATN.
47
The Company recognizes the financial statement benefit of a tax position after determining
that the relevant tax authority would more likely than not sustain the position following an audit.
For tax positions
meeting a more-likely-than-not threshold, the amount recognized in the financial statements is
the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate
settlement with the relevant tax authority. The Company had applied this methodology to all tax
positions for which the statute of limitation remains open, and there were no additions, reductions
or settlements in unrecognized tax benefits during the three and nine months ended September 30,
2009 and 2008. The Company has no material uncertain tax positions at September 30, 2009.
The Company is subject to income taxes in the U.S. federal jurisdiction and various states.
Tax regulations within each jurisdiction are subject to the interpretations of the related tax laws
and regulations and require significant judgment to apply. With few exceptions, the Company is no
longer subject to U.S. federal, state, and local, or non-U.S. income tax examinations by tax
authorities for the years before 2005. The Companys policy is to reflect interest and penalties
related to uncertain tax positions as part of the income tax expense, when and if they become
applicable.
NOTE 15 ISSUANCES OF SUBSIDIARY UNITS
The Company recognizes gains on its subsidiaries equity transactions as a credit to equity
rather than as income. These gains represent the Companys portion of the excess net offering
price per unit of each of its subsidiarys units to the book carrying amount per unit.
In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of
$6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital
contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in the
APL. In addition, APL issued warrants granting investors in its private placement the right to
purchase an additional 2,689,765 common units at a price of $6.35 per unit for a period of two
years following the issuance of the original common units. APL utilized the net proceeds from the
common unit offering to repay a portion of its indebtedness under its senior secured term loan (see
Note 9), and will make similar repayments with net proceeds from future exercises of the warrants.
The common units and warrants sold by APL in the August 2009 private placement are subject to
a registration rights agreement entered into in connection with the transaction. The registration
rights agreement required APL to (a) file a registration statement with the Securities and Exchange
Commission for the privately placed common units and those underlying the warrants by September 21,
2009 and (b) cause the registration statement to be declared effective by the Securities and
Exchange Commission by November 18, 2009. APL filed a registration statement with the Securities
and Exchange Commission in satisfaction of the registration requirements of the registration rights
agreement on September 3, 2009, and the registration statement was declared effective on October
14, 2009.
In June 2008, APL sold 5,750,000 common limited partner units in a public offering at a price
of $37.52 per unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, the
Company purchased 308,109 AHD common units and 1,112,000 APL common limited partner units through a
private placement transaction at a price of $32.50 and $36.02 per unit, respectively, for net
proceeds of approximately $10.0 million and $40.1 million, respectively. AHD utilized the net
proceeds from the sale to purchase 278,000 common units of APL, which in turn utilized the proceeds
to partially fund the early termination of certain derivative agreements (see Note 10).
In May 2008, ATN sold 2,070,000 of its Class B common units in a public offering yielding net
proceeds of approximately $82.5 million. The net proceeds were used to repay a portion of ATNs
outstanding balance under its revolving credit facility. A gain of $17.7 million, net of an income
tax provision of $8.7 million, in accordance with prevailing accounting literature was recorded in
consolidated equity as an increase to paid-in capital as well as a corresponding adjustment of
$26.4 million to non-controlling interest, during the year ended December 31, 2008.
48
NOTE 16 CASH DISTRIBUTIONS
Prior to the Merger, ATN was required to distribute, within 45 days after the end of each
quarter, all of its available cash (as defined in its limited liability company agreement) for that
quarter to its Class A and Class B common unitholders in accordance with their respective
percentage interests. Effective April 1, 2009, ATN suspended further distributions due to the
announcement of its intent to merge with the Company (see Note 3).
Atlas Pipeline Partners Cash Distributions. APL is required to distribute, within 45 days
after the end of each quarter, all of its available cash (as defined in its partnership agreement)
for that quarter to its common unitholders and AHD, as general partner. If APLs common unit
distributions in any quarter exceed specified target levels, AHD will receive between 15% and 50%
of such distributions in excess of the specified target levels. Common unit and General Partner
distributions declared by APL for the period from January 1, 2008 through September 30, 2009 were
as follows (in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
APL Cash |
|
|
Total APL Cash |
|
|
Total APL Cash |
|
|
|
|
|
Distribution |
|
|
Distribution |
|
|
Distribution |
|
Date Cash |
|
|
|
per Common |
|
|
to Common |
|
|
to the |
|
Distribution |
|
For Quarter |
|
Limited |
|
|
Limited |
|
|
General |
|
Paid |
|
Ended |
|
Partner Unit |
|
|
Partners |
|
|
Partner |
|
February 14, 2008 |
|
December 31, 2007 |
|
$ |
0.93 |
|
|
$ |
36,051 |
|
|
$ |
5,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 15, 2008 |
|
March 31, 2008 |
|
$ |
0.94 |
|
|
$ |
36,450 |
|
|
$ |
7,891 |
|
August 14, 2008 |
|
June 30, 2008 |
|
$ |
0.96 |
|
|
$ |
44,096 |
|
|
$ |
9,308 |
|
November 14, 2008 |
|
September 30, 2008 |
|
$ |
0.96 |
|
|
$ |
44,105 |
|
|
$ |
9,312 |
|
February 13, 2009 |
|
December 31, 2008 |
|
$ |
0.38 |
|
|
$ |
17,463 |
|
|
$ |
2,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 13, 2009 |
|
March 31, 2009 |
|
$ |
0.15 |
|
|
$ |
7,147 |
|
|
$ |
1,010 |
|
APL did not declare a cash distribution for the quarters ended September 30, 2009 and June 30,
2009. On May 29, 2009, APL entered into an amendment to its senior secured credit facility (see
Note 9), which, among other things, requires that it pay no cash distributions during the remainder
of the year ended December 31, 2009 and allows it to pay cash distributions beginning January 1,
2010 if its senior secured leverage ratio is above certain thresholds and it has minimum liquidity
(both as defined in the credit agreement) of at least $50.0 million.
In connection with APLs acquisition of control of the Chaney Dell and Midkiff/Benedum
systems, AHD, which holds all of the incentive distribution rights in APL, agreed to allocate up to
$3.75 million of its incentive distribution rights per quarter back to APL. AHD also agreed that
the resulting allocation of incentive distribution rights back to APL would be after AHD receives
the initial $7.0 million per quarter of incentive distribution rights.
49
Atlas Pipeline Holdings Cash Distributions. AHD has a cash distribution policy under which it
distributes, within 50 days after the end of each quarter, all of its available cash (as defined in
its partnership agreement) for that quarter to its common unitholders. Distributions declared by
AHD for the period from January 1, 2008 through September 30, 2009 were as follows (in thousands
except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash |
|
Date Cash |
|
|
|
Cash Distribution per |
|
|
Distribution to the |
|
Distribution Paid or |
|
For Quarter |
|
Common Limited |
|
|
Company |
|
Payable |
|
Ended |
|
Partner Unit |
|
|
(in thousands) |
|
February 19, 2008 |
|
December 31, 2007 |
|
$ |
0.34 |
|
|
$ |
5,950 |
|
|
|
|
|
|
|
|
|
|
|
|
May 20, 2008 |
|
March 31, 2008 |
|
$ |
0.43 |
|
|
$ |
7,525 |
|
August 19, 2008 |
|
June 30, 2008 |
|
$ |
0.51 |
|
|
$ |
9,082 |
|
November 19, 2008 |
|
September 30, 2008 |
|
$ |
0.51 |
|
|
$ |
9,082 |
|
February 19, 2009 |
|
December 31, 2008 |
|
$ |
0.06 |
|
|
$ |
1,068 |
|
There was no distribution declared by AHD for the quarters ended September 30, 2009, June 30,
2009 and March 31, 2009. On June 1, 2009, AHD entered into an amendment to its credit facility
agreement, which, among other changes, prohibited it from paying any cash distributions on its
equity while the credit facility is in effect (see Note 9).
NOTE 17 BENEFIT PLANS
Incentive Bonus Plan
The Companys shareholders approved an Incentive Bonus Plan (Bonus Plan) for the benefit of
its senior executive officers. The total amount of cash bonus awards to be made under the Bonus
Plan for any plan year will be based on performance goals related to objective business criteria
for such year. For any plan year, the Companys performance must achieve levels targeted by the
Companys compensation committee, as established at the beginning of each year, for any bonus
awards to be made. Aggregate bonus awards to all participants under the Bonus Plan may not exceed a
limit as set by the compensation committee. The compensation committee has the authority to reduce
the total amount of bonus awards, if any, to be made to the eligible employees for any plan year
based on its assessment of personal performance or other factors as the Board may determine to be
relevant or appropriate. The compensation committee may permit participants to elect to defer
awards. For the three month periods ended September 30, 2009 and 2008, the Company recognized $1.7
million and $0.9 million, respectively, of estimated expenses under the plan and $5.2 million and
$3.7 million for the nine month periods ended September 30, 2009 and 2008, respectively.
Stock Incentive Plans
The Company has a Stock Incentive Plan (the 2004 Plan) which authorizes the granting of up
to 4,499,999 shares of the Companys common stock to employees, affiliates, consultants and
directors of the Company in the form of incentive stock options (ISOs), non-qualified stock
options, stock appreciation rights (SARs), restricted stock and deferred units. The Company also
has a 2009 Stock Incentive Plan (the 2009 Plan and together with the 2004 Plan, the Plans)
which authorizes the granting of up to 4,800,000 shares of the Companys common stock to employees,
affiliates, consultants and directors of the Company in the form of ISOs, non-qualified stock
options, SARs, restricted stock, restricted stock units and deferred units. No awards have been
issued under the 2009 Plan. Generally, the approach to accounting in requires all share-based
payments to employees, including grants of employee stock options, to be recognized in the
financial statements based on their fair values.
Stock Options. Options under the 2004 Plan become exercisable as to 25% of the optioned shares
each year after the date of grant, except options totaling 1,687,500 shares awarded in fiscal 2005
to Messrs. Edward Cohen and Jonathan Cohen, which are immediately exercisable, and expire not later
than ten years after the date of grant. Compensation cost is recorded on a straight-line basis. The
Company issues new shares when stock options are exercised or units are converted to shares. Under
the 2004 Plan, there were 6,411 and 19,067 options exercised during the three and nine months ended
September 30, 2009, respectively. Under the 2004 Plan, 28,155 options were exercised during the three
and nine months ended September 30, 2008, respectively.
50
The following tables set forth the 2004 Plan activity for the three and nine months ended
September 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Unit |
|
|
Exercise |
|
|
of Unit |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
Outstanding, beginning of period |
|
|
3,537,132 |
|
|
$ |
16.96 |
|
|
|
3,540,380 |
|
|
$ |
16.89 |
|
Granted |
|
|
7,500 |
|
|
$ |
19.75 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(6,411 |
) |
|
$ |
11.32 |
|
|
|
(28,155 |
) |
|
$ |
11.32 |
|
Forfeited |
|
|
(30,000 |
) |
|
$ |
35.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(1)(2) |
|
|
3,508,221 |
|
|
$ |
16.81 |
|
|
|
3,512,225 |
|
|
$ |
16.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
494 |
|
|
|
|
|
|
$ |
983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Unit |
|
|
Exercise |
|
|
of Unit |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
Outstanding, beginning of period |
|
|
3,495,351 |
|
|
$ |
16.97 |
|
|
|
2,715,380 |
|
|
$ |
12.10 |
|
Granted |
|
|
107,500 |
|
|
$ |
13.80 |
|
|
|
825,000 |
|
|
$ |
32.68 |
|
Exercised(3) |
|
|
(19,067 |
) |
|
$ |
11.32 |
|
|
|
(28,155 |
) |
|
$ |
11.32 |
|
Cancelled |
|
|
(15,187 |
) |
|
$ |
11.32 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(60,376 |
) |
|
$ |
23.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(1)(2) |
|
|
3,508,221 |
|
|
$ |
16.81 |
|
|
|
3,512,225 |
|
|
$ |
16.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable, end of period(4) |
|
|
2,745,408 |
|
|
$ |
13.30 |
|
|
|
2,350,298 |
|
|
$ |
11.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
2,388 |
|
|
|
|
|
|
$ |
2,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for grant at September 30, 2009 |
|
|
761,562 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted average remaining contractual life for outstanding options at September 30, 2009 was 6.7
years. |
|
(2) |
|
The aggregate intrinsic value of options outstanding at September 30, 2009 was approximately $40.6 million. |
|
(3) |
|
The aggregate intrinsic values of options exercised were approximately $0.1 million during the nine months
ended September 30, 2009, and $0.8 million during the three and nine months ended September 30, 2008. |
|
(4) |
|
The weighted average outstanding contractual life of exercisable options at September 30, 2009 is 6.0
years. |
51
The Company used the Black-Scholes option pricing model to estimate the weighted average fair
value of options granted. The following weighted average assumptions were used for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected dividend yield |
|
|
|
|
|
|
|
|
|
|
0.6 |
% |
|
|
0.4 |
% |
Expected stock price volatility |
|
|
44 |
% |
|
|
|
|
|
|
37 |
% |
|
|
33 |
% |
Risk-free interest rate |
|
|
3.1 |
% |
|
|
|
|
|
|
2.3 |
% |
|
|
2.6 |
% |
Expected term (in years) |
|
|
6.88 |
|
|
|
|
|
|
|
6.29 |
|
|
|
6.25 |
|
Fair value of stock options granted |
|
$ |
9.80 |
|
|
|
|
|
|
$ |
5.23 |
|
|
$ |
11.75 |
|
Deferred Units and Restricted Shares
Under the 2004 Plan, non-employee directors of the Company are awarded deferred units that
vest over a four-year period. Each unit represents the right to receive one share of the Companys
common stock upon vesting. Units will vest sooner upon a change in control of the Company or death
or disability of a grantee. The fair value of the grants is based on the closing stock price on the
grant date, and is being charged to operations over the requisite service periods using a
straight-line attribution method. Upon termination of service by a grantee, all unvested units are
forfeited.
Restricted shares are granted from time to time to employees of the Company. Each unit
represents the right to receive one share of the Companys common stock upon vesting. The shares
are issued to the participant, held in escrow, and paid to the participant upon vesting. The units
vest one-fourth at each anniversary date over a four-year service period. The fair value of the
grant is based on the closing price on the grant date, and is being expensed over the requisite
service period using a straight-line attribution method.
The following table summarizes the activity of deferred and restricted units for the three and
nine months ended September 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
Number |
|
|
Grant Date |
|
|
Number |
|
|
Grant Date |
|
|
|
of Units |
|
|
Fair Value |
|
|
of Units |
|
|
Fair Value |
|
Non-vested shares outstanding,
beginning of period |
|
|
12,534 |
|
|
$ |
23.80 |
|
|
|
12,364 |
|
|
$ |
23.53 |
|
Granted |
|
|
24,663 |
|
|
$ |
22.10 |
|
|
|
396 |
|
|
$ |
37.69 |
|
Matured(1) |
|
|
(5,123 |
) |
|
$ |
22.43 |
|
|
|
(248 |
) |
|
$ |
20.14 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares outstanding,
end of period(2) |
|
|
32,074 |
|
|
$ |
22.71 |
|
|
|
12,512 |
|
|
$ |
24.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
93 |
|
|
|
|
|
|
$ |
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
Number |
|
|
Grant Date |
|
|
Number |
|
|
Grant Date |
|
|
|
of Units |
|
|
Fair Value |
|
|
of Units |
|
|
Fair Value |
|
Non-vested shares outstanding,
beginning of period |
|
|
12,512 |
|
|
$ |
24.05 |
|
|
|
21,114 |
|
|
$ |
14.61 |
|
Granted |
|
|
29,468 |
|
|
$ |
21.04 |
|
|
|
1,920 |
|
|
$ |
46.87 |
|
Matured(1) |
|
|
(9,906 |
) |
|
$ |
19.43 |
|
|
|
(10,522 |
) |
|
$ |
9.27 |
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares outstanding, end of
period(2) |
|
|
32,074 |
|
|
$ |
22.71 |
|
|
|
12,512 |
|
|
$ |
24.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
144 |
|
|
|
|
|
|
$ |
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The intrinsic values for phantom unit awards vested during the three months
ended at September 30, 2009 were $0.1 million and $0.2 million and $0.5
million during the nine months ended September 30, 2009 and 2008,
respectively. |
|
(2) |
|
The aggregate intrinsic value for phantom unit awards outstanding at
September 30, 2009 was $0.9 million. |
At September 30, 2009, the Company had unamortized compensation expense related to its
unvested portion of the options and units of $6.8 million that the Company expects to recognize
over the next four years.
Employee Stock Ownership Plan
The Company has an Employee Stock Ownership Plan (ESOP), which is a qualified
non-contributory retirement plan, that was established to acquire shares of the Companys common
stock for the benefit of all employees who are 21 years of age or older and have completed 1,000
hours of service. Contributions to the ESOP are made at the discretion of the Companys Board of
Directors. Any dividends which may be paid on allocated shares will reduce retained earnings;
dividends on unearned ESOP shares will be used to service the related debt.
The common stock purchased by the ESOP is held by the ESOP trustee in a suspense account. On
an annual basis, a portion of the common stock will be released from the suspense account and
allocated to participating employees. As of September 30, 2009, there were 767,378 shares allocated
to participants and 49,861 shares which are unallocated. All unallocated shares were allocated to
participating employees at the end of the ESOPs fiscal year on September 30, 2009. Participants
will receive shares upon vesting, which occurs over a five year period, beginning after the
participants second year of service. The fair value of unearned ESOP shares was $1.3 million at
September 30, 2009.
53
Supplemental Employment Retirement Plan (SERP)
The Company entered into an employment agreement with its Chairman of the Board, Chief
Executive Officer and President, Edward E. Cohen, pursuant to which the Company has agreed to
provide him with a SERP and with certain financial benefits upon termination of his employment.
Under the SERP, Mr. Cohen
will be paid an annual benefit equal to the product of (a) 6.5% multiplied by, (b) his base
salary at the time of his retirement, death or other termination of employment with the Company,
multiplied by, (c) the amount of years he shall be employed by the Company commencing upon the
effective date of the SERP agreement, limited to an annual maximum benefit of 65% of his final base
salary and a minimum of 26% of his final base salary. During the three months ended September 30,
2009 and 2008, expense recognized with respect to this commitment was $0.2 million and $0.4
million, respectively, and $0.5 million and $1.1 million during the nine months ended September 30,
2009 and 2008, respectively.
During the nine months ended September 30, 2009, the Company funded $3.2 million of the
outstanding liability with a financial institution in a rabbi trust, which is included in other
assets on the Companys consolidated balance sheet. As of September 30, 2009, the actuarial
present value of the expected postretirement obligation due under this the SERP was $3.6 million,
which is included in other long-term liabilities on the Companys consolidated balance sheets.
The following table provides information about amounts recognized in the Companys
consolidated balance sheets at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Other liabilities |
|
$ |
(3,587 |
) |
|
$ |
(3,209 |
) |
Accumulated other comprehensive income |
|
|
187 |
|
|
|
255 |
|
Deferred income tax asset |
|
|
110 |
|
|
|
150 |
|
|
|
|
|
|
|
|
Net amount recognized |
|
$ |
(3,290 |
) |
|
$ |
(2,804 |
) |
|
|
|
|
|
|
|
The estimated amount that will be amortized from accumulated other comprehensive income into
expense for the year ended December 31, 2009 is $0.1 million.
Amended and Restated Atlas Energy, Inc. Assumed Long-Term Incentive Plan
In connection with the Merger, the Company agreed to assume ATNs Long-Term Incentive Plan
(the Assumed LTIP), which applies to all of ATNs awards that were outstanding at the time of the
Merger. Under the Assumed LTIP, each outstanding unit option, phantom unit and restricted unit
granted under the ATNs previous plan was converted to an equivalent stock option, phantom share or
restricted share of the Companys at a ratio of 1.0 unit to 1.16 common shares.
Following the consummation of the Merger, no new grant awards will be issued pursuant to the
Assumed LTIP. All of the terms related to the previous LTIP remain unchanged and no new grant
awards will be issued pursuant to the Assumed LTIP. Awards granted after 2006 vest 25% after three
years and 100% upon the four-year anniversary of grant, except for awards to ATNs former board
members which vest 25% per year over four years. Awards granted in 2006 vest 25% per year over four
years. Upon termination of service by a grantee, all unvested awards are forfeited. A restricted
stock grant or phantom stock grant entitles a grantee to receive a share of the Companys common
stock upon vesting of the grant or, at the discretion of the Companys compensation committee, cash
equivalent to the then fair market value of its common share.
Restricted Stock and Phantom Units. Under the Assumed LTIP, 28,523 restricted and phantom
units were awarded during the period from January 1, 2009 to September 29, 2009. During the nine
months ended September 30, 2008, 35,793 restricted units were awarded under the Assumed LTIP. The
fair value of the grants is based on the closing unit price on the grant date, and is being charged
to operations over the requisite service periods using a straight-line attribution method.
54
The following table summarizes the activity of restricted stock and phantom units for the
period from January 1, 2009 to September 30, 2009 and lists the number and average grant date fair
value of the Companys common shares underlying the converted phantom and restricted stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Units |
|
|
Fair Value |
|
Non-vested units outstanding at December 31, 2008 |
|
|
768,829 |
|
|
$ |
23.86 |
|
Granted |
|
|
28,523 |
|
|
|
16.48 |
|
Vested |
|
|
(13,073 |
) |
|
|
21.70 |
|
Forfeited |
|
|
(46,000 |
) |
|
|
31.12 |
|
|
|
|
|
|
|
|
Non-vested units outstanding at September 29, 2009 |
|
|
738,279 |
|
|
|
23.16 |
|
Units converted on September 29, 2009(1) |
|
|
118,125 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
Non-vested units outstanding at September 30, 2009 |
|
|
856,404 |
|
|
$ |
19.97 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Converted at a ratio of 1.0 ATN common unit to 1.16 common shares of the Company. |
Unit Options. There were 5,000 unit options granted during the period from January 1, 2009 to
September 30, 2009. During the nine months ended September 30, 2008, 14,000 unit options were
awarded under the predecessor ATN LTIP. Option awards expire 10 years from the date of grant and
were generally granted with an exercise price equal to the market price of ATNs common units at
the date of grant. The Company uses the Black-Scholes option pricing model to estimate the weighted
average fair value per option granted.
The following table sets forth option activity for the period from January 1, 2009 to
September 30, 2009 and lists the number of the ATN class B units prior to September 29, 2009, the
number of the Companys common shares subsequent to the Merger and the weighted average exercise
price underlying the converted stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Remaining |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Contractual |
|
|
Intrinsic |
|
|
|
|
|
|
|
Exercise |
|
|
Term |
|
|
Value |
|
|
|
Units |
|
|
Price |
|
|
(in years) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008 |
|
|
1,902,902 |
|
|
$ |
24.17 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
5,000 |
|
|
|
25.78 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited or expired |
|
|
(123,600 |
) |
|
|
31.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 29, 2009 |
|
|
1,784,302 |
|
|
$ |
23.64 |
|
|
|
7.34 |
|
|
|
|
|
Stock options converted on
September 29, 2009 |
|
|
285,488 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested stock options
outstanding at September 30,
2009 |
|
|
2,069,790 |
|
|
$ |
20.36 |
|
|
|
7.34 |
|
|
$ |
14,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55
The following tables summarize information about unit options outstanding and exercisable at
September 30, 2009 and list the number of the Companys common shares subsequent to the Merger and
the weighted average exercise price underlying the converted stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number of |
|
|
Remaining |
|
|
Average |
|
|
Number of |
|
|
Average |
|
Range of |
|
Shares |
|
|
Contractual |
|
|
Exercise |
|
|
Shares |
|
|
Exercise |
|
Exercise Prices |
|
Outstanding |
|
|
Life in Years |
|
|
Price |
|
|
Exercisable |
|
|
Price |
|
$21.00 - 25.18 |
|
|
1,635,002 |
|
|
|
7.1 |
|
|
$ |
22.60 |
|
|
|
280,314 |
|
|
$ |
21.00 |
|
$30.24 - 35.00 |
|
|
141,800 |
|
|
|
7.8 |
|
|
$ |
34.78 |
|
|
|
|
|
|
|
|
|
$37.79 and above |
|
|
7,500 |
|
|
|
8.3 |
|
|
$ |
39.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,784,302 |
|
|
|
7.34 |
|
|
$ |
23.64 |
|
|
|
280,314 |
|
|
$ |
21.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options
converted on September 29, 2009(1) |
|
|
285,488 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
44,850 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Converted stock options at September 30, 2009 |
|
|
2,069,790 |
|
|
|
7.34 |
|
|
$ |
20.38 |
|
|
|
325,164 |
|
|
$ |
18.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Converted at a ratio of 1.0 ATN common unit to 1.16 common shares of the Company. |
The Company recognized $0.4 million and $1.4 million in compensation expense related to the
Assumed LTIP restricted stock units, phantom units and unit options for the three months ended
September 30, 2009 and 2008, respectively. The Company recognized $3.4 million and $4.0 million of
compensation expense related to the Assumed LTIP for the nine months ended September 30, 2009 and
2008, respectively. ATN paid $0.4 million with respect to distribution equivalent rights (DER)
for the three months ended September 30, 2008, and $0.4 million and $1.0 million for the nine
months ended September 30, 2009 and 2008, respectively. These amounts were recorded as a reduction
of members equity on the Companys consolidated balance sheet during the respective period. At
September 30, 2009, the Company had approximately $8.8 million of unrecognized compensation expense
related to the unvested portion of the restricted shares, phantom shares and stock options.
AHD Long-Term Incentive Plan
The Board of Directors of AHD approved and adopted AHDs Long-Term Incentive Plan (AHD
LTIP), which provides performance incentive awards to officers, employees and board members and
employees of its affiliates, consultants and joint-venture partners (collectively, the
Participants) who perform services for AHD. The AHD LTIP is administered by a committee (the
AHD LTIP Committee), appointed by AHDs board. Under the AHD LTIP, phantom units and/or unit
options may be granted, at the discretion of the AHD LTIP Committee, to all or designated
Participants, at the discretion of the AHD LTIP Committee. The AHD LTIP Committee may grant such
awards of either phantom units or unit options for an aggregate of 2,100,000 common limited partner
units. At September 30, 2009, AHD had 1,136,800 phantom units and unit options outstanding under
the AHD LTIP, with 962,650 phantom units and unit options available for grant.
AHD Phantom Units. A phantom unit entitles a Participant to receive a common unit of AHD,
without payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the
AHD LTIP Committee, cash equivalent to the then fair market value of a common limited partner unit
of AHD. In tandem with phantom unit grants, the AHD LTIP Committee may grant a Participant a
distribution equivalent right (DER), which is the right to receive cash per phantom unit in an
amount equal to, and at the same time as, the cash distributions AHD makes on a common unit during
the period such phantom unit is outstanding. The AHD LTIP Committee will determine the vesting
period for phantom units. Through September 30, 2009, phantom units granted under the AHD LTIP
generally will vest 25% three years from the date of grant and 100% four years from the date of
grant. The vesting of awards may also be contingent upon the attainment of predetermined
performance targets, which could increase or decrease the actual award settlement, as determined by
the AHD LTIP Committee, although no awards currently outstanding contain any such provision. Awards
will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. Of the
phantom units outstanding under the AHD LTIP at September 30, 2009, 44,550 units will vest within
the following twelve months. All phantom units outstanding under the AHD LTIP at September 30,
2009 include DERs granted to the Participants by the AHD LTIP Committee. The amount paid with
respect to AHDs LTIP DERs was $0.1 million for the three months ended September 30, 2008, and
$14,000 and $0.3 million for the nine months ended September 30, 2009 and 2008, respectively. No
DER payments were made during the three months ended September 30, 2009. These amounts were
recorded as an adjustment of non-controlling interests on the Companys consolidated balance sheet.
56
The following table sets forth the AHD LTIP phantom unit activity for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period |
|
|
181,300 |
|
|
|
225,475 |
|
|
|
226,300 |
|
|
|
220,825 |
|
Granted(1) |
|
|
500 |
|
|
|
|
|
|
|
500 |
|
|
|
4,650 |
|
Matured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
(45,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(2) |
|
|
181,800 |
|
|
|
225,475 |
|
|
|
181,800 |
|
|
|
225,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
295 |
|
|
$ |
354 |
|
|
$ |
277 |
|
|
$ |
1,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation
expense and do not represent exercise prices to be paid by the recipient, were $3.40 for the three and nine months ended
September 30, 2009, and $32.28 for the nine months ended September 30, 2008. There were no grants awarded for the three months
ended September 30, 2008. |
|
(2) |
|
The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2009 was $0.7 million. |
At September 30, 2009, AHD had approximately $1.0 million of unrecognized compensation
expense related to unvested phantom units outstanding under AHDs LTIP based upon the fair value of
the awards.
AHD Unit Options. A unit option entitles a Participant to receive a common unit of AHD upon
payment of the exercise price for the option after completion of vesting of the unit option. The
exercise price of the unit option may be equal to or more than the fair market value of AHDs
common unit as determined by the AHD LTIP Committee on the date of grant of the option. The AHD
LTIP Committee also shall determine how the exercise price may be paid by the Participant. The AHD
LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards
expire 10 years from the date of grant. Through September 30, 2009, unit options granted under the
AHD LTIP generally will vest 25% three years from the date of grant and 100% four years from the
date of grant. The vesting of awards may also be contingent upon the attainment of predetermined
performance targets, which could increase or decrease the actual award settlement, as determined by
AHDs LTIP Committee, although no awards currently outstanding contain any such provision. Awards
will automatically vest upon a change of control of AHD, as defined in the AHD LTIP. There are
213,750 unit options outstanding under the AHD LTIP at September 30, 2009 that will vest within the
following twelve months. The following table sets forth the AHD LTIP unit option activity for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Unit |
|
|
Exercise |
|
|
of Unit |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period |
|
|
955,000 |
|
|
$ |
20.54 |
|
|
|
1,215,000 |
|
|
$ |
22.56 |
|
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Matured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(1)(2) |
|
|
955,000 |
|
|
$ |
20.54 |
|
|
|
1,215,000 |
|
|
$ |
22.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable, end of period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
222 |
|
|
|
|
|
|
$ |
309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Unit |
|
|
Exercise |
|
|
of Unit |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
Outstanding, beginning of period |
|
|
1,215,000 |
|
|
$ |
22.56 |
|
|
|
1,215,000 |
|
|
$ |
22.56 |
|
Granted |
|
|
100,000 |
|
|
$ |
3.24 |
|
|
|
|
|
|
|
|
|
Matured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(360,000 |
) |
|
$ |
22.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(1)(2) |
|
|
955,000 |
|
|
$ |
20.54 |
|
|
|
1,215,000 |
|
|
$ |
22.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable, end of period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
(income) recognized (in thousands) |
|
$ |
(129 |
) |
|
|
|
|
|
$ |
928 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted average remaining contractual lives for outstanding options at September 30, 2009 were 7.3 years. |
|
(2) |
|
The intrinsic value of options outstanding at September 30, 2009 was $0.1 million. |
At September 30, 2009, AHD had approximately $0.7 million of unrecognized compensation expense
related to unvested unit options outstanding under AHDs LTIP based upon the fair value of the
awards.
AHD used the Black-Scholes option pricing model to estimate the weighted average fair value of
options granted. The following weighted average assumptions were used for the period indicated:
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, 2009 |
|
Expected dividend yield |
|
|
7.0 |
% |
Expected stock price volatility |
|
|
40 |
% |
Risk-free interest rate |
|
|
2.3 |
% |
Expected term (in years) |
|
|
6.9 |
|
APL Long-Term Incentive Plan
APL has a Long-Term Incentive Plan (APL LTIP), in which officers, employees and non-employee
managing board members of the General Partner and employees of the General Partners affiliates and
consultants are eligible to participate. The APL LTIP is administered by a committee (the APL
LTIP Committee) appointed by AHDs managing board. The APL LTIP Committee may make awards of
either phantom units or unit options for an aggregate of 435,000 common units.
58
APL Phantom Units. A phantom unit entitles a grantee to receive a common unit, without
payment of an exercise price, upon vesting of the phantom unit or, at the discretion of the APL
LTIP Committee, cash equivalent to the fair market value of an APL common unit. In addition, the
APL LTIP Committee may grant a participant a DER, which is the right to receive cash per phantom
unit in an amount equal to, and at the same time as, the cash distributions APL makes on a common
unit during the period the phantom unit is outstanding. A unit option entitles the grantee to
purchase APLs common limited partner units at an exercise price determined by the APL LTIP
Committee at its discretion. The APL LTIP Committee also has discretion to determine how the
exercise price may be paid by the participant. Except for phantom units awarded to non-employee
managing board members of AHD, the APL LTIP Committee will determine the vesting period for phantom
units and the exercise period for options. Through September 30, 2009, phantom units granted under
the APL LTIP generally had vesting periods of four years. The vesting of awards may also be
contingent upon the attainment of predetermined performance targets, which could increase or
decrease the actual award settlement, as determined by the APL LTIP Committee, although no awards
currently outstanding contain any such provision. Phantom units awarded to non-employee managing
board members will vest over a four year period. Awards will automatically vest upon a change of
control, as defined in the APL LTIP. Of the units outstanding under the APL LTIP at September 30,
2009, 28,960 units will vest within the following twelve months. All phantom units outstanding
under the APL LTIP at September 30, 2009 include DERs granted to the participants by the APL LTIP
Committee. The amounts paid with respect to APL LTIP DERs were $0.1 million for the three months
ended September 30, 2008, and $0.1 million and $0.4 million for the nine months ended September 30,
2009 and 2008, respectively. No LTIP DER payments were made for the three months ended September
30, 2009. These amounts were recorded as reductions of non-controlling interest on the Companys
consolidated balance sheet.
The following table sets forth the APL LTIP phantom unit activity for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Outstanding, beginning of period |
|
|
76,721 |
|
|
|
149,923 |
|
|
|
126,565 |
|
|
|
129,746 |
|
Granted(1) |
|
|
|
|
|
|
|
|
|
|
2,000 |
|
|
|
54,296 |
|
Matured(2) |
|
|
(11,038 |
) |
|
|
(10,860 |
) |
|
|
(46,132 |
) |
|
|
(44,229 |
) |
Forfeited |
|
|
(75 |
) |
|
|
(1,000 |
) |
|
|
(16,825 |
) |
|
|
(1,750 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(3) |
|
|
65,608 |
|
|
|
138,063 |
|
|
|
65,608 |
|
|
|
138,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense recognized
(in thousands) |
|
$ |
235 |
|
|
$ |
600 |
|
|
$ |
491 |
|
|
$ |
1,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted average prices for phantom unit awards on the date of grant, which are utilized in the calculation of compensation expense and do
not represent an exercise price to be paid by the recipient, were $4.75 and $44.43 for awards granted for the nine months ended September 30, 2009 and 2008,
respectively. There were no awards granted for the three months ended September 30, 2009 and 2008. |
|
(2) |
|
The intrinsic values for phantom unit awards exercised during the three months ended September 30, 2009 and 2008 were $0.1 million and $0.4
million, respectively, and $0.2 million and $1.8 million during the nine months ended September 30, 2009 and 2008, respectively. |
|
(3) |
|
The aggregate intrinsic value for phantom unit awards outstanding at September 30, 2009 was $0.5 million. |
At September 30, 2009, APL had approximately $0.8 million of unrecognized compensation
expense related to unvested phantom units outstanding under the APL LTIP based upon the fair value
of the awards.
59
APL Unit Options. A unit option entitles a participant to receive a common unit of APL upon
payment of the exercise price for the option after completion of vesting of the unit option. The
exercise price of the unit option may be equal to or more than the fair market value of APLs
common unit as determined by the APL LTIP Committee on the date of grant of the option. The APL
LTIP Committee also shall determine how the exercise price may be paid by the Participant. The APL
LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards
expire 10 years from the date of grant. Through September 30, 2009, unit options granted under
APLs LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. The
vesting of awards may also be contingent upon the attainment of predetermined performance targets,
which could increase or decrease the actual award settlement, as determined by the APL LTIP
Committee, although no awards currently outstanding contain any such provision. Awards will
automatically vest upon a change of control of APL, as defined in the APLs LTIP. There were
25,000 unit options outstanding under APLs LTIP at September 30, 2009 that will vest within the
following twelve months. The following table sets forth the APL LTIP unit option activity for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Unit |
|
|
Exercise |
|
|
of Unit |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
Outstanding, beginning of period |
|
|
100,000 |
|
|
$ |
6.24 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Matured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(1)(2) |
|
|
100,000 |
|
|
$ |
6.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable, end of period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of unit
options per unit granted during
the period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number |
|
|
Average |
|
|
Number |
|
|
Average |
|
|
|
of Unit |
|
|
Exercise |
|
|
of Unit |
|
|
Exercise |
|
|
|
Options |
|
|
Price |
|
|
Options |
|
|
Price |
|
Outstanding, beginning of period |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
100,000 |
|
|
|
6.24 |
|
|
|
|
|
|
|
|
|
Matured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of period(1)(2) |
|
|
100,000 |
|
|
$ |
6.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable, end of period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value of unit
options per unit granted during the period |
|
|
100,000 |
|
|
$ |
0.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
recognized
(in thousands) |
|
$ |
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted average remaining contractual life for outstanding options at September 30, 2009 was 9.3 years. |
|
(2) |
|
There was $0.1 million aggregate intrinsic value of options outstanding at September 30, 2009. |
60
APL used the Black-Scholes option pricing model to estimate the weighted average fair
value of options granted. The following weighted average assumptions were used for the period
indicated:
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, 2009 |
|
Expected dividend yield |
|
|
11.0 |
% |
Expected stock price volatility |
|
|
20 |
% |
Risk-free interest rate |
|
|
2.2 |
% |
Expected term (in years) |
|
|
6.3 |
|
APL Employee Incentive Compensation Plan and Agreement
In June 2009, a wholly-owned subsidiary of APL adopted an incentive plan (the APL Plan)
which allows for equity-indexed cash incentive awards to employees of APL (the Participants), but
expressly excludes as an eligible Participant any Named Executive Officer of APL (as such term is
defined under the rules of the Securities and Exchange Commission). The APL Plan is administered
by a committee appointed by the chief executive officer of APL. Under the APL Plan, cash bonus
units may be awarded Participants at the discretion of the committee and bonus units totaling
325,000 were awarded under the APL Plan in June 2009. In September 2009, the APL subsidiary
entered into an agreement with an APL executive officer that granted an award of 50,000 bonus units
on substantially the same terms as the bonus units available under the APL Plan (the bonus units
issued under the APL Plan and under the separate agreement are, for purposes hereof, referred to as
APL Bonus Units). An APL Bonus Unit entitles the employee to receive the cash equivalent of the
then-fair market value of an APL common limited partner unit, without payment of an exercise price,
upon vesting of the APL Bonus Unit. APL Bonus Units vest ratably over a three year period from the
date of grant and will automatically vest upon a change of control, death, or termination without
cause, each as defined in the governing document. Vesting will terminate upon termination of
employment with cause. During the three and nine months ended September 30, 2009, APL granted
50,000 and 375,000 APL Bonus Units, respectively. Of the APL Bonus Units outstanding at September
30, 2009, 123,750 APL Bonus Units will vest within the following twelve months. APL recognized
compensation expense related to these awards based upon the fair value. APL recognized $0.4
million and $0.5 million of compensation expense within general and administrative expense on the
Companys consolidated statements of operations with respect to the vesting of these awards for the
three and nine months ended September 30, 2009, respectively. At September 30, 2009, the Company
has recognized $0.5 million within accrued liabilities on its consolidated balance sheet with
regard to the awards, which represents their fair value at September 30, 2009.
NOTE 18 OPERATING SEGMENT INFORMATION
The Companys operations include three reportable operating segments. These operating segments
reflect the way the Company manages its operations and makes business decisions. The Company does
not allocate income taxes to its operating segments. Operating segment data for the periods
indicated are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2009 |
|
|
2008 (c) |
|
|
2009 (c) |
|
|
2008 (c) |
|
Gas and oil production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (a) |
|
$ |
65,986 |
|
|
$ |
81,235 |
|
|
$ |
207,908 |
|
|
$ |
236,417 |
|
Costs and expenses |
|
|
(12,128 |
) |
|
|
(12,688 |
) |
|
|
(33,217 |
) |
|
|
(35,735 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
53,858 |
|
|
$ |
68,547 |
|
|
$ |
174,691 |
|
|
$ |
200,682 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well construction and completion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
81,496 |
|
|
$ |
116,987 |
|
|
$ |
257,231 |
|
|
$ |
343,466 |
|
Costs and expenses |
|
|
(69,138 |
) |
|
|
(101,727 |
) |
|
|
(218,236 |
) |
|
|
(298,666 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
12,358 |
|
|
$ |
15,260 |
|
|
$ |
38,995 |
|
|
$ |
44,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
14,259 |
|
|
$ |
3,380 |
|
|
$ |
23,999 |
|
|
$ |
13,116 |
|
Costs and expenses |
|
|
(10,350 |
) |
|
|
(2,890 |
) |
|
|
(19,290 |
) |
|
|
(8,206 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
3,909 |
|
|
$ |
490 |
|
|
$ |
4,709 |
|
|
$ |
4,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Pipeline (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (c) |
|
$ |
200,537 |
|
|
$ |
553,561 |
|
|
$ |
521,918 |
|
|
$ |
945,864 |
|
Revenues affiliates |
|
|
|
|
|
|
12,021 |
|
|
|
16,766 |
|
|
|
32,768 |
|
Equity income in joint venture |
|
|
1,430 |
|
|
|
|
|
|
|
2,140 |
|
|
|
|
|
Costs and expenses |
|
|
(159,890 |
) |
|
|
(333,851 |
) |
|
|
(458,384 |
) |
|
|
(992,113 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss) |
|
$ |
42,077 |
|
|
$ |
231,731 |
|
|
$ |
82,440 |
|
|
$ |
(13,481 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2009 |
|
|
2008 (c) |
|
|
2009 (c) |
|
|
2008 (c) |
|
|
Reconciliation of segment profit (loss) to net
income (loss) before income tax provision
(benefit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production |
|
$ |
53,858 |
|
|
$ |
68,547 |
|
|
$ |
174,691 |
|
|
$ |
200,682 |
|
Well construction and completion |
|
|
12,358 |
|
|
|
15,260 |
|
|
|
38,995 |
|
|
|
44,800 |
|
Other |
|
|
3,909 |
|
|
|
490 |
|
|
|
4,709 |
|
|
|
4,910 |
|
Atlas Pipeline |
|
|
42,077 |
|
|
|
231,731 |
|
|
|
82,440 |
|
|
|
(13,481 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment profit (loss) |
|
|
112,202 |
|
|
|
316,028 |
|
|
|
300,835 |
|
|
|
236,911 |
|
Gain on sale of APLs Appalachia system assets |
|
|
55 |
|
|
|
|
|
|
|
105,746 |
|
|
|
|
|
General and administrative expenses |
|
|
(31,786 |
) |
|
|
(12,392 |
) |
|
|
(80,777 |
) |
|
|
(57,903 |
) |
Net expense reimbursement affiliate |
|
|
(280 |
) |
|
|
(255 |
) |
|
|
(842 |
) |
|
|
(689 |
) |
Depreciation, depletion and amortization |
|
|
(46,460 |
) |
|
|
(44,325 |
) |
|
|
(147,427 |
) |
|
|
(129,539 |
) |
Interest expense (d) |
|
|
(47,754 |
) |
|
|
(37,331 |
) |
|
|
(124,322 |
) |
|
|
(106,538 |
) |
Other income (loss) net |
|
|
3,421 |
|
|
|
3,818 |
|
|
|
9,556 |
|
|
|
11,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing
operations before income tax provision
(benefit) |
|
$ |
(10,602 |
) |
|
$ |
225,543 |
|
|
$ |
62,769 |
|
|
$ |
(45,916 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas and oil production |
|
$ |
33,824 |
|
|
$ |
89,165 |
|
|
$ |
129,818 |
|
|
$ |
224,179 |
|
Well construction and completion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Pipeline |
|
|
7,116 |
|
|
|
81,714 |
|
|
|
137,610 |
|
|
|
223,768 |
|
Corporate and other |
|
|
548 |
|
|
|
135 |
|
|
|
967 |
|
|
|
791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
41,488 |
|
|
$ |
171,014 |
|
|
$ |
268,395 |
|
|
$ |
448,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 (c) |
|
Balance sheet |
|
|
|
|
|
|
|
|
Goodwill |
|
|
|
|
|
|
|
|
Gas and oil production |
|
$ |
21,527 |
|
|
$ |
21,527 |
|
Well construction and completion |
|
|
13,639 |
|
|
|
13,639 |
|
Atlas Pipeline |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
35,166 |
|
|
$ |
35,166 |
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
|
|
Gas and oil production |
|
$ |
2,201,175 |
|
|
$ |
2,210,563 |
|
Well construction and completion |
|
|
12,760 |
|
|
|
16,399 |
|
Atlas Pipeline (c) |
|
|
2,139,561 |
|
|
|
2,157,590 |
|
Discontinued operations |
|
|
|
|
|
|
255,606 |
|
Corporate and other |
|
|
118,230 |
|
|
|
205,723 |
|
|
|
|
|
|
|
|
|
|
$ |
4,471,726 |
|
|
$ |
4,845,881 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes revenues and expenses from well services, transportation and
administration and oversight that do not meet the quantitative threshold for reporting
segment information. |
|
(b) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs
sale of its NOARK gas gathering and interstate pipeline system (see Note 5). |
|
(c) |
|
Includes gains of $1.0 million and $147.5 million on mark-to-market derivatives
for three months ended September 30, 2009 and 2008, respectively, and losses of $17.2
million and $257.3 million on mark-to-market derivatives for nine months ended September
30, 2009 and 2008, respectively. |
|
(d) |
|
The Company notes that interest expense has not been allocated to its reportable
segments as it would be impracticable to reasonably do so for the periods presented. |
Operating profit (loss) represents total revenues less costs and expenses attributable
thereto. Amounts for interest, provision for possible losses and depreciation, depletion and
amortization and general corporate expenses are shown in the aggregate because these measures are
not significant drivers in deciding how to allocate resources and assessing performance of each
defined segment.
62
NOTE 19 SUBSEQUENT EVENTS
On November 2, 2009, APLs agreement with Pioneer, whereby Pioneer had an option to purchase
up to an additional 22.0% interest in the Midkiff/Benedum system, expired without Pioneer
exercising its option (see Note 2).
On October 22, 2009, the Company entered into the following natural gas derivative contracts:
Natural Gas Fixed Price Swaps
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
Average |
|
December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
|
(MMBtu) |
|
|
(per MMBtu) |
|
2010 |
|
|
2,520,000 |
|
|
$ |
6.250 |
|
2011 |
|
|
1,260,000 |
|
|
$ |
6.863 |
|
Natural Gas Costless Collars
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
|
|
Average |
|
December 31, |
|
Option Type |
|
Volumes |
|
|
Floor and Cap |
|
|
|
|
|
(MMBtu) |
|
|
(per MMBtu) |
|
2012 |
|
Puts purchased |
|
|
3,480,000 |
|
|
$ |
6.550 |
|
2012 |
|
Calls sold |
|
|
3,480,000 |
|
|
$ |
7.750 |
|
2013 |
|
Puts purchased |
|
|
3,480,000 |
|
|
$ |
6.700 |
|
2013 |
|
Calls sold |
|
|
3,480,000 |
|
|
$ |
7.800 |
|
On October 14, 2009, in conjunction with a regularly scheduled borrowing based
redetermination, the Companys borrowing base under its revolving credit facility of $575.0 million
was approved.
On October 13, 2009 AHD repaid $4.0 million of its outstanding credit facility borrowings in
accordance with the amendment through a subordinate loan with the Company.
|
|
|
ITEM 2. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Forward-Looking Statements
When used in this Form 10-Q, the words believes, anticipates, expects and similar
expressions are intended to identify forward-looking statements. Such statements are subject to
certain risks and uncertainties more particularly described in Item 1A, Risk Factors, in our
annual report on Form 10-K for the year ended December 31, 2008. These risks and uncertainties
could cause actual results to differ materially from the results stated or implied in this
document. Readers are cautioned not to place undue reliance on these forward-looking statements,
which speak only as of the date hereof. We undertake no obligation to publicly release the results
of any revisions to forward-looking statements which we may make to reflect events or circumstances
after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.
GENERAL
The following discussion provides information to assist in understanding our financial
condition and results of operations. This discussion should be read in conjunction with our
consolidated financial statements and related notes appearing elsewhere in this report.
63
We are a publicly traded Delaware corporation whose common units are listed on the NASDAQ
Stock Market under the symbol ATLS. On September 29, 2009, we completed our merger with Atlas
Energy Resources, LLC (ATN), our formerly publicly traded subsidiary and a Delaware limited
liability company (NYSE: ATN), pursuant to the definitive merger agreement previously executed
between us and ATN, with ATN surviving as our wholly-owned subsidiary (the Merger).
We are an independent developer and producer of natural gas and oil, with operations in the
Appalachian Basin, the Michigan Basin, and the Illinois Basin. Within these Basins, we focus our
drilling and production in four established shale plays: namely, the Marcellus Shale of western
Pennsylvania, the Antrim Shale of northern Michigan, the Chattanooga Shale of northeastern
Tennessee, and the New Albany Shale of west central Indiana. Our Appalachian Basin major
operations are located in eastern Ohio, western Pennsylvania, and north central Tennessee. We have
additional operations in New York, West Virginia and Kentucky. We specialize in development of
these natural gas basins because they provide it with repeatable, low-risk drilling opportunities.
We are also a leading sponsor and manager of tax-advantaged direct investment natural gas and oil
partnerships in the United States. We fund the drilling of natural gas and oil wells on its acreage
by sponsoring and managing tax advantaged investment partnerships. We generally structure our
investment partnerships so that, upon formation of a partnership, we co-invest in and contribute
leasehold acreage to it, enter into drilling and well operating agreements with it and becomes its
managing general partner.
KEY PERFORMANCE INDICATORS
In our Appalachia gas and oil operations:
|
|
|
we own direct and indirect working interests in approximately 8,658 gross productive
gas and oil wells; |
|
|
|
we own overriding royalty interests in approximately 624 gross productive gas and oil
wells; |
|
|
|
our net daily production was 41.3 million cubic feet equivalents per day (Mmcfed) and
42.4 Mmcfed for the three and nine months ended September 30, 2009, respectively; |
|
|
|
we lease approximately 919,200 gross (873,600 net) acres, of which approximately
606,800 gross (599,800 net) acres are undeveloped; |
|
|
|
|
included in our undeveloped acreage are approximately 215,600 Marcellus acres in
Pennsylvania, New York and West Virginia, of which approximately 160,400 acres are located
in our core Marcellus Shale position in southwestern Pennsylvania; |
|
|
|
we drilled 153 gross wells (including 73 Marcellus Shale wells), during the nine months
ended September 30, 2009, on our own behalf and that of our investment partnerships; |
|
|
|
we have drilled 184 vertical and 15 horizontal gross Marcellus Shale wells to date, of
which 159 vertical and 7 horizontal Marcellus Shale wells have been successfully completed
and have been turned on-line and are producing; |
|
|
|
of the 159 vertical completed Marcellus Shale wells we drilled to date, we have
utilized the multi-frac technique on 68 wells, with successful results; |
64
|
|
|
we turned on-line 274 gross wells during the nine months ended September 30, 2009; and |
|
|
|
we drilled and participated in 25 horizontal wells in the Chattanooga Shale of eastern
Tennessee to date. We have leased approximately 130,700 gross acres (128,200 net
undeveloped) in this shale area. |
In our Michigan gas and oil operations:
|
|
|
we own direct and indirect working interests in approximately 2,498 gross producing gas
and oil wells; |
|
|
|
we own overriding royalty interests in approximately 93 gross producing gas and oil
wells; |
|
|
|
our net daily production was 57.8 Mmcfed and 58.3 Mmcfed for the three and nine months
ended September 30, 2009, respectively; |
|
|
|
we have leased approximately 345,000 gross (271,900 net) acres, of which approximately
34,900 gross (26,400 net) acres are undeveloped; and |
|
|
|
we drilled 32 gross wells (27 net wells) during the nine months ended September 30,
2009. |
In our Indiana gas and oil operations:
|
|
|
we own direct and indirect working interests in approximately 20 gross producing gas
and oil wells; |
|
|
|
our net daily production was 0.8 Mmcfed and 0.4 Mmcfed for the three and nine months
ended September 30, 2009, respectively; |
|
|
|
we have leased approximately 249,600 gross (122,800 net) acres, of which approximately
242,600 gross (117,200 net) acres are undeveloped; and |
|
|
|
we drilled 19 gross wells (17 net wells) during the nine months ended September 30,
2009. |
In our partnership management business:
|
|
|
our investment partnership business includes equity interests in 96 investment
partnerships and a registered broker-dealer which acts as the dealer manager of our
investment partnership offerings; and |
|
|
|
during 2009, we have raised $122.8 million in investor funds for Atlas Resources Public
#18B-2009(B) L.P., and have begun raising funds for our most recent investment
partnership, Atlas Resources Public #18-2009(C) L.P. in which we have registered
subscriptions of up to $275.7 million (A written prospectus meeting the requirements of
Section 10 of the Securities Act may be obtained from Anthem Securities, Inc. (a
subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. 3rd Floor, Moon Township, PA
15108). |
65
OTHER OWNERSHIP INTERESTS
In addition to our production operations, we also maintain ownership interests in the
following entities at September 30, 2009:
|
|
|
1,112,000 common units, representing a 2.2% ownership interest, in Atlas Pipeline
Partners, L.P. (Atlas Pipeline Partners or APL), a publicly traded Delaware limited
partnership (NYSE: APL) and midstream energy service provider engaged in the transmission,
gathering and processing of natural gas in the Mid-Continent and Appalachia regions; |
|
|
|
17,808,109 common units, representing a 64.4% ownership interest, in Atlas Pipeline
Holdings, L.P. (Atlas Pipeline Holdings or AHD), a publicly traded Delaware limited
partnership (NYSE: AHD) and owner of the general partner of APL. We manage AHD through our
ownership of its general partner; and |
|
|
|
Lightfoot Capital Partners LP (Lightfoot LP) and Lightfoot Capital Partners GP LLC
(Lightfoot GP), the general partner of Lightfoot (collectively, Lightfoot), entities
which incubate new master limited partnerships (MLPs) and invest in existing MLPs. We
have an approximate direct and indirect 18% ownership interest in Lightfoot GP and a
commitment to invest a total of $20.0 million in Lightfoot LP. We also have a direct and
indirect ownership interests in Lightfoot LP. |
AHD, which owns the general partner and manages APL, had the following ownership interests in
APL at September 30, 2009:
|
|
|
a 2.0% general partner interest, which entitles it to receive 2% of the cash distributed
by APL; |
|
|
|
all of the incentive distribution rights, which entitle it to receive increasing
percentages, up to a maximum of 48.0%, of any cash distributed by APL as it reaches certain
target distribution levels in excess of $0.42 per APL common unit in any quarter. AHD, the
holder of all of the incentive distribution rights in APL, agreed to allocate up to $3.75
million of its incentive distribution rights per quarter back to APL (the IDR Adjustment
Agreement) after AHD receives the initial $7.0 million per quarter of incentive
distribution rights; |
|
|
|
5,754,253 common units, representing approximately 11.4% of the outstanding common units
at September 30, 2009, or a 11.2% ownership interest in APL; and |
|
|
|
15,000 $1,000 par value 12.0% cumulative preferred limited partner units at September
30, 2009. |
FINANCIAL PRESENTATION
Our consolidated financial statements contain our accounts and those of our subsidiaries, all
of which are wholly-owned at September 30, 2009 except for AHD, which we control, and APL, which is
controlled by AHD. Prior to the Merger on September 29, 2009, ATN was a controlled subsidiary of
ours but was not wholly-owned. The non-controlling interests in ATN prior to the Merger and AHD
and APL are reflected as income (loss) attributable to non-controlling interests in our
consolidated statements of operations and as a component of stockholders equity on our
consolidated balance sheets. Throughout this section, when we refer to our consolidated
financial statements, we are referring to the consolidated results for us and our wholly-owned
subsidiaries and the consolidated results of AHD, including APLs financial results, adjusted for
non-controlling interests in ATNs net income (loss) prior to the Merger on September 29, 2009 and
AHDs and APLs net income (loss).
66
RECENT DEVELOPMENTS
On September 29, 2009, we completed our merger with ATN pursuant to the definitive merger
agreement previously executed between us and ATN, with ATN surviving as our wholly-owned
subsidiary. In the Merger, the 33.4 million Class B common units of ATN not previously held by us
were exchanged for 38.8 million shares of our common stock (a ratio of 1.16 shares of our common
stock for each Class B common unit of ATN). We also changed our name from Atlas America, Inc. to
Atlas Energy, Inc. Concurrent with the Merger, the Compensation Committee of the Board of
Directors approved the Atlas Energy, Inc. 2009 Stock Incentive Plan, which creates a new stock
incentive plan for the combined entity. We also have the legacy Atlas America stock incentive plan
and assumed the legacy ATN Long-Term Incentive Plan. Due to the Merger, we recognized a reduction
of $556.4 million in non-controlling interest and a decrease to deferred tax liability of $179.4
million, all of which was reflected as an increase to additional paid-in-capital on our
consolidated balance sheets.
On September 7, 2009, we began fundraising for Atlas Resources Public #18-2008 Drilling
Program, in which we have the capacity to raise approximately $275.7 million, representing the
third partnership (Atlas Resources Public #18-2009(C) L.P.) in the program. During the first six
months of 2009, we raised $122.8 million for our second partnership (Atlas Resources Public
#18-2009 (B) L.P.). Atlas Resources, LLC, our wholly-owned subsidiary, serves as the managing
general partner for each partnership. A written prospectus meeting the requirements of Section 10
of the Securities Act of 1933, as amended, may be obtained from Anthem Securities, Inc. (a
subsidiary of Atlas Energy), 1550 Coraopolis Heights Rd. 3rd Floor, Moon Township, PA 15108.
On July 13, 2009, ATN issued $200.0 million of 12.125% senior unsecured notes (ATN 12.125%
Senior Notes) due 2017 at 98.116% of par value to yield 12.5% at maturity. We used the net
proceeds of $191.7 million, net underwriting fees of $4.5 million, to repay outstanding borrowings
under ATNs revolving credit facility (see ATN Credit Facility). Under the terms of the credit
facility, the borrowing base is automatically reduced by 25% of the stated principal amount of any
senior unsecured notes offering by ATN. As such, the borrowing base of the credit facility was
reduced by $50.0 million to $600.0 million upon the issuance of the ATN 12.125% Senior Notes.
Interest on the ATN 12.125% Senior Notes is payable semi-annually in arrears on February 1 and
August 1 of each year. The ATN 12.125% Senior Notes are redeemable on or after August 1, 2013 at
certain redemption prices, together with accrued interest at the date of redemption. In addition,
before August 1, 2012, we may redeem up to 35% of the aggregate principal amount of the ATN 12.125%
Senior Notes with the proceeds of certain equity offerings at a stated redemption price of 112.125%
of the principal, plus accrued interest. The ATN 12.125% Senior Notes are junior in right of
payment to ATNs secured debt, including its obligations under the revolving credit facility. The
indenture governing the ATN 12.125% Senior Notes contains covenants, including limitations of ATNs
ability to incur certain liens, engage in sale/leaseback transactions, incur additional
indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase,
or retire equity interests or subordinated indebtedness; make certain investments; or merge,
consolidate or sell substantially all of ATNs assets. We are not
guarantors of ATNs or APLs senior notes, including the ATN 12.125% Senior Notes, ATNs or
APLs credit facilities, or APLs term loan.
On July 10, 2009, ATNs credit agreement was amended to, among other things, permit the Merger
and to allow ATN to distribute (a) amounts equal to our income tax liability attributable to ATNs
net income at the highest marginal rate and (b) up to $40.0 million per year and, to the extent
that it distributes less than that amount in any year, may carry an amount up to $20.0 million for
use in the next year.
SUBSEQUENT EVENTS
On November 2, 2009, APLs agreement with Pioneer Natural Resources Company (Pioneer),
whereby Pioneer had an option to purchase up to an additional 22.0% interest in the Midkiff/Benedum
system, expired without Pioneer exercising its option (see Note 2 under Item 1, Financial
Statements).
67
Natural Gas Derivative Contracts
On October 22, 2009, we entered into the following natural gas derivative contracts:
Natural Gas Fixed Price Swaps
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
Average |
|
December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
|
(MMBtu) |
|
|
(per MMBtu) |
|
2010 |
|
|
2,520,000 |
|
|
$ |
6.250 |
|
2011 |
|
|
1,260,000 |
|
|
$ |
6.863 |
|
Natural Gas Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
|
|
|
|
Average |
|
December 31, |
|
Option Type |
|
|
Volumes |
|
|
Floor and Cap |
|
|
|
|
|
|
|
(MMBtu) |
|
|
(per MMBtu) |
|
2012 |
|
Puts purchased |
|
|
3,480,000 |
|
|
$ |
6.550 |
|
2012 |
|
Calls sold |
|
|
3,480,000 |
|
|
$ |
7.750 |
|
2013 |
|
Puts purchased |
|
|
3,480,000 |
|
|
$ |
6.700 |
|
2013 |
|
Calls sold |
|
|
3,480,000 |
|
|
$ |
7.800 |
|
Credit Agreement Amendment
Effective October 14, 2009, in conjunction with a regularly scheduled borrowing base
redetermination, ATNs borrowing base under its revolving credit facility of $575.0 million was
approved.
On October 13, 2009 AHD repaid $4.0 million of its outstanding credit facility borrowings in
accordance with the amendment through a subordinate loan with us.
CONTRACTUAL REVENUE ARRANGEMENTS
Appalachia Natural Gas. We market our natural gas, which is principally located in the
Fayette County, PA area, primarily to Hess Corporation, Colonial Energy, Inc., South Jersey
Resources Group and
others. We expect that natural gas produced from our wells drilled in areas of the
Appalachian Basin other than those described above will be primarily tied to the spot market price
and supplied to:
|
|
|
local distribution companies; |
|
|
|
industrial or other end-users; and/or |
|
|
|
companies generating electricity. |
Michigan Natural Gas. In Michigan, we have natural gas sales agreements with DTE Energy
Company, which are valid through December 31, 2012. DTE has the obligation to purchase all of the
natural gas produced and delivered by us and our affiliates from specific projects at certain
delivery points. Based on recent production data available to us, we anticipate that we and our
affiliates will sell approximately 49% of our Michigan natural gas production during the year
ending December 31, 2009 under the DTE agreements, in most cases at NYMEX pricing.
68
Crude Oil. Crude oil produced from our wells flow directly into storage tanks where it is
picked up by an oil company, a common carrier or pipeline companies acting for an oil company,
which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional
oil refining companies at the prevailing spot market price for Appalachian crude oil. In Michigan,
the property operator typically markets the oil produced.
Investment Partnerships. We generally fund our drilling activities through sponsorship of
tax-advantaged investment partnerships. In addition to providing capital for our drilling
activities, our investment partnerships are a source of fee-based revenues, which are not directly
dependent on natural gas and oil prices. As managing general partner of the investment
partnerships, we receive the following fees:
|
|
|
Well construction and completion. For each well that is drilled by an investment
partnership, we receive an 18% mark-up on those costs incurred to drill and complete the
well. |
|
|
|
Administration and oversight. For each well drilled by an investment partnership, we
receive a fixed fee that currently ranges from $15,700 to $248,964. The fixed fee is based
on factors such as well type (vertical or horizontal), depth, formation, and area.
Additionally, the partnership pays us a monthly per well administrative fee of $75 for the
life of the well. Because we coinvest in the partnerships, the net fee that we receive is
reduced by its proportionate interest in the well. |
|
|
|
Well services. Each partnership pays us a monthly per well operating fee, currently $100
to $1,500, for the life of the well. Because we coinvest in the partnerships, the net fee
that we receive is reduced by our proportionate interest in the well. |
GENERAL TRENDS AND OUTLOOK
We expect our business to be affected by the following key trends. Our expectations are based
on assumptions made by us and information currently available to us. To the extent our underlying
assumptions about or interpretations of available information prove to be incorrect, our actual
results may vary materially from our expected results.
Natural Gas Supply and Outlook
While commodity prices for natural gas were at lower levels during the three months ended
September 30, 2009 when compared with the prior year, we believe that the current development of
the Marcellus Shale
and the New Albany Shale, and new horizontal drilling techniques will likely cause relatively
high levels of natural gas-related drilling in these geological areas as producers seek to increase
their level of natural gas production. Although the number of natural gas wells drilled in the
United States has increased overall in recent years, a corresponding increase in production has not
been realized, primarily as a result of smaller discoveries and the decline in production from
existing wells. We believe that an increase in United States drilling activity, additional sources
of supply such as liquefied natural gas and imports of natural gas will be required for the natural
gas industry to meet the expected increased demand for, and to compensate for the slowing
production of, natural gas in the United States. However, the areas in which we operate are
experiencing a decline in the development of shallow wells, but a significant increase in drilling
activity related to new and increased drilling for deeper natural gas formations and the
implementation of new exploration and production techniques, including horizontal and multiple
fracturing techniques.
While we anticipate continued high levels of exploration and production activities over the
long-term in the areas in which we operate, fluctuations in energy prices can greatly affect
production rates and investments by third parties in the development of new natural gas reserves.
Drilling activity generally decreases as natural gas prices decrease. We have no control over the
level of drilling activity in the areas of our operations.
69
Reserve Outlook
Our future oil and gas reserves, production, cash flow and our ability to make payments on
ATNs debt depend on our success in producing our current reserves efficiently, developing our
existing acreage and acquiring additional proved reserves economically. We face the challenge of
natural production declines and volatile natural gas and oil prices. As initial reservoir
pressures are depleted, natural gas production from particular wells decreases. We attempt to
overcome this natural decline by drilling to find additional reserves and acquiring more reserves
than we produce. In order to sustain and grow our cash flow, we may need to make acquisitions.
RESULTS OF OPERATIONS
GAS AND OIL PRODUCTION
Production Profile. Currently, we have focused our natural gas production operations
in various shale plays in the northeastern and midwestern United States. Notably, we are one of the
leading producers in the Marcellus Shale, a rich, organic shale located in the Appalachia basin.
The portion of the Marcellus Shale in southwestern Pennsylvania in which we focus our drilling is
high-pressured and generally contains dry, pipeline-quality natural gas. In addition, we also are a
leading natural gas producer in Michigan through our activity in the Antrim Shale, a biogenic shale
play with a long-lived and shallow decline profile. We have also established a position in the New
Albany Shale in southwestern Indiana, where we produce out of the biogenic region of the shale
similar to the Antrim. We also produce from the Chattanooga Shale in northeastern Tennessee, which
enables us to access other formations in that region such as the Monteagle and Ft. Payne Limestone.
Production Volumes. The following table shows our total net gas and oil production
volumes and production per day during the three and nine months ended September 30, 2009 and 2008,
respectively (in thousands, except for production per day):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Production:(1)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf) |
|
|
3,549 |
|
|
|
3,057 |
|
|
|
10,851 |
|
|
|
8,748 |
|
Oil (000s Bbls) |
|
|
42 |
|
|
|
39 |
|
|
|
120 |
|
|
|
112 |
|
Total (MMcfe) |
|
|
3,801 |
|
|
|
3,291 |
|
|
|
11,571 |
|
|
|
9,420 |
|
Michigan/Indiana: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf) |
|
|
5,384 |
|
|
|
5,561 |
|
|
|
15,910 |
|
|
|
16,373 |
|
Oil (000s Bbls) |
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
Total (MMcfe) |
|
|
5,390 |
|
|
|
5,567 |
|
|
|
15,928 |
|
|
|
16,391 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf) |
|
|
8,933 |
|
|
|
8,618 |
|
|
|
26,761 |
|
|
|
25,121 |
|
Oil (000s Bbls) |
|
|
43 |
|
|
|
40 |
|
|
|
123 |
|
|
|
115 |
|
Total (MMcfe) |
|
|
9,191 |
|
|
|
8,858 |
|
|
|
27,499 |
|
|
|
25,811 |
|
70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Production per day:(1)(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd) |
|
|
38,579 |
|
|
|
33,228 |
|
|
|
39,749 |
|
|
|
31,929 |
|
Oil (Bpd) |
|
|
460 |
|
|
|
413 |
|
|
|
442 |
|
|
|
410 |
|
Total (Mcfed) |
|
|
41,339 |
|
|
|
35,706 |
|
|
|
42,401 |
|
|
|
34,389 |
|
Michigan/Indiana: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd) |
|
|
58,519 |
|
|
|
60,436 |
|
|
|
58,277 |
|
|
|
59,755 |
|
Oil (Bpd) |
|
|
9 |
|
|
|
11 |
|
|
|
9 |
|
|
|
11 |
|
Total (Mcfed) |
|
|
58,573 |
|
|
|
60,502 |
|
|
|
58,331 |
|
|
|
59,821 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcfd) |
|
|
97,098 |
|
|
|
93,664 |
|
|
|
98,026 |
|
|
|
91,684 |
|
Oil (bpd) |
|
|
469 |
|
|
|
424 |
|
|
|
451 |
|
|
|
421 |
|
Total (Mcfed) |
|
|
99,912 |
|
|
|
96,208 |
|
|
|
100,732 |
|
|
|
94,210 |
|
|
|
|
(1) |
|
Production quantities consist of the sum of (i) our proportionate share of
production from wells in which we have a direct interest, based on our proportionate net
revenue interest in such wells, and (ii) our proportionate share of production from wells
owned by the investment partnerships in which we have an interest, based on our equity
interest in each such partnership and based on each partnerships proportionate net revenue
interest in these wells. |
|
(2) |
|
MMcf represents million cubic feet; MMcfe represent million cubic feet
equivalents; Mcfd represents thousand cubic feet per day; Mcfed represents thousand cubic
feet equivalents per day; and Bbls and Bpd represent barrels and barrels per day. |
|
(3) |
|
Appalachia includes our production located in Pennsylvania, Ohio, New York, West
Virginia, and Tennessee. |
Production Revenues, Prices and Costs. Production revenues and estimated gas and
oil reserves are substantially dependent on prevailing market prices for natural gas, which
comprised 99% of our proved reserves on an energy equivalent basis at December 31, 2008. The
following table shows our production revenues and average sales prices for our oil and gas
production during the three and nine months ended September 30, 2009 and 2008, along with our
average production costs, taxes, and transmission and compression costs in each of the reported
periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Production Revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
$ |
22,802 |
|
|
$ |
30,430 |
|
|
$ |
79,873 |
|
|
$ |
85,440 |
|
Oil |
|
|
3,185 |
|
|
|
3,868 |
|
|
|
8,265 |
|
|
|
11,753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
25,987 |
|
|
$ |
34,298 |
|
|
$ |
88,138 |
|
|
$ |
97,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michigan/Indiana: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
$ |
39,946 |
|
|
$ |
46,823 |
|
|
$ |
119,646 |
|
|
$ |
138,905 |
|
Oil |
|
|
53 |
|
|
|
114 |
|
|
|
124 |
|
|
|
319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
39,999 |
|
|
$ |
46,937 |
|
|
$ |
119,770 |
|
|
$ |
139,224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
$ |
62,748 |
|
|
$ |
77,253 |
|
|
$ |
199,519 |
|
|
$ |
224,345 |
|
Oil |
|
|
3,238 |
|
|
|
3,982 |
|
|
|
8,389 |
|
|
|
12,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
65,986 |
|
|
$ |
81,235 |
|
|
$ |
207,908 |
|
|
$ |
236,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge(2) |
|
$ |
7.00 |
|
|
$ |
9.95 |
|
|
$ |
7.67 |
|
|
$ |
9.76 |
|
Total realized price, before hedge(2) |
|
$ |
2.92 |
|
|
$ |
11.13 |
|
|
$ |
4.06 |
|
|
$ |
10.62 |
|
Michigan/Indiana: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge(1) |
|
$ |
7.49 |
|
|
$ |
8.88 |
|
|
$ |
7.67 |
|
|
$ |
9.13 |
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Total realized price, before hedge |
|
$ |
3.38 |
|
|
$ |
10.15 |
|
|
$ |
3.98 |
|
|
$ |
9.71 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge(1)(2) |
|
$ |
7.29 |
|
|
$ |
9.26 |
|
|
$ |
7.67 |
|
|
$ |
9.35 |
|
Total realized price, before hedge(2) |
|
$ |
3.20 |
|
|
$ |
10.49 |
|
|
$ |
4.01 |
|
|
$ |
10.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge |
|
$ |
75.26 |
|
|
$ |
101.07 |
|
|
$ |
68.49 |
|
|
$ |
104.04 |
|
Total realized price, before hedge |
|
$ |
62.81 |
|
|
$ |
106.81 |
|
|
$ |
52.33 |
|
|
$ |
108.09 |
|
Michigan/Indiana: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge |
|
$ |
63.00 |
|
|
$ |
111.72 |
|
|
$ |
50.72 |
|
|
$ |
108.36 |
|
Total realized price, before hedge |
|
$ |
63.00 |
|
|
$ |
111.72 |
|
|
$ |
50.72 |
|
|
$ |
108.36 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total realized price, after hedge |
|
$ |
75.03 |
|
|
$ |
101.34 |
|
|
$ |
68.13 |
|
|
$ |
104.15 |
|
Total realized price, before hedge |
|
$ |
62.81 |
|
|
$ |
106.94 |
|
|
$ |
52.30 |
|
|
$ |
108.09 |
|
|
|
|
(1) |
|
Includes cash proceeds of $0.3 million and $2.6 million for the three months
ended September 30, 2009 and 2008, respectively and $2.4 million and $10.5 million for the
nine months ended September 30, 2009 and 2008, respectively, received from the settlement of
ineffective derivative gains associated with the acquisition of our Michigan operations, but
not reflected in the consolidated statements of operations for the respective periods. |
|
(2) |
|
Excludes the impact of certain allocation of production revenue to investor partners
within our investment partnerships. Including the effect of these allocations, average
realized gas sales prices for the three and nine months ended September 30, 2009 for
Appalachia were $6.42 per Mcf ($2.34 per Mcf before the effects of financial hedging) and
$7.36 per Mcf ($3.75 before the effects of financial hedging), respectively, and in total were
$7.06 per Mcf ($2.97 per Mcf before the effects of financial hedging) and $7.55 per Mcf ($3.89
per Mcf before the effects of financial hedging), respectively. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Production Costs (per Mcfe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses(1) |
|
$ |
0.97 |
|
|
$ |
1.08 |
|
|
$ |
1.03 |
|
|
$ |
0.98 |
|
Production taxes |
|
|
0.01 |
|
|
|
0.04 |
|
|
|
0.03 |
|
|
|
0.04 |
|
Transportation and compression |
|
|
0.77 |
|
|
|
1.18 |
|
|
|
0.79 |
|
|
|
0.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1.75 |
|
|
$ |
2.30 |
|
|
$ |
1.85 |
|
|
$ |
1.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michigan/Indiana: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
0.69 |
|
|
$ |
0.67 |
|
|
$ |
0.70 |
|
|
$ |
0.73 |
|
Production taxes |
|
|
0.22 |
|
|
|
0.63 |
|
|
|
0.25 |
|
|
|
0.59 |
|
Transportation and compression |
|
|
0.23 |
|
|
|
0.28 |
|
|
|
0.24 |
|
|
|
0.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1.14 |
|
|
$ |
1.58 |
|
|
$ |
1.19 |
|
|
$ |
1.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses(1) |
|
$ |
0.81 |
|
|
$ |
0.82 |
|
|
$ |
0.84 |
|
|
$ |
0.82 |
|
Production taxes |
|
|
0.14 |
|
|
|
0.41 |
|
|
|
0.16 |
|
|
|
0.39 |
|
Transportation and compression |
|
|
0.45 |
|
|
|
0.61 |
|
|
|
0.47 |
|
|
|
0.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1.40 |
|
|
$ |
1.84 |
|
|
$ |
1.47 |
|
|
$ |
1.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes the effects of the Companys proportionate share of lease operating expenses
associated with certain allocations of production revenue to investor partners within its
investment partnerships. Including the effects of these costs, lease operating expenses per
Mcfe for the three and nine months ended September 30, 2009 for Appalachia were $0.80 per
Mcfe (total production costs per Mcfe were $1.58) and $0.94 per Mcfe (total production
costs per Mcfe were $1.76), respectively, and in total they were $0.73 per Mcfe (total
production costs per Mcfe were $1.32) and $0.80 per Mcfe (total production costs per Mcfe
were $1.43), respectively. |
72
Total natural gas revenues were $62.8 million for the three months ended
September 30, 2009, a decrease of $14.5 million from $77.3 million for the three months ended
September 30, 2008. The $14.6 million decrease consisted of a $14.7 million decrease resulting
from lower realized natural gas prices, $2.0 million of subordinated gas revenues during the
current period to the investor partners within our investment partnerships, and a $2.2 million
increase attributable to increases in natural gas production volumes. In accordance with the terms
of our investment partnerships, we may be required to net revenues subordinated from the investment
partnerships to the benefit of the investor partners in order to provide them with an amount equal
to at least 10% of their subscriptions determined on a cumulative basis for the initial 5-year
period after commencement of distributions from the investment partnerships, subject to certain
limitations. Appalachian production volumes increased 5.4 MMcfd to 38.6 MMcfd for the three months
ended September 30, 2009 when compared with the prior year comparable period, which was principally
attributable to the increase in production we received from our Marcellus Shale wells and an
increase in wells drilled in the most recent nine-month period as they were connected to gas
gathering facilities and transportation pipelines. Total oil revenues were $3.2 million for the
three months ended September 30, 2009, a decrease of $0.7 million from $3.9 million for the three
months ended September 30, 2008. The decrease resulted primarily from a $1.0 million decrease from
lower average realized oil prices, partially offset by a $0.3 million increase from the increase in
production volumes.
Appalachia production costs were $6.0 million for the three months ended September 30, 2009, a
decrease of $1.5 million from $7.5 million, before the elimination of the excess gathering fees
prior to the Laurel Mountain joint venture (see Transmission, gathering and processing). This
decrease principally consists of a $1.0 million decrease due to the Companys proportionate share
of lease operating expenses associated with its revenue that was subordinated to the investor
partners within its investment partnerships and a $1.0 million decrease in transportation expense,
partially offset by a $0.8 million increase in water hauling and disposal costs associated with an
increase in the number of Marcellus Shale wells we drilled. The decrease in Appalachia
transportation expense was related to the decline in natural gas prices, for which our wells are
generally charged a percentage of the sales price received for the natural gas transported.
Michigan/Indiana production costs were $6.1 million for the three months ended September 30, 2009,
a decrease of $2.7 million from $8.8 million for the three months ended September 30, 2008. This
decrease was primarily attributable to a $2.3 million decrease in production taxes due to a state
reduction in the production tax rate on January 1, 2009.
Total natural gas revenues were $199.5 million for the nine months ended September 30, 2009, a
decrease of $24.8 million from $224.4 million for the nine months ended September 30, 2008. This
decrease consisted of $33.7 million decrease attributable to lower realized natural gas prices and
$3.3 million of gas revenues subordinated to the investor partners within our investment
partnerships, partially offset by a $12.2
million increase attributable to a higher natural gas production volumes. Appalachian
production volumes increased 7.8 MMcfd to 39.7 MMcfd for the nine months ended September 30, 2009
when compared to the prior year comparable period, which was principally attributable to the
increase in production we received from our Marcellus Shale wells and wells drilled in the most
recent nine-month period as they were connected to gas gathering facilities and transportation
pipelines. Total oil revenues were $8.4 million for the nine months ended September 30, 2009, a
decrease of $3.6 million from $12.0 million for the nine months ended September 30, 2008. This
decrease resulted primarily from a $4.2 million decrease associated with lower average realized oil
prices, partially offset by a $0.5 million increase associated with higher production volumes.
73
Appalachia production costs were $14.1 million for the nine months ended September 30, 2009,
an increase of $4.6 million from $9.5 million for the nine months ended September 30, 2008. This
increase was principally due to a $2.5 million increase in water hauling and disposal costs and a
$0.8 million increase associated with an increase in the number of Marcellus Shale wells we
drilled from the prior year comparable period, partially offset by a decrease of $1.4 million
associated with the Companys proportionate share of lease operating expenses associated with its
revenue that was subordinated to the investor partners within its investment partnerships.
Michigan/Indiana production costs were $19.1 million for the nine months ended September 30, 2009,
a decrease of $7.1 million from $26.2 million for the nine months ended September 30, 2008. This
decrease was primarily attributable to a $5.7 million decrease in production taxes due to a state
reduction in the production tax rate on January 1, 2009 and other production cost decreases when
compared with the prior year comparable period.
PARTNERSHIP MANAGEMENT
Well Construction and Completion
Drilling Program Results. The number of wells we drill will vary depending on the
amount of money we raise through our investment partnerships, the cost of each well, the depth or
type of each well, the estimated recoverable reserves attributable to each well and accessibility
to the well site. The following table presents the number of gross and net development wells we
drilled exclusively for us and for our investment partnerships during the three and nine months
ended September 30, 2009 and 2008. We did not drill any exploratory wells during the three and
nine months ended September 30, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Gross: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
27 |
|
|
|
242 |
|
|
|
153 |
|
|
|
733 |
|
Michigan/Indiana |
|
|
11 |
|
|
|
49 |
|
|
|
51 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38 |
|
|
|
291 |
|
|
|
204 |
|
|
|
868 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
|
26 |
|
|
|
242 |
|
|
|
126 |
|
|
|
672 |
|
Michigan/Indiana |
|
|
11 |
|
|
|
49 |
|
|
|
44 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37 |
|
|
|
291 |
|
|
|
170 |
|
|
|
807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Well construction and completion revenues and costs and expenses incurred represent the
billings and costs associated with the completion of wells for investment partnerships we sponsor.
The following table sets forth information relating to these revenues and the related costs and
number of net wells drilled and completed during the periods indicated (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Average construction and completion: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue per well |
|
$ |
2,328 |
|
|
$ |
483 |
|
|
$ |
1,487 |
|
|
$ |
511 |
|
Cost per well |
|
|
1,975 |
|
|
|
420 |
|
|
|
1,261 |
|
|
|
444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit per well |
|
$ |
353 |
|
|
$ |
63 |
|
|
$ |
226 |
|
|
$ |
67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit margin |
|
$ |
12,358 |
|
|
$ |
15,260 |
|
|
$ |
38,995 |
|
|
$ |
44,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net wells drilled and completed: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marcellus Shale |
|
|
22 |
|
|
|
26 |
|
|
|
64 |
|
|
|
68 |
|
Chattanooga Shale |
|
|
4 |
|
|
|
30 |
|
|
|
9 |
|
|
|
75 |
|
Michigan/Indiana |
|
|
11 |
|
|
|
|
|
|
|
44 |
|
|
|
|
|
Other shallow |
|
|
|
|
|
|
186 |
|
|
|
53 |
|
|
|
529 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37 |
|
|
|
242 |
|
|
|
170 |
|
|
|
672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74
Well construction and completion segment margin was $12.4 million for the three months ended
September 30, 2009, a decrease of $2.9 million from $15.3 million for the three months ended
September 30, 2008. This decrease was due to a $73.0 million decrease associated with a decrease
in the number of wells drilled, partially offset by a $70.1 million increase associated with the an
increase in the gross profit per well. Since our drilling contracts are on a cost-plus basis
(typically cost-plus 18%), an increase in our average cost per well also results in a proportionate
increase in our average revenue per well, which directly affects the number of wells we drill.
Average cost and revenue per well have increased due to a shift from drilling less expensive
shallow wells to more expensive deep or horizontal shale wells in Appalachia and in
Michigan/Indiana during the three and nine months ended September 30, 2009 in comparison to the
prior year comparable periods.
Well construction and completion segment margin was $39.0 million for the nine months ended
September 30, 2009, a decrease of $5.8 million from $44.8 million for the nine months ended
September 30, 2008. The decrease in segment margin was due to a $112.5 million decrease associated
with a decrease in the number of wells drilled, partially offset by a $106.7 million increase
associated with an increase in the gross profit per well.
Our consolidated balance sheet at September 30, 2009 includes $16.6 million of liabilities
associated with drilling contracts for funds raised by our investment partnerships that have not
been applied to the completion of wells due to the timing of drilling operations, and thus had not
been recognized as well construction and completion revenue on our consolidated statements of
operations. We expect to recognize this amount as revenue during the fourth quarter of 2009.
Administration and Oversight
Administration and oversight represents supervision and administrative fees earned for the
drilling and subsequent ongoing management of wells for our investment partnerships. Administration
and oversight fees were $3.1 million for the three months ended September 30, 2009, a decrease of
$2.1 million from $5.2 million for the three months ended September 30, 2008. This decrease was due
to a decrease in the number of wells drilled during the period in comparison to the prior year.
Administration and oversight fees were $9.6 million for the nine months ended September 30, 2009, a
decrease of $5.8 million from $15.4 million for the nine months ended September 30, 2008. This
decrease was primarily a result of a decrease associated with fewer wells drilled during the period
in comparison to the prior year.
Well Services
Well service revenue and expenses represent the monthly operating fees we charge and the work
our service company performs for our investment partnership wells during the drilling and
completing phase as well as ongoing maintenance of these wells and other wells in which we serve as
operator.
Well services revenues were $5.0 million for the three months ended September 30, 2009, a
decrease of $0.3 million from $5.3 million for the three months ended September 30, 2008. This
decrease was principally attributable to the slowdown in drilling for shallow wells for our
investment partnerships. Well services expenses were $2.4 million for the three months ended
September 30, 2009, a decrease of $0.4 million from $2.8 million for the three months ended
September 30, 2008. This decrease was primarily attributable to a decrease in labor costs
associated with drilling a large number of shallow wells in prior periods to fewer, but more
productive, wells for our investment partnerships during the current period.
75
Well services revenues were $14.9 million for the nine months ended September 30, 2009, a
decrease of $0.5 million from $15.4 million for the nine months ended September 30, 2008. This
decrease was primarily attributable to the slowdown in drilling for shallow wells for our
investment partnerships, partially offset by an increase in well operating revenues for the
investment partnership wells put into operation during the twelve months ended September 30, 2009.
Well services expenses were $6.9 million for the nine months ended September 30, 2009, a decrease
of $0.9 million from $7.8 million for the nine months ended September 30, 2008. This decrease was
primarily attributable to a decrease in labor costs associated with drilling a large number of
shallow wells in prior periods to fewer, but more productive, wells for our investment partnerships
during the current period.
TRANSMISSION, GATHERING & PROCESSING
Transmission, gathering and processing revenue includes our gathering fees to our investment
partnership wells that are connected to Laurel Mountains Appalachian gathering systems and the
operating revenues and expenses of Atlas Pipeline. On May 31, 2009, APL contributed its Appalachian
gathering systems to Laurel Mountain, a joint venture in which APL retained a 49% ownership
interest. Under new gas gathering agreements with Laurel Mountain entered into upon formation of
the joint venture, we are obligated to pay to Laurel Mountain all of the gathering fees we collect
from the partnerships. During the period from January 1, 2009 to May 31, 2009, we were required to
remit these gathering fees to APL, which are eliminated when we consolidate APLs financial
statements.
The gathering fee generally ranges from $0.35 per Mcf to the amount of the competitive
gathering fee, currently defined as 13% of the gross sales price. Pursuant to our new agreements
with Laurel Mountain, we must also pay an additional amount equal to the excess of the gathering
fees collected from the investment partnerships up to an amount equal to approximately 16% of the
natural gas sales price. As a result of our agreements with Laurel Mountain, our Appalachian
gathering expenses within our partnership management segment will generally exceed the revenues
collected from the investment partnerships by approximately 3%. We also pay our proportionate
share of gathering fees based on our percentage interest in the well, which is included in gas and
oil production expense. The net effect of the elimination amounts is eliminated against our
pro-rata portion of production costs from our investment partnerships in our consolidated
statements of operations.
The following table presents our gathering revenues and expenses and those attributable to
Atlas Pipeline for each of the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
Transmission, Gathering and |
|
September 30, |
|
|
September 30, |
|
Processing |
|
2009 |
|
|
2008(1) |
|
|
2009 |
|
|
2008(1) |
|
Atlas Energy: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
6,098 |
|
|
$ |
4,886 |
|
|
$ |
16,210 |
|
|
$ |
15,151 |
|
Expense |
|
|
(7,972 |
) |
|
|
(8,531 |
) |
|
|
(24,205 |
) |
|
|
(24,293 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
$ |
(1,874 |
) |
|
$ |
(3,645 |
) |
|
$ |
(7,995 |
) |
|
$ |
(9,142 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Pipeline: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
199,505 |
|
|
$ |
418,077 |
|
|
$ |
555,929 |
|
|
$ |
1,235,976 |
|
Expense |
|
|
(159,890 |
) |
|
|
(333,851 |
) |
|
|
(458,384 |
) |
|
|
(992,113 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
$ |
39,615 |
|
|
$ |
84,226 |
|
|
$ |
97,545 |
|
|
$ |
243,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eliminations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
|
|
|
$ |
(12,021 |
) |
|
$ |
(16,766 |
) |
|
$ |
(32,768 |
) |
Expense |
|
|
|
|
|
|
8,394 |
|
|
|
11,837 |
|
|
|
23,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
$ |
|
|
|
$ |
(3,627 |
) |
|
$ |
(4,929 |
) |
|
$ |
(8,866 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
205,603 |
|
|
$ |
410,942 |
|
|
$ |
555,373 |
|
|
$ |
1,218,359 |
|
Expense |
|
|
(167,862 |
) |
|
|
(333,988 |
) |
|
|
(470,752 |
) |
|
|
(992,504 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Margin |
|
$ |
37,741 |
|
|
$ |
76,954 |
|
|
$ |
84,621 |
|
|
$ |
225,855 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system. |
76
Our net gathering fee expense for the three months ended September 30, 2009 was $1.9
million compared with $3.6 million for the prior year comparable period, and $8.0 million and $9.1
million for the nine months ended September 30, 2009 compared with $9.1 million for the prior year
comparable period. These favorable decreases were principally due to lower average gas sales prices
between periods.
Transmission, gathering and processing margin for Atlas Pipeline was $39.6 million for the
three months ended September 30, 2009 compared with $84.2 million for the prior year comparable
period, and $97.5 million for the nine months ended September 30, 2009 compared with $243.9 million
for the prior year comparable period. These decreases were due principally to lower average
commodity prices between periods.
GAIN ON ASSET SALES
Gain on asset sales of $105.7 million for the nine months ended September 30, 2009 principally
represents the gain recognized on APLs sale of a 51% ownership interest in its Appalachia natural
gas gathering system to the Laurel Mountain joint venture.
LOSS ON MARK-TO-MARKET DERIVATIVES
Gain on mark-to-market derivatives was $1.0 million for the three months ended September 30,
2009 compared with $147.5 million for the comparable prior year period. The unfavorable movement
was due primarily to a $223.0 million unfavorable movement in non-cash mark-to-market adjustments
on APL derivatives, partially offset by the absence in the current period of a $70.3 million net
cash derivative expense related to the early termination of a portion of its derivative contracts.
The unfavorable movement in non-cash mark-to-market adjustments on APL derivatives was due
principally to a $235.0 million gain during the three months ended September 30, 2008, which was
due to a decrease in forward crude oil market prices from June 30, 2008 to September 30, 2008 and
their favorable mark-to-market impact on certain non-qualified derivative contracts APL had for
production volumes in future periods. Average forward crude oil prices,
which are the basis for adjusting the fair value of APLs crude oil derivative contracts, at
September 30, 2008, were $102.64 per barrel, a decrease of $37.48 per barrel from average forward
crude oil market prices at June 30, 2008 of $140.12 per barrel.
Loss on mark-to-market derivatives was $17.2 million for the nine months ended September 30,
2009 compared with $257.3 million for the comparable prior year period. This favorable movement was
due primarily to the absence in the current year period of APLs $186.1 million net cash derivative
expense related to the early termination of a portion of its derivative contracts, a $74.6 million
favorable movement in APLs non-cash derivative gains related to the early termination of a portion
of its derivative contracts, and a $28.3 million favorable movement related to APLs cash
settlements on derivatives that were not designated as hedges, partially offset by an unfavorable
movement of $43.0 million in APLs non-cash mark-to-market adjustments on derivatives.
77
OTHER COSTS AND EXPENSES
General and Administrative
The following table presents our general and administrative expenses and those attributable to
Atlas Pipeline and Atlas Pipeline Holdings for each of the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008(1) |
|
|
2009(1) |
|
|
2008(1) |
|
General and Administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Energy |
|
$ |
22,532 |
|
|
$ |
14,435 |
|
|
$ |
54,631 |
|
|
$ |
43,916 |
|
Atlas Pipeline and Atlas Pipeline Holdings |
|
|
9,534 |
|
|
|
(1,788 |
) |
|
|
26,988 |
|
|
|
14,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
32,066 |
|
|
$ |
12,647 |
|
|
$ |
81,619 |
|
|
$ |
58,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system. |
Total general and administrative expenses, including amounts reimbursed to affiliates,
increased to $32.1 million for the three months ended September 30, 2009 compared with $12.6
million for the comparable prior year period. This $19.5 million increase was primarily due to our
$8.1 million increase and a $11.4 million increase related to APL and AHD. Our $8.1 million
increase was principally attributable to $6.2 million of professional fees incurred related to the
Merger and a $1.9 million increase in expenses related wages and other corporate activities due to
the growth of our business. The $11.4 million increase in general and administrative expense for
APL and AHD was due principally to a $13.3 million mark-to-market gain recognized during the three
months ended September 30, 2008 for certain APL common unit awards that were based on the financial
performance of certain assets during 2008, partially offset by a $1.9 million decrease in wages and
other corporate activities. The mark-to-market gain was the result of a significant change in
APLs common unit market price at September 30, 2008 when compared with the June 30, 2008 price,
which was utilized in the estimate of the non-cash compensation expense for these awards.
Total general and administrative expenses, including amounts reimbursed to affiliates,
increased to $81.6 million for the nine months ended September 30, 2009 compared with $58.6 million
for the comparable prior year period. This $23.0 million increase was primarily due to our $10.7
million increase and a $12.3 million increase related to APL and AHD. Our $10.7 million increase
was principally attributable to $6.8 million of professional fees incurred related to the Merger
and a $3.9 million increase in expenses related wages and other corporate activities due to the
growth of our business. The $12.3 million increase in general and administrative expense for APL
and AHD was due principally to a $13.3 million mark-to-market gain recognized during the nine
months ended September 30, 2008 for certain APL common unit awards, partially offset by a $1.0
million decrease in wages and other corporate activities.
Depreciation, depletion and amortization
The following table presents our depreciation, depletion and amortization expense and that
which is attributable to APL and AHD for each of the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008(1) |
|
|
2009(1) |
|
|
2008(1) |
|
Depreciation, depletion and amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Energy |
|
$ |
24,563 |
|
|
$ |
23,584 |
|
|
$ |
79,863 |
|
|
$ |
68,339 |
|
APL and AHD |
|
|
21,897 |
|
|
|
20,741 |
|
|
|
67,564 |
|
|
|
61,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
46,460 |
|
|
$ |
44,325 |
|
|
$ |
147,427 |
|
|
$ |
129,539 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system. |
78
Total depreciation, depletion and amortization increased to $46.5 million for the three
months ended September 30, 2009 compared with $44.3 million for the comparable prior year period,
and $147.4 million for the nine months ended September 30, 2009 compared with $129.5 million for
the comparable prior year period, due primarily to an increase in our depletable basis and
production volumes and APLs expansion capital expenditures incurred subsequent to September 30,
2008. The following table shows our depletion expense, excluding amounts attributable to APL and
AHD, per Mcfe for our Appalachia and Michigan/Indiana regions for the three and nine months ended
September 30, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Depletion Expense (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
$ |
9,383 |
|
|
$ |
9,544 |
|
|
$ |
34,645 |
|
|
$ |
25,942 |
|
Michigan/Indiana |
|
|
14,103 |
|
|
|
13,164 |
|
|
|
41,967 |
|
|
|
39,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
23,486 |
|
|
$ |
22,708 |
|
|
$ |
76,612 |
|
|
$ |
65,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion expense as a
percentage of gas and oil
production |
|
|
36 |
% |
|
|
28 |
% |
|
|
37 |
% |
|
|
28 |
% |
Depletion per Mcfe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia |
|
$ |
2.47 |
|
|
$ |
2.84 |
|
|
$ |
2.99 |
|
|
$ |
2.75 |
|
Michigan/Indiana |
|
$ |
2.62 |
|
|
$ |
2.40 |
|
|
$ |
2.63 |
|
|
$ |
2.43 |
|
Total |
|
$ |
2.55 |
|
|
$ |
2.57 |
|
|
$ |
2.79 |
|
|
$ |
2.55 |
|
Depletion expense varies from period to period and is directly affected by changes in our oil
and gas reserve quantities, production levels, product prices and changes in the depletable cost
basis of our oil and gas properties. Our depletion expense (including accretion of our asset
retirement obligations) of oil and gas properties as a percentage of oil and gas revenues was 36%
for the three months ended September 30, 2009, compared with 28% for the three months ended
September 30, 2008. Depletion expense per Mcfe was $2.55 for the three months ended September 30,
2009, a decrease of $0.02 per Mcfe from $2.57 for the three months ended September 30, 2008.
Increases in our depletable basis and production volumes caused depletion expense to increase $0.8
million to $23.5 million for the three months ended September 30, 2009 compared with $22.7 million
for the three months ended September 30, 2008.
Depletion of oil and gas properties as a percentage of oil and gas revenues was 37% for the
nine months ended September 30, 2009, compared with 28% for the nine months ended September 30,
2008. Depletion expense per Mcfe was $2.79 for the nine months ended September 30, 2009, an
increase of $0.24 (9%) per Mcfe from $2.55 for the nine months ended September 30, 2008. Increases
in our depletable basis and production volumes caused depletion expense to increase $10.8 million
to $76.6 million for the nine months ended September 30, 2009 compared with $65.8 million for the
nine months ended September 30, 2008.
Interest Expense
The following table presents our interest expense and that which is attributable to APL and
AHD for each of the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008(1) |
|
|
2009(1) |
|
|
2008(1) |
|
Interest Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Atlas Energy |
|
$ |
19,133 |
|
|
$ |
14,769 |
|
|
$ |
47,184 |
|
|
$ |
42,580 |
|
APL and AHD |
|
|
28,621 |
|
|
|
22,562 |
|
|
|
77,138 |
|
|
|
63,958 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
47,754 |
|
|
$ |
37,331 |
|
|
$ |
124,322 |
|
|
$ |
106,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system. |
79
Total interest expense increased to $47.8 million for the three months ended September
30, 2009 as compared with $37.3 million for the comparable prior year period. This $10.5 million
increase was primarily due to our $4.4 million increase and a $6.1 million increase related to APL
and AHD. Our $4.4 million increase was principally attributable to a $5.3 million increase
associated with the issuance of ATNs $200.0 million of 12.125% Senior Notes in July 2009 (see
Recent Developments) and a $0.1 million increase associated with borrowings under ATNs credit
facility, partially offset by a $0.8 million increase in capitalized interest. The $0.1 million
increase associated with ATNs credit facility was primarily due to lower average borrowings
outstanding due to the repayment of amounts from the net proceeds of the 12.125% Senior Notes,
partially offset by higher weighted average interest rates between periods. The $6.1 million
increase in interest expense for APL and AHD was due principally to a $4.2 million increase
associated with higher borrowings under APLs credit facility, $1.2 million of lower capitalized
interest, and a $1.0 million increase in interest expense associated with APLs senior secured term
loan, partially offset by a $0.8 million decrease associated with the repayment of certain amounts
of APLs senior notes.
Total interest expense increased to $124.3 million for the nine months ended September 30,
2009 as compared with $106.5 million for the comparable prior year period. This $17.8 million
increase was primarily due to our $4.6 million increase and a $13.2 million increase related to APL
and AHD. Our $4.6 million increase was principally attributable to an $11.6 million increase
associated with the issuances of ATNs senior unsecured notes in July 2009 and May 2008, partially
offset by a $3.7 million increase associated with borrowings under ATNs credit facility and a $3.3
million increase in capitalized interest. The $3.7 million increase associated with ATNs credit
facility was primarily due to lower average interest rates and borrowings outstanding due to the
repayment of amounts from the net proceeds of the issuances of senior notes. The $13.2 million
increase in interest expense for APL and AHD was due principally to a $8.2 million increase
associated with the issuances of APL senior notes in June 2008, a $6.2 million increase associated
with higher borrowings under APLs credit facility, $2.7 million of lower capitalized interest, and
a $2.6 million increase in amortization of deferred finance costs, partially offset by a $6.4
million decrease associated with the repayment of certain amounts of APLs senior secured term
loan.
Income Taxes
Income tax benefit was $0.7 million for the three months ended September 30, 2009 compared
with income tax expense of $13.6 million for the comparable prior year period, and income tax
expense was $5.6 million for the nine months ended September 30, 2009 compared with $12.3 million
for the comparable prior year period. Our effective income tax rate attributable to common
shareholders was 38.4% and 36.6% for the nine months ended September 30, 2009 and 2008,
respectively. The increase in our effective income tax rate between periods was the result of a
reduction in tax benefits related to depletion and tax-exempt interest income relative to income
(loss) before taxes. We recognize our income tax provision (benefit) for interim periods based
upon our estimate of the effective income tax rate we will achieve for the full fiscal year, with
the effects of any change in the estimated effective income tax rate for the full fiscal year
recognized within income tax provision (benefit) for the current interim period. Currently, it is
our expectation that our effective income tax rate will approximate 39.0% for the year ended
December 31, 2009.
Income from Discontinued Operations
Income from discontinued operations, net of income tax, which consists of amounts associated
with APLs NOARK gas gathering and interstate pipeline system that was sold in May 2009, was $6.3
million for the three months ended September 30, 2008. Income from discontinued operations
increased to $59.8 million for the nine months ended September 30, 2009 compared with $20.2 million
for the comparable prior year period. The increase was due to the $48.9 million gain, net of
income tax expense of $2.2 million, APL
recognized on the sale of the NOARK system, partially offset by a $9.3 million decrease in the
operating results of the system, net of income taxes, due to its sale.
80
Income (Loss) Attributable to Non-controlling Interests
Income (loss) attributable to non-controlling interest was a benefit of $9.2 million for the
three months ended September 30, 2009 compared with an expense of $194.1 million for the prior year
comparable period. Non-controlling interest includes an allocation of APLs and AHDs net income
(loss) to non-controlling interest holders, as well as an allocation of ATNs net income prior to
the Merger on September 29, 2009 to its non-controlling interest holders. The change between
periods was primarily due to a decrease in APLs net earnings.
Income (loss) attributable to non-controlling interests was an expense of $103.7 million for
the nine months ended September 30, 2009 compared with a benefit of $60.8 million for the prior
year comparable period. This change was primarily due to an increase in ATNs and APLs net
earnings between periods.
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated from operations, capital raised through
investment partnerships and borrowings under ATNs credit facility. Our primary cash requirements,
in addition to normal operating expenses, are for debt service and capital expenditures. In
general, we expect to fund:
|
|
|
capital expenditures and working capital deficits through the retention of cash,
additional borrowings and capital raised through investment partnerships; and |
|
|
|
|
debt principal payments through additional borrowings as they become due or by the
issuance of additional common shares. |
At September 30, 2009, ATN had $328.8 million of available committed capacity under its credit
facility, subject to covenant limitations, to fund working capital obligations. In July 2009, ATN
issued $200.0 million of 12.125% Senior Notes due 2017 at 98.116% of par value to yield 12.5% at
maturity (see Recent Developments). We used the net proceeds of $191.7 million, net underwriting
fees of $4.5 million, to repay outstanding borrowings under ATNs revolving credit facility. Under
the terms of ATNs credit facility, the credit facility borrowing base is automatically reduced by
25% of the stated principal amount of any senior unsecured notes offering by ATN. As such, the
borrowing base of its credit facility was reduced by $50.0 million to $600.0 million upon the
issuance of the 12.125% Senior Notes.
We believe that we will have sufficient liquid assets, cash from operations and borrowing
capacity to meet our financial commitments, debt service obligations, contingencies and anticipated
capital expenditures for at least the next twelve-month period. However, we are subject to
business, operational and other risks that could adversely affect our cash flow. We may supplement
our cash generation with proceeds from financing activities, including borrowings under ATNs
credit facilities and other borrowings, the issuance of additional common shares and units and the
sale of assets.
Recent instability in the financial markets, as a result of recession or otherwise, has
increased the cost of capital while the availability of funds has diminished significantly. This
may affect our ability to raise capital and reduce the amount of cash available to fund its
operations. We rely on cash flow from operations and ATNs credit facility to execute their growth
strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be
certain that additional capital will be available to us to the extent required and on acceptable
terms. We believe that we will have sufficient liquid assets, cash from operations and borrowing
capacity to meet our financial commitments, debt service obligations, contingencies and anticipated
capital expenditures for at least the next twelve month period.
81
Cash Flows Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
Net cash provided by operating activities of $124.0 million for the nine months ended
September 30, 2009 represented a favorable movement of $266.1 million from net cash used in
operating activities of $142.1 million for the comparable prior year period. The increase was
derived principally from a $145.1 million increase in net income excluding non-cash items and a
$134.1 million favorable movement in distributions paid to non-controlling interest holders and a
$23.7 million unfavorable movement in working capital changes, partially offset by a $22.4 million
unfavorable movement in cash provided by discontinued operations. The non-cash charges which
impacted net income include favorable movements in income from continuing operations of $115.4
million and favorable increases in non-cash loss on derivatives of $101.1 million, partially offset
by a decrease related to $105.2 million of gains on asset sales. The movement in cash
distributions to non-controlling interest holders is due mainly to decreases in the cash
distributions of our consolidated subsidiaries, including ATNs prior to the Merger. The movement
in working capital was principally due to a $26.6 million favorable movement in accounts receivable
and other current assets, partially offset by a $2.6 million unfavorable movement in accrued
liabilities and other current liabilities. The movement in non-cash derivative losses resulted
from decreases in commodity prices during the nine months ended September 30, 2009 and their
favorable impact on the fair value of derivative contracts ATN and APL have for future periods.
Net cash provided by investing activities of $133.8 million for the nine months ended
September 30, 2009 represented a favorable movement of $573.3 million from $439.5 million of net
cash used in investing activities for the comparable prior year period. This favorable movement
was principally due to a $313.2 million favorable movement in cash provided by discontinued
operations, a $120.6 million increase in proceeds from assets sales due primarily to the sale of
APLs Appalachia segment assets to the Laurel Mountain joint venture and a decrease in our and
APLs capital expenditures of $180.3 million, partially offset by a prior year period receipt of
$31.4 million of cash proceeds from acquisition purchase price adjustments. The $313.2 million
favorable movement in cash provided by discontinued operations was principally the result of $294.5
million of net cash proceeds from the sale of APLs NOARK system assets. See further discussion of
capital expenditures under Capital Requirements.
Net cash used in financing activities of $326.6 million for the nine months ended September
30, 2009 represented an unfavorable movement of $887.5 million from $560.9 million of net cash
provided by financing activities for the comparable prior year period. This unfavorable movement
was principally due to a $455.7 million reduction in net proceeds from APL and ATNs issuance of
debt, and a $273.3 million reduction in net proceeds from APL and ATNs issuance of equity and a
$166.8 million favorable movement in subsidiary borrowings under their respective credit
facilities.
Capital Requirements
Our capital requirements consist primarily of:
|
|
|
capital expenditures we make to expand our capital asset base for longer than the
short-term and include new leasehold interests and the development and exploitation of
existing leasehold interests through acquisitions and investments in our drilling
partnerships; and |
|
|
|
|
our commitment to invest a maximum of $20.0 million in Lightfoot, of which we had
invested $10.7 million at September 30, 2009. |
82
The following table summarizes our consolidated capital expenditures, including those for
Atlas Pipeline, excluding amounts paid for acquisitions, for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008(1) |
|
|
2009 |
|
|
2008(1) |
|
Atlas Energy |
|
$ |
34,372 |
|
|
$ |
89,300 |
|
|
$ |
130,785 |
|
|
$ |
224,970 |
|
Atlas Pipeline |
|
|
7,116 |
|
|
|
81,714 |
|
|
|
137,610 |
|
|
|
223,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
41,488 |
|
|
$ |
171,014 |
|
|
$ |
268,395 |
|
|
$ |
448,738 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Restated to reflect amounts reclassified to discontinued operations due to APLs sale
of its NOARK gas gathering and interstate pipeline system. |
During the three months ended September 30, 2009, our capital expenditures related
primarily to $16.3 million of investments in our investment partnerships compared with $44.2
million for the three months ended September 30, 2008. For the three months ended September 30,
2009, we also invested $3.7 million in leasehold acreage, $4.9 million in wells drilled exclusively
for our own account, and we incurred $3.8 million in construction costs related to two gas
processing plants in Tennessee. During the nine months ended September 30, 2009, our capital
expenditures related primarily to $67.9 million of investments in our investment partnerships
compared with $110.6 million for the nine months ended September 30, 2008. For the nine months
ended September 30, 2009, we also invested $17.0 million in wells drilled exclusively for our own
account, incurred $20.3 million in leasehold acquisition costs, and we incurred $10.2 million in
construction costs related to two gas processing plants in Tennessee. We funded and expect to
continue to fund these capital expenditures through cash on hand, cash flows from operations and
from amounts available under ATNs credit facility.
The level of capital expenditures we devote to our exploration and production operations
depends upon any acquisitions made and the level of funds raised through our investment
partnerships. We believe cash flows from operations and amounts available under ATNs credit
facility will be adequate to fund our capital expenditures. However, the amount of funds we raise
and the level of our capital expenditures will vary in the future depending on market conditions
for natural gas and other factors. We expect to fund our capital expenditures with cash flow from
our operations, borrowings under ATNs credit facility, and with the temporary use of funds raised
in our investment partnerships in the period before we invest the funds.
We continuously evaluate acquisitions of gas and oil assets. In order to make any
acquisition, we believe we will be required to access outside capital either through debt or equity
placements or through joint venture operations with other energy companies. There can be no
assurance that we will be successful in our efforts to obtain outside capital.
Atlas Pipeline Partners. APLs capital expenditures decreased to $7.1 million and $137.6
million for the three and nine months ended September 30, 2009, respectively, compared with $81.7
million and $223.8 million, respectively, for the prior year comparable periods. The decrease was
due principally to APLs construction of a 60 MMcfd expansion of its Sweetwater processing plant
and the construction of its Madill to Velma pipeline during the prior year, decreases in capital
expenditures related to the sale of its NOARK system and its 49% ownership interest in the
Appalachia system, and other decreases in capital spending related to the expansion of its
gathering system.
As of September 30, 2009, APL is committed to expend approximately $17.8 million on pipeline
extensions, compressor station upgrades and processing facility upgrades.
Off Balance Sheet Arrangements
As of September 30, 2009, our off balance sheet arrangements are limited to our guarantee of
Crown Drilling of Pennsylvania, LLCs $11.4 million credit agreement, ATNs and APLs letters of
credit outstanding of $1.2 million and $9.1 million, respectively, and APLs commitments to expend
approximately $17.8 million on capital projects. In addition, we are committed to invest a total
of $20.0 million in Lightfoot, of which $10.7 million has been invested as of September 30, 2009.
83
Issuances of Subsidiary Common Units
We gains on our subsidiaries equity transactions as a credit to equity rather than as income.
These gains represent our portion of the excess net offering price per unit of each of our
subsidiaries units to the book carrying amount per unit.
Atlas Pipeline Partners and Atlas Pipeline Holdings
In August 2009, APL sold 2,689,765 common units in a private placement at an offering price of
$6.35 per unit, yielding net proceeds of approximately $16.1 million. APL also received a capital
contribution from AHD of $0.4 million for AHD to maintain its 2.0% general partner interest in APL.
In addition, APL issued warrants granting investors in our private placement the right to purchase
an additional 2,689,765 common units at a price of $6.35 per unit for a period of two years
following the issuance of the original common units. APL utilized the net proceeds from the common
unit offering to repay a portion of its indebtedness under its senior secured term loan, and will
make similar repayments with net proceeds from future exercises of the warrants.
The common units and warrants sold by APL in the August 2009 private placement are subject to
a registration rights agreement entered into in connection with the transaction. The registration
rights agreement required APL to (a) file a registration statement with the Securities and Exchange
Commission for the privately placed common units and those underlying the warrants by September 21,
2009 and (b) cause the registration statement to be declared effective by the Securities and
Exchange Commission by November 18, 2009. APL filed a registration statement with the Securities
and Exchange Commission in satisfaction of the registration requirements of the registration rights
agreement on September 3, 2009, and the registration statement was declared effective on October
14, 2009.
In June 2008, APL sold 5,750,000 common units in a public offering at a price of $37.52 per
unit, yielding net proceeds of approximately $206.6 million. Also in June 2008, we purchased
308,109 AHD common units and 1,112,000 APL common limited partner units through a private placement
transaction at a price of $32.50 and $36.02 per unit, respectively, for net proceeds of
approximately $10.0 million and $40.1 million, respectively. APL also received a capital
contribution from AHD of $5.4 million for AHD to maintain its 2.0% general partner interest in it.
APL utilized the net proceeds from both the sales of common units and the capital contribution from
AHD to fund the early termination of certain derivative agreements.
Shelf
Registration Statement
In
May 2009, ATNs shelf registration statement was declared
effective by the Securities and Exchange Commission. The registration
statement permits it to periodically issue up to $500.0 million
of debt securities. In July 2009, ATN filed an additional shelf
registration in connection with its July 2009 senior notes
offering (see Recent Developments). The amount, type and
timing of any additional offerings will depend upon, among other
things, its funding requirements, prevailing market conditions and
compliance with its credit facility and unsecured senior note
covenants.
Dividends
We paid cash dividends of $2.0 million for the three months ended March 31, 2009, but we did
not pay cash dividends for both the three months ended September 30, 2009 and June 30, 2009. The
determination of the amount of future cash dividends, if any, is at the sole discretion of our
board of directors and will depend on the various factors affecting our financial condition and
other matters the board of directors deems relevant.
84
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires making estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date
of the financial statements and the reported amounts of actual revenue and expenses during the
reporting period. Although we base our estimates on historical experience and various other
assumptions that we believe to be reasonable under the circumstances, actual results may differ
from the estimates on which our financial statements are prepared at any given point of time.
Changes in these estimates could materially affect our financial position, results of
operations or cash flows. Significant items that are subject to such estimates and
assumptions include revenue and expense accruals, deferred tax assets and liabilities, depletion,
depreciation and amortization, asset impairment, fair value of derivative instruments, the
probability of forecasted transactions and the allocation of purchase price to the fair value of
assets acquired. A discussion of our significant accounting policies we have adopted and followed
in the preparation of our consolidated financial statements is included within our Annual Report on
Form 10-K for the year ended December 31, 2008 and in Note 2 under Item 1, Financial Statements
included in this report, and there have been no material changes to these policies through
September 30, 2009.
Fair Value of Financial Instruments
We have established a hierarchy to measure our financial instruments at fair value which
requires us to maximize the use of observable inputs and minimize the use of unobservable inputs
when measuring fair value. The hierarchy defines three levels of inputs that may be used to
measure fair value:
Level 1 Unadjusted quoted prices in active markets for identical, unrestricted assets and
liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 Inputs other than quoted prices included within Level 1 that are observable for
the asset and liability or can be corroborated with observable market data for substantially
the entire contractual term of the asset or liability.
Level 3 Unobservable inputs that reflect the entitys own assumptions about the assumption
market participants would use in the pricing of the asset or liability and are consequently
not based on market activity but rather through particular valuation techniques.
We use a fair value methodology to value the assets and liabilities for its, AHDs and APLs
outstanding derivative contracts and our Supplemental Employment Retirement Plan (SERP). Our and
APLs commodity hedges, with the exception of APLs NGL fixed price swaps and NGL options, are
calculated based on observable market data related to the change in price of the underlying
commodity and are therefore defined as Level 2 fair value measurements. Our, AHDs and APLs
interest rate derivative contracts are valued using a LIBOR rate-based forward price curve model
and are therefore defined as Level 2 fair value measurements. Our SERP is calculated based on
observable actuarial inputs developed by a third-party actuary and therefore is defined as a Level
2 fair value measurement, while the asset related to the funding of the SERP in a rabbi trust is
based on third-party financial statements and is therefore also defined as a Level 2 fair value
measurement. Valuations for APLs NGL fixed price swaps are based on a forward price curve modeled
on a regression analysis of natural gas, crude oil and propane prices and therefore are defined as
Level 3 fair value measurements. Valuations for APLs NGL options are based on forward price
curves developed by the related financial institution and therefore are defined as Level 3 fair
value measurements.
Liabilities that are required to be measured at fair value on a nonrecurring basis include our
asset retirement obligations (AROs) that are defined as Level 3. Estimates of the fair value of
AROs are based on discounted cash flows using numerous estimates, assumptions, and judgments
regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.
85
Recently Adopted Accounting Standards
In August 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update 2009-05, Fair Value Measurements and Disclosures (Topic 820) Measuring Liabilities at
Fair Value (Update 2009-05). Update 2009-05 amends Subtopic 820-10, Fair Value Measurements
and Disclosures Overall and provides clarification for the fair value measurement of liabilities
in circumstances where quoted prices for an identical liability in an active market are not
available. The amendments also
provide clarification for not requiring the reporting entity to include separate inputs or
adjustments to other inputs relating to the existence of a restriction that prevents the transfer
of a liability when estimating the fair value of a liability. Additionally, these amendments
clarify that both the quoted price in an active market for an identical liability at the
measurement date and the quoted price for an identical liability when traded as an asset in an
active market when no adjustments to the quoted price of the asset are required are considered
Level 1 fair value measurements. These requirements are effective for financial statements
issued after the release of Update 2009-05. We adopted the requirements on September 30, 2009, and
it did not have a material impact on our financial position, results of operations or related
disclosures.
In August 2009, the FASB issued Accounting Standards Update 2009-04, Accounting for
Redeemable Equity Instruments Amendment to Section 480-10-S99 (Update 2009-04). Update
2009-04 updates Section 480-10-S99, Distinguishing Liabilities from Equity, to reflect the SEC
staffs views regarding the application of Accounting Series Release No. 268, Presentation in
Financial Statements of Redeemable Preferred Stocks (ASR No. 268). ASR No. 268 requires
preferred securities that are redeemable for cash or other assets to be classified outside of
permanent equity if they are redeemable (1) at a fixed or determinable price on a fixed or
determinable date, (2) at the option of the holder, or (3) upon the occurrence of an event that is
not solely within the control of the issuer. We adopted the requirements of FASB Update 2009-04 on
August 1, 2009, and it did not have a material impact on our financial position, results of
operations or related disclosures.
In June 2009, the FASB issued Accounting Standards Update 2009-01, Topic 105 Generally
Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards
No. 168 The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles (Update 2009-01). Update 2009-01 establishes the FASB Accounting
Standards Codification (ASC) as the single source of authoritative U.S. generally accepted
accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC
supersedes all existing non-Securities and Exchange Commission accounting and reporting standards.
Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff
Positions or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting
Standards Updates, which will serve only to update the ASC. The ASC is effective for financial
statements issued for interim and annual periods ending after September 15, 2009. All required
references to non-SEC accounting standards have been modified by us. We adopted the requirements
of Update 2009-01 to our financial statements on September 30, 2009, and it did not have a material
impact to our financial statement disclosures.
In May 2009, the FASB issued ASC 855-10, Subsequent Events (ASC 855-10). ASC 855-10
establishes general standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or are available to be issued. The
provisions require management of a reporting entity to evaluate events or transactions that may
occur after the balance sheet date for potential recognition or disclosure in the financial
statements and provides guidance for disclosures that an entity should make about those events.
ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and
shall be applied prospectively. We adopted the requirements of this standard on June 30, 2009, and
it did not have a material impact to our financial position or results of operations or related
disclosures. The adoption of these provisions does not change our current practices with respect to
evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued ASC 820-10-65-4, Determining Fair Value When the Volume and
Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly (ASC 820-10-65-4). ASC 820-10-65-4 applies to all fair value
measurements and provides additional clarification on estimating fair value when the market
activity for an asset has declined significantly. ASC 820-10-65-4 also requires an entity to
disclose a change in valuation technique and related inputs to the valuation calculation and to
quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods
ending after June 15, 2009, with early adoption permitted for periods ending after
March 15, 2009. We adopted the requirements of ASC 820-10-65-4 on April 1, 2009, and our
adoption did not have a material impact on our financial position and results of operations.
86
In April 2009, the FASB issued ASC 320-10-65-1, Recognition and Presentation of
Other-Than-Temporary Impairments (ASC 320-10-65-1), which changes previously existing guidance
for determining whether an impairment is other than temporary for debt securities. ASC 320-10-65-1
replaces the previously existing requirement that an entitys management assess if it has both the
intent and ability to hold an impaired security until recovery with a requirement that management
assess that it does not have the intent to sell the security and that it is more likely than not
that it will not have to sell the security before recovery of its cost basis. ASC 320-10-65-1 also
requires that an entity recognize noncredit losses on held-to-maturity debt securities in other
comprehensive income and amortize that amount over the remaining life of the security and for the
entity to present the total other-than-temporary impairment in the statement of operations with an
offset for the amount recognized in other comprehensive income. ASC 320-10-65-1 is effective for
interim and annual periods ending after June 15, 2009, with early adoption permitted for periods
ending after March 15, 2009. We adopted these requirements on April 1, 2009, and our adoption did
not have a material impact on our financial position and results of operations.
In April 2009, the FASB issued ASC 825-10-65-1, Interim Disclosures about Fair Value of
Financial Instruments (ASC 825-10-65-1), which requires an entity to provide disclosures about
fair value of financial instruments in interim financial information. In addition, an entity shall
disclose in the body or in the accompanying notes of its summarized financial information for
interim reporting periods and in its financial statements for annual reporting periods the fair
value of all financial instruments for which it is practicable to estimate that value, whether
recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective
for interim periods ending after June 15, 2009, with early adoption permitted for periods ending
after March 15, 2009. We adopted these requirements on April 1, 2009, and our adoption did not
have a material impact on our financial position and results of operations.
In April 2009, the FASB issued ASC 805-20-30-23, Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from Contingencies (ASC 805-20-30-23),
which requires that assets acquired and liabilities assumed in a business combination that arise
from contingencies be recognized at fair value if fair value can be reasonably estimated. If fair
value of such an asset or liability cannot be reasonably estimated, the asset or liability would
generally be recognized in accordance with previous requirements. ASC 805-20-30-23 eliminates the
requirement to disclose an estimate of the range of outcomes of recognized contingencies at the
acquisition date. ASC 805-20-30-23 is effective for business combinations for which the
acquisition date is on or after the beginning of the first annual reporting period beginning on or
after December 15, 2008 (January 1, 2009 for the Company). We adopted the requirements on January
1, 2009, and our adoption did not have a material impact on our financial position and results of
operations.
In June 2008, the FASB issued ASC 260-10-45-61A, Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities (ASC 260-10-45-61A). ASC
260-10-45-61A applies to the calculation of earnings per share (EPS) described in previous
guidance, for share-based payment awards with rights to dividends or dividend equivalents. It
states that unvested share-based payment awards that contain non-forfeitable rights to dividends or
dividend equivalents (whether paid or unpaid) are participating securities and shall be included in
the computation of EPS pursuant to the two-class method. ASC 260-10-45-61A is effective for
financial statements issued for fiscal years beginning after December 15, 2008, and interim periods
within those fiscal years. Early adoption was prohibited. We adopted the requirements on January
1, 2009 and our adoption did not have a material impact on our financial position and results of
operations.
87
In April 2008, the FASB issued ASC 350-30-65-1, Determination of Useful Life of Intangible
Assets (ASC 350-30-65-1). ASC 350-30-65-1 amends the factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of a recognized
intangible asset under
previous guidance. The intent of ASC 350-30-65-1 is to improve the consistency between the
useful life of a recognized intangible asset and the period of expected cash flows used to measure
the fair value of the asset. We adopted the requirements of ASC 350-30-65-1 on January 1, 2009, and
our adoption did not have a material impact on our financial position and results of operations.
In March 2008, the FASB issued ASC 260-10-55-103 through 55-110, Application of the Two-Class
Method (ASC 260-10-55-103), which considers whether the incentive distributions of a master
limited partnership represent a participating security when considered in the calculation of
earnings per unit under the two-class method. ASC 260-10-55-103 considers whether the partnership
agreement contains any contractual limitations concerning distributions to the incentive
distribution rights that would impact the amount of earnings to allocate to the incentive
distribution rights for each reporting period. If distributions are contractually limited to the
incentive distribution rights share of currently designated available cash for distributions as
defined under the partnership agreement, undistributed earnings in excess of available cash should
not be allocated to the incentive distribution rights. Our adoption of ASC 260-10-55-103 on
January 1, 2009 impacted our presentation of net income (loss) per common limited partner unit as
we previously presented net income (loss) per common limited partner unit as though all earnings
were distributed each quarterly period (see Net Income (Loss) Per Common Unit). We adopted the
requirements of ASC 260-10-55-103 on January 1, 2009 and our adoption did not have a material
impact on our financial position and results of operations.
In March 2008, the FASB issued ASC 815-10-50-1, Disclosures about Derivative Instruments and
Hedging Activities (ASC 815-10-50-1), to require enhanced disclosure about how and why an entity
uses derivative instruments, how derivative instruments and related hedged items are accounted for
and how derivative instruments and related hedged items affect an entitys financial position,
financial performance and cash flows. We adopted the requirements of this section of ASC
815-10-50-1on January 1, 2009 and it did not have a material impact on our financial position or
results of operations (see Note 10).
In December 2007, the FASB issued ASC 810-10-65-1, Non-controlling Interests in Consolidated
Financial Statements (ASC 810-10-65-1). ASC 810-10-65-1 establishes accounting and reporting
standards for the non-controlling interest (minority interest) in a subsidiary and for the
deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an
ownership interest in the consolidated entity that should be reported as equity in the consolidated
financial statements. It also requires consolidated net income to be reported and disclosed on the
face of the consolidated statement of operations at amounts that include the amounts attributable
to both the parent and the non-controlling interest. Additionally, ASC 810-10-65-1 establishes a
single method of accounting for changes in a parents ownership interest in a subsidiary that does
not result in deconsolidation and that the parent recognize a gain or loss in net income when a
subsidiary is deconsolidated and adjust its remaining investment, if any, at fair value. We
adopted the requirements of ASC 810-10-65-1on January 1, 2009, and adjusted our presentation of our
financial position and results of operations. Prior period financial position and results of
operations have been adjusted retrospectively to conform to these provisions.
In December 2007, the FASB issued ASC 805, Business Combinations (ASC 805). ASC 805
retains the fundamental requirements that the acquisition method of accounting be used for all
business combinations and for an acquirer to be identified for each business combination. ASC 805
requires an acquirer to recognize the assets acquired, liabilities assumed, and any non-controlling
interest in the acquiree at the acquisition date, at their fair values as of that date, with
specified limited exceptions. Changes subsequent to that date are to be recognized in earnings,
not goodwill. Additionally, it requires costs incurred in connection with an acquisition be
expensed as incurred. Restructuring costs, if any, are to be recognized separately from the
acquisition. The acquirer in a business combination achieved in stages must also recognize the
identifiable assets and liabilities, as well as the non-controlling interests in the acquiree, at
the full amounts of their fair values. We adopted these requirements on January 1, 2009, and it did
not have a material impact on our financial position and results of operations.
88
Recently Issued Accounting Standards
In October 2009, the FASB issued Accounting Standards Update 2009-15, Accounting for
Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing
(Update 2009-15). Update 2009-15 includes amendments to Topic 470, Debt, and Topic 260,
Earnings per Share, to provide guidance on share-lending arrangements entered into on an entitys
own shares in contemplation of a convertible debt offering or other financing. These
requirements are effective for existing arrangements for fiscal years beginning on or after
December 15, 2009, and interim periods within those fiscal years for arrangements outstanding as of
the beginning of those years, with retrospective application required for such arrangements that
meet the criteria. These requirements are also effective for arrangements entered into on (not
outstanding) or after the beginning of the first reporting period that begins on or after June 15,
2009. We will apply these requirements upon our adoption on January 1, 2010 and we do not expect
it to have a material impact to our financial position or results of operations or related
disclosures.
In June 2009, the FASB issued ASC 810-10-25-20 through 25-59, Consolidation of Variable
Interest Entities (ASC 810-10-25-20), which changes how a reporting entity determines when an
entity that is insufficiently capitalized or is not controlled through voting (or similar rights)
should be consolidated. ASC 820-10-25-20 requires a reporting entity to provide additional
disclosures about its involvement with variable interest entities and any significant changes in
risk exposure due to that involvement. A reporting entity will be required to disclose how its
involvement with a variable interest entity affects the reporting entitys financial statements.
These requirements are effective at the start of a reporting entitys first fiscal year beginning
after November 15, 2009 (January 1, 2010 for us). We will apply these requirements upon our
adoption on January 1, 2010 and we do not expect it to have a material impact to our financial
position or results of operations or related disclosures.
MODERNIZATION OF OIL AND GAS REPORTING
In December 2008, the Securities and Exchange Commission (SEC) announced that it had
approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of
Regulation S-X and Items 201, 801, and 802 of Regulation S-K. These new disclosure requirements are
referred to as Modernization of Oil and Gas Reporting and include provisions that:
|
|
|
Introduce a new definition of oil and gas producing activities. This new
definition allows companies to include in their reserve base volumes from
unconventional resources. Such unconventional resources include bitumen extracted
from oil sands and oil and gas extracted from coal beds and shale formations. |
|
|
|
|
Report oil and gas reserves using an unweighted average price using the prior
12-month period, based on the closing prices on the first day of each month, rather
than year-end pricing. This should maximize the comparability of reserve estimates
among companies and mitigate the distortion of the estimates that arises when using
a single pricing date. |
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|
Permit companies to disclose their probable and possible reserves on a voluntary
basis. Current rules limit disclosure to only proved reserves. |
|
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|
|
Update and revise reserve definitions to reflect changes in the oil and gas
industry and new technologies. New updated definitions include by geographic area
and reasonable certainty. |
|
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|
Permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserves volumes. |
|
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|
|
Require additional disclosures regarding the qualifications of the chief
technical person who oversees its overall reserve estimation process. Additionally,
disclosures are required related to internal controls over reserve estimation, as
well as a report addressing the independence
and qualifications of a companys reserves preparer or auditor based on Society of
Petroleum Engineers criteria. |
89
We will begin complying with the disclosure requirements in our annual report on Form 10-K for
the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly
reports prior to the first annual report in which the revised disclosures are required. We are
currently in the process of evaluating the new requirements.
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. As our assets currently
consist principally of our ownership interests in our subsidiaries, the following information
principally encompasses their exposure to market risks unless otherwise noted. The term market
risk refers to the risk of loss arising from adverse changes in interest rates and oil and natural
gas prices. The disclosures are not meant to be precise indicators of expected future losses, but
rather indicators of reasonable possible losses. This forward-looking information provides
indicators of how we view and manage our ongoing market risk exposures. All of the market risk
sensitive instruments were entered into for purposes other than trading.
General
All of our assets and liabilities are denominated in U.S. dollars, and as a result, we do not
have exposure to currency exchange risks.
We are exposed to various market risks, principally fluctuating interest rates and changes in
commodity prices. These risks can impact our results of operations, cash flows and financial
position. We manage these risks through regular operating and financing activities and periodical
use of derivative financial instruments such as forward contracts and interest rate cap and swap
agreements. The following analysis presents the effect on our results of operations, cash flows and
financial position as if the hypothetical changes in market risk factors occurred on September 30,
2009. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not
consider other possible effects that could impact our and our subsidiaries business.
Current market conditions elevate our concern over counterparty risks and may adversely affect
the ability of these counterparties to fulfill their obligations to us, if any. The counterparties
related to our commodity and interest-rate derivative contracts are banking institutions, who also
participate in their revolving credit facilities. The creditworthiness of our counterparties is
constantly monitored, and we currently believe them to be financially viable. We are not aware of
any inability on the part of our counterparties to perform under their contracts and believe our
exposure to non-performance is remote.
Interest Rate Risk. At September 30, 2009, ATN had an outstanding balance of $270.0 million on
its revolving credit facility. At September 30, 2009, we had interest rate derivative contracts
having aggregate notional principal amounts of $150.0 million. Under the terms of this agreement,
we will pay weighted average interest rates of 3.11% plus the applicable margin as defined under
the terms of ATNs revolving credit facility, and will receive LIBOR, plus the applicable margin on
the notional principal amounts. These derivatives effectively convert $150.0 million of ATNs
floating rate debt under its revolving credit facility to fixed rate debt.
At September 30, 2009, AHD had a credit facility with $12.0 million outstanding. The weighted
average interest rate for these borrowings was 3.25% at September 30, 2009.
90
In May 2008, AHD entered into an interest rate derivative contract having an aggregate
notional principal amount of $25.0 million. Under the terms of agreement, AHD will pay an interest
rate of 3.01%, plus the applicable margin as defined under the terms of its credit facility, and
will receive LIBOR, plus the
applicable margin, on the notional principal amounts. The interest rate swap agreement is in effect
at September 30, 2009 and expires on May 28, 2010.
At September 30, 2009, APL had $315.0 million of outstanding borrowings under its senior
secured revolving credit facility and $433.5 million outstanding under its senior secured term
loan. Borrowings under APLs credit facility bear interest, at its option at either (i) adjusted
LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus
0.5% or the Wachovia Bank prime rate (each plus the applicable margin). On May 29, 2009, APL
entered into an amendment to its senior secured credit facility agreement, which, among other
changes, set a floor for the LIBOR interest rate of 2.0% per annum. At September 30, 2009, APL had
interest rate derivative contracts having aggregate notional principal amounts of $450.0 million.
Under the terms of these agreements, APL will pay weighted average interest rates of 3.02%, plus
the applicable margin as defined under the terms of its revolving credit facility, and will receive
LIBOR, plus the applicable margin, on the notional principal amounts. These derivatives are in
effect as of September 30, 2009 and expire during periods ranging from January 30, 2010 through
April 30, 2010. Beginning May 29, 2009, APL discontinued hedge accounting for its interest rate
derivatives which were qualified as hedges under prevailing accounting literature. As such,
subsequent changes in fair value of these derivatives will be recognized immediately with other
income (loss), net in our consolidated statement of operations.
Holding all other variables constant, including the effect of interest rate derivatives, a
hypothetical 100 basis-point or 1% change in interest rates would change our consolidated interest
expense by $5.8 million.
Commodity Price Risk. Our market risk exposure to commodities is due to the fluctuations in
the price of natural gas, NGLs, condensate and oil and the impact those price movements have on the
financial results of our subsidiaries. To limit our exposure to changing natural gas and oil
prices, we use financial derivative instruments for a portion of our future natural gas and oil
production. APL is exposed to commodity prices as a result of being paid for certain services in
the form of natural gas, NGLs and condensate rather than cash. APL enters into financial swap and
option instruments to hedge forecasted sales against the variability in expected future cash flows
attributable to changes in market prices. The swap instruments are contractual agreements between
counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate
are sold. Under these swap agreements, APL receives or pays a fixed price and receives or remits a
floating price based on certain indices for the relevant contract period. Option instruments are
contractual agreements that grant the right, but not obligation, to purchase or sell natural gas,
NGLs and condensate at a fixed price for the relevant period.
Holding all other variables constant, including the effect of commodity derivatives, a 10%
change in the average price of natural gas, NGLs, condensate and oil would result in a change to
our consolidated operating income from continuing operations, excluding income tax effects, for the
twelve-month period ending September 30, 2010 of approximately $32.1 million.
Realized pricing of our oil and natural gas production is primarily driven by the prevailing
worldwide prices for crude oil and spot market prices applicable to United States natural gas
production. Pricing for natural gas and oil production has been volatile and unpredictable for many
years. To limit our exposure to changing natural gas prices, we enter into natural gas and oil swap
and costless collar option contracts. At any point in time, such contracts may include regulated
NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with
qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may
be settled by the delivery of natural gas oil contracts and are based on a West Texas Intermediate,
or WTI, index.
91
We formally document all relationships between derivative instruments and the items being
hedged, including the risk management objective and strategy for undertaking the derivative
transactions. This includes matching the natural gas and oil futures and options contracts to the
forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis,
whether the derivatives are highly effective
in offsetting changes in the fair value of hedged items. Historically these contracts have
qualified and been designated as cash flow hedges, and are recorded at their fair values. Gains or
losses on future contracts are determined as the difference between the contract price and a
reference price, generally prices on NYMEX or WTI. Changes in fair value are recognized in
consolidated equity and recognized within the consolidated statements of operations in the month
the hedged commodity is sold. If it is determined that a derivative is not highly effective as a
hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between
changes in reference prices underlying a hedging instrument and actual commodity prices, we will
discontinue hedge accounting for the derivative and subsequent changes in fair value for the
derivative will be recognized immediately into earnings.
We recognized gains on settled contracts covering natural gas and oil production of $35.1
million and a loss of $27.6 million for the three months ended September 30, 2009 and 2008,
respectively and gains of $82.2 million and a loss of $26.0 million for the nine months ended
September 30, 2009 and 2008, respectively. As the underlying prices and terms in our
derivative contracts were consistent with the indices used to sell our natural gas, there were no
gains or losses recognized during the three and nine months ended September 30, 2009 and 2008 for
hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.
In May 2009, we received approximately $28.5 million in proceeds from the early settlement of
natural gas and oil derivative positions for production periods from 2011 through 2013. In
conjunction with the early termination of these derivatives, we entered into new derivative
positions at prevailing prices at the time of the transaction. The net proceeds from the early
termination of these derivatives were used to reduce indebtedness under our revolving credit
facility. The derivative gain recognized upon early termination of these discontinued derivative
positions will continue to be reported in accumulated other comprehensive income and will be
reclassified to our consolidated statements of operations during the periods which the physical
transactions would have affected earnings.
We have a $50.5 million net unrealized gain related to financial derivatives in accumulated
other comprehensive loss associated with commodity derivatives and interest rate swaps at September
30, 2009, compared to a net unrealized gain of $21.4 million at December 31, 2008. If the fair
values of the instruments remain at current market values, we will reclassify $32.8 million of
gains to our consolidated statements of operations over the next twelve month period as these
contracts expire, consisting of $37.1 million of gains to gas and oil production revenues, $2.2
million of losses to gathering, transmission and processing revenues and $2.1 million of losses to
interest expense. Aggregate gains of $17.7 million will be reclassified to our consolidated
statements of operations in later periods as these remaining contracts expire, consisting of $20.3
million of gains to gas and oil production revenues, $1.5 million of losses to gathering,
transmission and processing revenues and $1.1 million of losses to interest expense. Actual
amounts that will be reclassified will vary as a result of future price changes.
The fair value of the derivatives at September 30, 2009 is a net unrealized derivative asset
of $99.9 million, of which our portion is $64.8 million and $35.1 million of unrealized gains have
been reallocated to our investment partnerships.
92
As of September 30, 2009, we had the following interest rate and commodity hedges:
Interest Fixed Rate Swap
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract |
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Period Ended |
|
|
Fair Value |
|
Term |
|
Amount |
|
|
Option Type |
|
|
December 31, |
|
|
Liability |
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
January 2008 - January 2011 |
|
$ |
150,000,000 |
|
|
Pay 3.11% - Receive LIBOR |
|
|
2009 |
|
|
$ |
(1,009 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(3,495 |
) |
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
|
|
(194 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Liability |
|
|
$ |
(4,698 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset |
|
|
|
(mmbtu) (3) |
|
|
(per mmbtu) (3) |
|
|
(in thousands) (1) |
|
2009 |
|
|
10,340,000 |
|
|
$ |
8.242 |
|
|
$ |
36,116 |
|
2010 |
|
|
31,880,000 |
|
|
$ |
7.708 |
|
|
|
47,682 |
|
2011 |
|
|
20,720,000 |
|
|
$ |
7.040 |
|
|
|
3,403 |
|
2012 |
|
|
19,680,000 |
|
|
$ |
7.223 |
|
|
|
4,119 |
|
2013 |
|
|
13,260,000 |
|
|
$ |
7.082 |
|
|
|
235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
91,555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Option Type |
|
|
Volumes |
|
|
Floor and Cap |
|
|
Asset/(Liability) |
|
|
|
|
|
|
(mmbtu) (3) |
|
|
(per mmbtu) (3) |
|
|
(in thousands) (1) |
|
2009 |
|
Puts purchased |
|
|
60,000 |
|
|
$ |
11.000 |
|
|
$ |
370 |
|
2009 |
|
Calls sold |
|
|
60,000 |
|
|
$ |
15.350 |
|
|
|
|
|
2010 |
|
Puts purchased |
|
|
3,360,000 |
|
|
$ |
7.839 |
|
|
|
6,021 |
|
2010 |
|
Calls sold |
|
|
3,360,000 |
|
|
$ |
9.007 |
|
|
|
|
|
2011 |
|
Puts purchased |
|
|
9,540,000 |
|
|
$ |
6.523 |
|
|
|
808 |
|
2011 |
|
Calls sold |
|
|
9,540,000 |
|
|
$ |
7.666 |
|
|
|
|
|
2012 |
|
Puts purchased |
|
|
4,020,000 |
|
|
$ |
6.514 |
|
|
|
|
|
2012 |
|
Calls sold |
|
|
4,020,000 |
|
|
$ |
7.718 |
|
|
|
(249 |
) |
2013 |
|
Puts purchased |
|
|
5,340,000 |
|
|
$ |
6.516 |
|
|
|
|
|
2013 |
|
Calls sold |
|
|
5,340,000 |
|
|
$ |
7.811 |
|
|
|
(579 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6,371 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset/(Liability) |
|
|
|
(Bbl) (3) |
|
|
(per Bbl) (3) |
|
|
(in thousands) (2) |
|
2009 |
|
|
14,600 |
|
|
$ |
99.319 |
|
|
$ |
424 |
|
2010 |
|
|
48,900 |
|
|
$ |
97.400 |
|
|
|
1,134 |
|
2011 |
|
|
42,600 |
|
|
$ |
77.460 |
|
|
|
11 |
|
2012 |
|
|
33,500 |
|
|
$ |
76.855 |
|
|
|
(74 |
) |
2013 |
|
|
10,000 |
|
|
$ |
77.360 |
|
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
93
Crude Oil Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period Ending |
|
|
|
|
|
|
|
|
|
Average |
|
|
Fair Value |
|
December 31, |
|
Option Type |
|
|
Volumes |
|
|
Floor and Cap |
|
|
Asset/(Liability) |
|
|
|
|
|
|
(Bbl) (3) |
|
|
(per Bbl) (3) |
|
|
(in thousands) (2) |
|
2009 |
|
Puts purchased |
|
|
9,000 |
|
|
$ |
85.000 |
|
|
$ |
134 |
|
2009 |
|
Calls sold |
|
|
9,000 |
|
|
$ |
116.561 |
|
|
|
|
|
2010 |
|
Puts purchased |
|
|
31,000 |
|
|
$ |
85.000 |
|
|
|
468 |
|
2010 |
|
Calls sold |
|
|
31,000 |
|
|
$ |
112.918 |
|
|
|
|
|
2011 |
|
Puts purchased |
|
|
27,000 |
|
|
$ |
67.223 |
|
|
|
|
|
2011 |
|
Calls sold |
|
|
27,000 |
|
|
$ |
89.436 |
|
|
|
(27 |
) |
2012 |
|
Puts purchased |
|
|
21,500 |
|
|
$ |
65.506 |
|
|
|
|
|
2012 |
|
Calls sold |
|
|
21,500 |
|
|
$ |
91.448 |
|
|
|
(70 |
) |
2013 |
|
Puts purchased |
|
|
6,000 |
|
|
$ |
65.358 |
|
|
|
|
|
2013 |
|
Calls sold |
|
|
6,000 |
|
|
$ |
93.442 |
|
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ATN net asset |
|
|
$ |
95,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Fair value based on forward NYMEX natural gas prices, as applicable. |
|
(2) |
|
Fair value based on forward WTI crude oil prices, as applicable. |
|
(3) |
|
Mmbtu represents million British thermal units; Bbl represents barrels. |
Atlas Pipeline Partners and Atlas Pipeline Holdings. AHD and APL formally document all
relationships between derivative instruments and the items being hedged, including their risk
management objective and strategy for undertaking the derivative transactions. This includes
matching the derivative contracts to the forecasted transactions. AHD and APL assess, both at the
inception of the derivative and on an ongoing basis, whether the derivative is effective in
offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a
derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the
loss of adequate correlation between the derivative instrument and the underlying item being
hedged, AHD and APL will discontinue hedge accounting for the derivative and subsequent changes in
the derivative fair value, which is determined by AHD and APL through the utilization of market
data, will be recognized immediately within gain (loss) on mark-to-market derivatives in our
consolidated statements of operations. For AHDs and APLs derivatives qualifying as hedges, we
will recognize the effective portion of changes in fair value in stockholders equity as
accumulated other comprehensive income on our consolidated balance sheet, and reclassify the
portion relating to commodity derivatives to transmission, gathering and processing revenue and the
portion relating to interest rate derivatives to interest expense within our consolidated
statements of operations as the underlying transactions are settled. For AHDs and APLs
non-qualifying derivatives and for the ineffective portion of qualifying derivatives, we will
recognize changes in fair value within gain (loss) on mark-to-market derivatives in our
consolidated statements of operations as they occur.
The following table summarizes AHD and APLs derivative activity for the periods indicated
(amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Early Termination of Derivative Contracts |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net cash derivative
expense included
within gain (loss)
on mark-to-market
derivatives |
|
$ |
|
|
|
$ |
(70,258 |
) |
|
$ |
(5,000 |
) |
|
$ |
(186,068 |
) |
Net cash derivative
expense included
within
transmission,
gathering and
processing revenue |
|
|
|
|
|
|
(1,258 |
) |
|
|
|
|
|
|
(1,573 |
) |
Net non-cash
derivative income
(expense) included
within gain (loss)
on mark-to-market
derivatives |
|
|
15,488 |
|
|
|
6,488 |
|
|
|
34,708 |
|
|
|
(39,857 |
) |
Net non-cash
derivative expense
included within
transmission,
gathering and
processing revenue |
|
|
(19,976 |
) |
|
|
(19,514 |
) |
|
|
(54,043 |
) |
|
|
(19,514 |
) |
94
The following table summarizes AHDs and APLs derivative activity, including the early
termination of derivative contracts disclosed above, for the periods indicated (amounts in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Loss from cash settlement and
non-cash recognition of
qualifying hedge
instruments(1) |
|
$ |
(9,779 |
) |
|
$ |
(27,419 |
) |
|
$ |
(37,281 |
) |
|
$ |
(78,214 |
) |
Gain (loss) from change in
market value of non-
qualifying
derivatives(2) |
|
|
12,021 |
|
|
|
190,013 |
|
|
|
(30,460 |
) |
|
|
(17,919 |
) |
Gain (loss) from change in
market value of ineffective
portion of qualifying
derivatives(2) |
|
|
|
|
|
|
44,997 |
|
|
|
10,813 |
|
|
|
41,271 |
|
Gain (loss) from cash
settlement and non-cash
recognition of non-qualifying
derivatives(2) |
|
|
(10,165 |
) |
|
|
(84,207 |
) |
|
|
3,225 |
|
|
|
(280,696 |
) |
Loss from cash settlement of
interest rate
derivatives(3) |
|
|
(3,321 |
) |
|
|
(708 |
) |
|
|
(9,500 |
) |
|
|
(915 |
) |
Loss from change in market
value of non-qualifying
interest rate derivatives(2) |
|
|
(861 |
) |
|
|
|
|
|
|
(891 |
) |
|
|
|
|
Loss from reclassification of
loss from Other Comprehensive
Income to Other
Loss(2)(4) |
|
|
(60 |
) |
|
|
|
|
|
|
(256 |
) |
|
|
|
|
|
|
|
(1) |
|
Included within transmission, gathering and processing revenue on our consolidated
statements of operations. |
|
(2) |
|
Included within (gain) loss on mark-to-market derivatives, net on our consolidated statements
of operations. |
|
(3) |
|
Included within interest expense on our consolidated statements of operations. |
|
(4) |
|
Reclassification due to reduction of outstanding borrowings being hedged. |
The following table summarizes AHDs and APLs gross fair values of derivative
instruments for the period indicated (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
|
|
Asset Derivatives |
|
|
Liability Derivatives |
|
|
|
Balance Sheet |
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
|
Location |
|
|
Fair Value |
|
|
Location |
|
|
Fair Value |
|
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts |
|
N/A |
|
$ |
|
|
|
Current portion of derivative liability |
|
$ |
(6,352 |
) |
Commodity contracts |
|
Current portion of derivative asset |
|
|
4,514 |
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
Long-term derivative asset |
|
|
1,980 |
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
Current portion of derivative liability |
|
|
10,050 |
|
|
Current portion of derivative liability |
|
|
(45,162 |
) |
Commodity contracts |
|
Long-term derivative liability |
|
|
3,341 |
|
|
Long-term derivative liability |
|
|
(12,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,885 |
|
|
|
|
|
|
$ |
(64,111 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95
The following table summarizes the gross effect of AHDs and APLs derivative instruments
on our consolidated statements of operations for the period indicated (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
|
Three months ended September 30, 2009 |
|
|
|
Gain (Loss) |
|
|
Gain (Loss) Reclassified from |
|
|
Gain (Loss) Recognized in Income |
|
|
|
Recognized in |
|
|
Accumulated OCI into Income |
|
|
(Ineffective Portion and Amount |
|
|
|
Accumulated |
|
|
(Effective Portion) |
|
|
Excluded from Effectiveness Testing) |
|
|
|
OCI |
|
|
Amount |
|
|
Location |
|
|
Amount |
|
|
Location |
|
Interest rate contracts(1) |
|
$ |
30 |
|
|
$ |
(3,419 |
) |
|
Interest expense |
|
$ |
(951 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(1) |
|
|
|
|
|
|
(10,294 |
) |
|
Transmission, gathering and processing revenue |
|
|
(13,671 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(2) |
|
|
|
|
|
|
|
|
|
N/A |
|
|
|
16,036 |
|
|
Gain (loss) on mark-to-market derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
30 |
|
|
$ |
(13,713 |
) |
|
|
|
|
|
$ |
1,414 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Hedges previously designated as cash flow hedges |
|
(2) |
|
Dedesignated cash flow hedges and non-designated hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
|
Nine months ended September 30, 2009 |
|
|
|
Gain (Loss) |
|
|
Gain (Loss) Reclassified from |
|
|
Gain (Loss) Recognized in Income |
|
|
|
Recognized in |
|
|
Accumulated OCI into Income |
|
|
(Ineffective Portion and Amount |
|
|
|
Accumulated |
|
|
(Effective Portion) |
|
|
Excluded from Effectiveness Testing) |
|
|
|
OCI |
|
|
Amount |
|
|
Location |
|
|
Amount |
|
|
Location |
|
Interest rate contracts(1) |
|
$ |
(2,411 |
) |
|
$ |
(9,599 |
) |
|
Interest expense |
|
$ |
(1,147 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(1) |
|
|
|
|
|
|
(37,158 |
) |
|
Transmission, gathering and processing revenue |
|
|
(36,579 |
) |
|
Gain (loss) on mark-to-market derivatives |
Commodity contracts(2) |
|
|
|
|
|
|
|
|
|
N/A |
|
|
|
20,155 |
|
|
Gain (loss) on mark-to-market derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(2,411 |
) |
|
$ |
(46,757 |
) |
|
|
|
|
|
$ |
(17,571 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Hedges previously designated as cash flow hedges |
|
(2) |
|
Dedesignated cash flow hedges and non-designated hedges |
96
As of September 30, 2009, AHD had the following interest rate derivatives, including
derivatives that do not qualify for hedge accounting:
Interest Fixed-Rate Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Contract Period |
|
|
Fair Value |
|
Term |
|
Amount |
|
|
Type |
|
|
Ended December 31, |
|
|
Liability(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
May 2008 - May 2010 |
|
$ |
25,000,000 |
|
|
Pay 3.01% Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(174 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total AHD liability |
|
$ |
(445 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Fair value based on independent, third-party
statements, supported by observable levels at which transactions are executed in the
marketplace. |
As of September 30, 2009, APL had the following interest rate and commodity derivatives,
including derivatives that do not qualify for hedge accounting:
Interest Fixed-Rate Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Contract Period |
|
|
Fair Value |
|
Term |
|
Amount |
|
|
Type |
|
|
Ended December 31, |
|
|
Liability(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
January 2008 - January 2010 |
|
$ |
200,000,000 |
|
|
Pay 2.88% Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(1,335 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(426 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,761 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 - April 2010 |
|
$ |
250,000,000 |
|
|
Pay 3.14% Receive LIBOR |
|
|
|
2009 |
|
|
$ |
(1,832 |
) |
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
|
(2,314 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(4,146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Sales Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset(3) |
|
2009 |
|
|
120,000 |
|
|
$ |
8.000 |
|
|
$ |
390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
1,230,000 |
|
|
$ |
(0.558 |
) |
|
$ |
(386 |
) |
2010 |
|
|
2,220,000 |
|
|
$ |
(0.607 |
) |
|
|
(401 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(787 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Purchases Fixed Price Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
2,580,000 |
|
|
$ |
8.687 |
|
|
$ |
(10,162 |
) |
2010 |
|
|
4,380,000 |
|
|
$ |
8.635 |
|
|
|
(11,718 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(21,880 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
97
Natural Gas Basis Purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Asset(3) |
|
|
|
(mmbtu)(6) |
|
|
(per mmbtu)(6) |
|
|
(in thousands) |
|
2009 |
|
|
3,690,000 |
|
|
$ |
(0.659 |
) |
|
$ |
1,508 |
|
2010 |
|
|
6,600,000 |
|
|
$ |
(0.590 |
) |
|
|
1,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,701 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Fixed Price Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(2) |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
2009 |
|
|
5,544,000 |
|
|
$ |
0.754 |
|
|
$ |
(762 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Ethane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Liability(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
630,000 |
|
|
$ |
0.340 |
|
|
$ |
(57 |
) |
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Asset(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
15,246,000 |
|
|
$ |
0.820 |
|
|
$ |
579 |
|
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Isobutane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Liability(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
126,000 |
|
|
$ |
0.5890 |
|
|
$ |
(20 |
) |
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Normal Butane Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Asset(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
3,654,000 |
|
|
$ |
0.943 |
|
|
$ |
98 |
|
|
Puts purchased |
2010 |
|
|
3,654,000 |
|
|
$ |
1.038 |
|
|
$ |
544 |
|
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98
Natural Gasoline Put Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
|
|
|
|
|
|
|
|
Production Period |
|
NGL |
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Price(4) |
|
|
Asset(1) |
|
|
Option Type |
|
|
|
(gallons) |
|
|
(per gallon) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
3,906,000 |
|
|
$ |
1.341 |
|
|
$ |
549 |
|
|
Puts purchased |
2010 |
|
|
3,906,000 |
|
|
$ |
1.345 |
|
|
$ |
902 |
|
|
Puts purchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales Options (associated with NGL volume)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated |
|
|
Average |
|
|
|
|
|
|
|
Production Period |
|
Crude |
|
|
NGL |
|
|
Crude |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volume |
|
|
Volume |
|
|
Price (4) |
|
|
Asset/(Liability)(3) |
|
|
Option Type |
|
|
|
(barrels) |
|
|
(gallons) |
|
|
(per barrel) |
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
165,000 |
|
|
|
9,321,900 |
|
|
$ |
63.53 |
|
|
$ |
856 |
|
|
Puts purchased |
2009 |
|
|
527,700 |
|
|
|
29,874,978 |
|
|
$ |
84.80 |
|
|
|
(647 |
) |
|
Calls sold |
2010 |
|
|
486,000 |
|
|
|
27,356,700 |
|
|
$ |
61.24 |
|
|
|
4,111 |
|
|
Puts purchased |
2010 |
|
|
3,127,500 |
|
|
|
213,088,050 |
|
|
$ |
86.20 |
|
|
|
(20,462 |
) |
|
Calls sold |
2010 |
|
|
714,000 |
|
|
|
45,415,440 |
|
|
$ |
132.17 |
|
|
|
705 |
|
|
Calls purchased(5) |
2011 |
|
|
606,000 |
|
|
|
33,145,560 |
|
|
$ |
100.70 |
|
|
|
(4,517 |
) |
|
Calls sold |
2011 |
|
|
252,000 |
|
|
|
13,547,520 |
|
|
$ |
133.16 |
|
|
|
920 |
|
|
Calls purchased(5) |
2012 |
|
|
450,000 |
|
|
|
25,893,000 |
|
|
$ |
102.71 |
|
|
|
(4,038 |
) |
|
Calls sold |
2012 |
|
|
180,000 |
|
|
|
9,676,800 |
|
|
$ |
134.27 |
|
|
|
919 |
|
|
Calls purchased(5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(22,153 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
Ended December 31, |
|
Volumes |
|
|
Fixed Price |
|
|
Liability(3) |
|
|
|
(barrels) |
|
|
(per barrel) |
|
|
(in thousands) |
|
2009 |
|
|
6,000 |
|
|
$ |
62.700 |
|
|
$ |
(48 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Period |
|
|
|
|
|
Average |
|
|
Fair Value |
|
|
|
|
Ended December 31, |
|
Volumes |
|
|
Crude Price(4) |
|
|
Asset(Liability)(3) |
|
|
Option Type |
|
|
|
(barrels) |
|
|
(per barrel) |
|
|
(in thousands) |
|
|
|
|
2009 |
|
|
117,000 |
|
|
$ |
64.151 |
|
|
$ |
604 |
|
|
Puts purchased |
2009 |
|
|
76,500 |
|
|
$ |
84.956 |
|
|
|
(116 |
) |
|
Calls sold |
2010 |
|
|
411,000 |
|
|
$ |
64.732 |
|
|
|
4,450 |
|
|
Puts purchased |
2010 |
|
|
234,000 |
|
|
$ |
88.088 |
|
|
|
(1,475 |
) |
|
Calls sold |
2011 |
|
|
72,000 |
|
|
$ |
93.109 |
|
|
|
(746 |
) |
|
Calls sold |
2012 |
|
|
48,000 |
|
|
$ |
90.314 |
|
|
|
(648 |
) |
|
Calls sold |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net APL liability |
|
|
$ |
(43,782 |
) |
|
|
|
|
Total net AHD liability |
|
|
|
(445 |
) |
|
|
|
|
Total net Company asset |
|
|
|
95,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total consolidated net asset |
|
|
$ |
50,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Fair value based on independent, third-party statements, supported by
observable levels at which transactions are executed in the marketplace. |
|
(2) |
|
Fair value based upon management estimates, including forecasted forward NGL
prices. |
|
(3) |
|
Fair value based on forward NYMEX natural gas and light crude prices,
as applicable. |
99
|
|
|
(4) |
|
Average price of options based upon average strike price adjusted by average
premium paid or received. |
|
(5) |
|
Calls purchased for 2010 through 2012 represent offsetting positions for
calls sold. These offsetting positions were entered into by APL to limit the loss which
could be incurred if crude oil prices continued to rise. |
|
(6) |
|
Mmbtu represents million British Thermal Units. |
The fair value of derivatives is included in our consolidated balance sheets as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Current portion of derivative asset |
|
$ |
88,960 |
|
|
$ |
152,727 |
|
Long-term derivative asset |
|
|
42,405 |
|
|
|
69,451 |
|
Current portion of derivative liability |
|
|
(46,570 |
) |
|
|
(73,776 |
) |
Long-term derivative liability |
|
|
(33,847 |
) |
|
|
(59,103 |
) |
|
|
|
|
|
|
|
Total net asset |
|
$ |
50,948 |
|
|
$ |
89,299 |
|
|
|
|
|
|
|
|
At September 30, 2009 and December 31, 2008, we reflected a net hedging asset on our
consolidated balance sheets of $50.9 million and $89.3 million, respectively, as a result of our,
AHDs and APLs derivative contracts. Of the $50.4 million gains in accumulated other
comprehensive income at September 30, 2009, we will reclassify $32.9 million of gains to our
consolidated statements of operations over the next twelve month period as these contracts expire,
and $17.6 million of gains will be reclassified in later periods if the fair values of the
instruments remain at current market values. Actual amounts that will be reclassified will vary as
a result of future price changes.
ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information
required to be disclosed in our Securities Exchange Act of 1934 reports 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 our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating the disclosure controls and procedures, our management
recognized that any controls and procedures, no matter how well designed and operated, can provide
only reasonable assurance of achieving the desired control objectives, and our management
necessarily was required to apply its judgment in evaluating the cost-benefit relationship of
possible controls and procedures.
Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the
participation of our disclosure committee appointed by such officers, we have carried out an
evaluation of the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that, as of September 30, 2009, our disclosure controls and procedures
were effective at the reasonable assurance level.
There have been no changes in our internal control over financial reporting during our most
recent fiscal quarter that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
100
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Following the announcement of the merger agreement on April 27, 2009 between us and ATN, the
following actions were filed in Delaware Chancery Court purporting to challenge the merger:
|
|
|
Alonzo v. Atlas Energy Resources, LLC, et al., C.A. No. 4553-VCN (Del. Ch. filed 4/30/09); |
|
|
|
|
Operating Engineers Constructions Industry and Miscellaneous Pension
Fund v. Atlas America, Inc., et al., C.A. No. 4589-VCN (Del. Ch. filed
5/13/09); |
|
|
|
|
Vanderpool v. Atlas Energy Resources, LLC, et al., C.A. No. 4604-VCN (Del. Ch. filed 5/15/09); |
|
|
|
|
Farrell v. Cohen, et al., C.A. No. 4607-VCN (Del. Ch. filed 5/19/09); and |
|
|
|
|
Montgomery County Employees Retirement Fund v. Atlas Energy
Resources, L.L.C., et al., C.A. No. 4613-VCN (Del. Ch. filed 5/21/09). |
On June 15, 2009, Vice Chancellor Noble issued an order consolidating all five lawsuits,
renaming the action In re Atlas Energy Resources, LLC Unitholder Litigation, C.A. No. 4589-VCN, and
appointing as co-lead plaintiffs Operating Engineers Construction Industry and Miscellaneous
Pension Fund and Montgomery County Employees Retirement Fund. Plaintiffs filed a Verified
Consolidated Class Action Complaint on July 1, 2009, which has superseded all prior complaints. On
July 27, 2009, the Chancery Court granted the parties scheduling stipulation, setting a
preliminary injunction hearing for September 4, 2009. The complaint advances claims of breach of
fiduciary duty in connection with the Merger agreement, including allegations of inadequate
disclosures in connection with the unitholder vote on the Merger, and seeks monetary damages or
injunctive relief, or both. On August 7, 2009, Plaintiffs advised the Court by letter that they
are not pursuing their motion for preliminary injunction and requested that the preliminary
injunction hearing date be removed from the Courts calendar. Around that time, plaintiffs advised
counsel for the defendants that they intended to continue to pursue the case after the merger as a
claim for money damages. The Chancery Court approved the briefing schedule in mid-September and
defendants filed a brief in support of their motion to dismiss on October 16, 2009. Predicting the
outcome of this lawsuit is difficult. An adverse judgment for monetary damages could have a
material adverse effect on the operations of the combined company. Based on the facts known to
date, the defendants believe that the claims asserted against them in this lawsuit are without
merit, and intend to defend themselves vigorously against the claims.
In June 2008, our wholly-owned subsidiary, Atlas America, LLC, was named as a co-defendant in
the matter captioned CNX Gas Company, LLC (CNX) v. Miller Petroleum, Inc. (Miller), et
al. (Chancery Court, Campbell County, Tennessee). In its complaint, CNX alleges that Miller
breached a contract to assign to CNX certain leasehold rights (Leases) representing approximately
30,000 acres in Campbell County, Tennessee and that Atlas America, LLC and another defendant, Wind
City Oil & Gas, LLC, interfered with the closing of this assignment on June 6, 2008. ATN purchased
the Leases from Miller for approximately $19.1 million. On December 15, 2008, the Chancery Court
dismissed the matter in its entirety, holding that there had been no breach of the contract by
Miller and, therefore, that Atlas America, LLC could not have tortuously interfered with the
contract. The Chancery Court dismissed all claims against Atlas America, LLC; however, CNX has
appealed this decision.
We, Atlas Pipeline Holdings, and Atlas Pipeline and their subsidiaries are party to various
routine legal proceedings arising in the ordinary course of our collective business. Management
believes that none of these actions, individually or in the aggregate, will have a material adverse
effect on our financial condition or results of operations.
101
ITEM 1A. RISK FACTORS
Our business operations and financial position are subject to various risks. These risks are
described elsewhere in this report and in our most recent Form 10-K for the year ended December 31,
2008, and our Forms 10-Q for the quarters ended March 31, 2009 and June 30, 2009. The risk factors
identified therein have not changed in any material respect, except for the additional risk factors
added below.
The combined company resulting from the merger may fail to realize the anticipated cost savings,
growth opportunities and synergies and other benefits anticipated from the merger, which could
adversely affect the value of our common stock.
The success of the merger will depend, in part, on our ability to realize the anticipated
synergies and growth opportunities from combining the businesses, as well as the projected
stand-alone cost savings and revenue growth trends identified by each company. In addition, on a
combined basis, we expect to benefit from operational synergies resulting from the consolidation of
capabilities and elimination of redundancies as well as greater efficiencies from increased scale.
Management also intends to focus on revenue synergies for the combined entity. However, management
must successfully combine our businesses in a manner that permits these cost savings and synergies
to be realized. In addition, it must achieve the anticipated savings
without adversely affecting current revenues and our investments in future growth. If it is
not able to successfully achieve these objectives, the anticipated cost savings, revenue growth and
synergies may not be realized fully or at all, or may take longer to realize than expected.
Lawsuits have been filed against ATN, certain officers and members of its board of directors and us
challenging the merger, and any adverse judgment for monetary damages could have a material adverse
effect on the operations of the combined company.
We, ATN, and certain officers and directors of both companies are named as defendants in a
consolidated purported class action lawsuit brought by our unitholders in Delaware Chancery Court
generally alleging claims of breach of fiduciary duty in connection with the Merger. The complaint
alleges inadequate disclosures in connection with the ATNs unitholder vote on the Merger.
Plaintiffs filed a Verified Consolidated Class Action Complaint on July 1, 2009. The lawsuit
originally sought monetary damages or injunctive relief, or both. However, on August 7, 2009,
plaintiffs advised the Chancery Court by letter that they were not pursuing their motion for a
preliminary injunction, and requested that the preliminary injunction hearing date be removed from
the Courts calendar. Around that time, plaintiffs advised counsel for the defendants that
plaintiffs intended to continue to pursue the action for monetary damages after the Merger was
completed. The Chancery Court approved the briefing schedule in mid-September and defendants filed
a brief in support of their motion to dismiss on October 16, 2009. Predicting the outcome of this
lawsuit is difficult. An adverse judgment for monetary damages could have a material adverse
effect on the operations of the combined company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the 2009 Annual Meeting of Stockholders, which was held on July 13,
2009, the stockholders elected Mark C. Biderman and Gayle P.W. Jackson to serve
until the 2012 Annual Meeting. The ballot tabulation for the election of
directors was as follows:
|
|
|
|
|
|
|
|
|
|
|
Votes In |
|
|
Votes Against |
|
Nominees |
|
Favor |
|
|
or Withheld |
|
Mark C. Biderman |
|
|
36,690,458 |
|
|
|
149,980 |
|
Gayle P.W. Jackson |
|
|
36,979,160 |
|
|
|
150,278 |
|
The stockholders also voted upon a proposal to amend the Companys amended
and restated certificate of incorporation to increase the number of authorized
shares of common stock by 65 million to 114 million. The ballot tabulation for
the approval of the amendment was as follows:
|
|
|
|
|
Votes in Favor |
|
Votes Against |
|
Votes in Abstention/Broker Non-Votes |
30,376,096
|
|
6,730,237
|
|
23,101 |
102
At the Special Meeting of Stockholders, which was held on September 25, 2009, stockholders voted
upon a proposal to approve the issuance of the Companys common stock in connection with the merger
contemplated by the Agreement and Plan of Merger, dated as of April 27, 2009, among ATN, the
Company, Atlas Energy Management, Inc. and ATLS Merger Sub, LLC. The ballot tabulation for the
approval of the proposal was as follows:
|
|
|
|
|
Votes in Favor |
|
Votes Against |
|
Votes in Abstention/Broker Non-Votes |
33,443,782
|
|
38,050
|
|
4,466 |
At the Special Meeting, the stockholders also voted upon a proposal to approve the Atlas America
2009 Stock Incentive Plan. The ballot tabulation for the approval of the proposal was as follows:
|
|
|
|
|
Votes in Favor |
|
Votes Against |
|
Votes in Abstention/Broker Non-Votes |
25,089,398
|
|
8,375,507
|
|
21,394 |
ITEM 6. EXHIBITS
|
|
|
|
|
Exhibit No. |
|
Description |
|
|
|
|
|
|
2.1 |
|
|
Agreement and Plan of Merger, dated as of April 27, 2009, by
and among Atlas Energy Resources, LLC, Atlas America, Inc.,
Atlas Energy Management, Inc. and Merger Sub, as defined
therein(11) |
|
|
|
|
|
|
3.1 |
|
|
Amended and Restated Certificate of Incorporation(15) |
|
|
|
|
|
|
3.2 |
|
|
Amended and Restated Bylaws(15) |
|
|
|
|
|
|
4.1 |
|
|
Form of stock certificate(2) |
|
|
|
|
|
|
10.1 |
|
|
Indenture dated as of January 23, 2008 among Atlas Energy
Operating Company, LLC, Atlas Energy Finance Corp., as Issuers,
the subsidiaries named therein, as Guarantors, and U.S. Bank
National Association, as Trustee(17) |
|
|
|
|
|
|
10.2 |
|
|
Form of 10.75% Senior Note due 2018 (included as an exhibit to
the Indenture filed as Exhibit 4.2 hereto) |
|
|
|
|
|
|
10.3 |
|
|
Senior Indenture dated July 16, 2009 among Atlas Energy
Operating Company, LLC, Atlas Energy Finance Corp., as Issuers,
the subsidiaries named therein, as Guarantors, and U.S. Bank
National Association, as Trustee(18) |
|
|
|
|
|
|
10.4 |
|
|
First Supplemental Indenture date July 16, 2009(18) |
|
|
|
|
|
|
10.5 |
|
|
Form of Note 12.125% Senior Notes due 2017 (contained in Annex
A to the First Supplemental Indenture filed as Exhibit 4.5
hereto) |
|
|
|
|
|
|
10.6 |
|
|
Tax Matters Agreement between Atlas America, Inc. and Resource America, Inc. dated
May 14, 2004(5) |
|
|
|
|
|
|
10.7 |
|
|
Transition Services Agreement between Atlas America, Inc. and Resource America, Inc.
dated May 14, 2004(5) |
|
|
|
|
|
|
10.8 |
(a) |
|
Employment Agreement for Edward E. Cohen dated May 14, 2004(5) |
103
|
|
|
|
|
Exhibit No. |
|
Description |
|
|
|
|
|
|
10.8 |
(b) |
|
Amendment to Employment Agreement dated as of December 31, 2008(12) |
|
|
|
|
|
|
10.9 |
(a) |
|
Agreement for Services among Atlas America, Inc. and Richard Weber, dated April 5,
2006(6) |
|
|
|
|
|
|
10.9 |
(b) |
|
Amendment No. 1 to Agreement for Services dated as of April 26, 2007(7) |
|
|
|
|
|
|
10.9 |
(c) |
|
Amendment No. 2 to Agreement for Services dated as of December 18, 2008(12) |
|
|
|
|
|
|
10.10 |
|
|
Management Agreement, dated as of December 18, 2006, among Atlas Energy Resources, LLC,
Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc.(4) |
|
|
|
|
|
|
10.11 |
|
|
Stock Incentive Plan(12) |
|
|
|
|
|
|
10.12 |
|
|
2009 Stock Incentive Plan(15) |
|
|
|
|
|
|
10.13 |
|
|
Assumed Long-Term Incentive Plan(24) |
|
|
|
|
|
|
10.14 |
|
|
Atlas America Employee Stock Ownership Plan(8) |
|
|
|
|
|
|
10.15 |
|
|
Atlas America, Inc. Investment Savings Plan(8) |
|
|
|
|
|
|
10.16 |
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Form of Stock Award Agreement(9) |
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10.17 |
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Amended and Restated Annual Incentive Plan for Senior Executives(10) |
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10.18 |
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Employment Agreement between Atlas America, Inc. and Jonathan Z. Cohen dated as of
January 30, 2009(12) |
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10.19 |
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Securities Purchase Agreement dated April 7, 2009, by and between Atlas Pipeline
Mid-Continent, LLC and Spectra Energy Partners OLP, LP(16) |
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10.19 |
(a) |
|
Revolving Credit Agreement dated as of July 26, 2006 by and among Atlas Pipeline
Holdings, L.P., Atlas Pipeline Partners GP, LLC, Wachovia Bank, National Association
and the lenders thereto(16) |
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10.19 |
(b) |
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First Amendment to Revolving Credit Agreement dated as of June 1, 2009(13) |
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10.20 |
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Promissory Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.(13) |
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10.21 |
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Guaranty Note dated as of June 1, 2009 by Atlas Pipeline Holdings, L.P.(13) |
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10.22 |
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Guaranty, Subordination and Cash Collateral Agreement dated as of June 1, 2009 in favor
of Wachovia Bank, National Association(13) |
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10.23 |
(a) |
|
Revolving Credit Agreement, dated as of June 29, 2007, among Atlas Energy Operating
Company, LLC its subsidiaries, J.P. Morgan Chase Bank, N.A., as Administrative Agent
and the other lenders signatory thereto(19) |
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10.23 |
(b) |
|
First Amendment to Credit Agreement, dated as of October 25, 2007(20) |
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10.23 |
(c) |
|
Second Amendment to Credit Agreement, dated as of April 9, 2009(21) |
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10.23 |
(d) |
|
Third Amendment to Credit Agreement, dated as of July 10, 2009(22) |
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10.24 |
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|
ATN Option Agreement dated as of June 1, 2009, by and among APL Laurel Mountain, LLC,
Atlas Pipeline Operating Partnership, L.P. and Atlas Energy Resources,
LLC(14) |
104
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Exhibit No. |
|
Description |
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10.25 |
|
|
Amended and Restated Limited Liability Company Agreement of Laurel Mountain Midstream,
LLC dated as of June 1, 2009(14) |
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10.26 |
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Employment Agreement for Matthew A. Jones dated July 1, 2009(16) |
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10.27 |
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|
Gas Gathering Agreement for Natural Gas on the Legacy Appalachian System dated as of
June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas
Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource
Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline
Operating Partnership, L.P. (25) Specific terms in this exhibit have been
redacted, as marked three asterisks (***), because confidential treatment for those
terms has been requested. The redacted material has been separately filed with the
Securities and Exchange Commission. |
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31.2 |
|
|
Gas Gathering Agreement for Natural Gas on the Expansion Appalachian System dated as of
June 1, 2009 between Laurel Mountain Midstream, LLC and Atlas America, LLC, Atlas
Energy Resources, LLC, Atlas Energy Operating Company, LLC, Atlas Noble LLC, Resource
Energy, LLC, Viking Resources, LLC, Atlas Pipeline Partners, L.P. and Atlas Pipeline
Operating Partnership, L.P. (25) Specific terms in this exhibit have been
redacted, as marked three asterisks (***), because confidential treatment for those
terms has been requested. The redacted material has been separately filed with the
Securities and Exchange Commission. |
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31.1 |
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Rule 13(a)-14(a)/15d-14(a) Certification |
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31.2 |
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Rule 13(a)-14(a)/15d-14(a) Certification |
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32.1 |
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Section 1350 Certification |
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32.2 |
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Section 1350 Certification |
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(1) |
|
Previously filed as an exhibit to our Form 8-K filed on June 14, 2005 |
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(2) |
|
Previously filed as an exhibit to our registration statement on Form S-1 (registration no.
333-112653) |
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(3) |
|
[Intentionally Omitted] |
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(4) |
|
Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2006 |
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(5) |
|
Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2004 |
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(6) |
|
Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2006 |
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(7) |
|
Previously filed as an exhibit to our Form 8-K filed on May 1, 2007 |
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(8) |
|
Previously filed as an exhibit to our Form 10-K for the year ended September 30, 2005 |
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(9) |
|
Previously filed as an exhibit to our Form 10-Q for the quarter ended December 31, 2005 |
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(10) |
|
Previously filed as an exhibit to our definitive proxy statement filed May 8, 2008 |
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(11) |
|
Previously filed as an exhibit to our Form 8-K filed on April 27, 2009 |
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(12) |
|
Previously filed as an exhibit to our Form 10-K for the year ended December 31, 2008 |
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(13) |
|
Previously filed as an exhibit to our Form 8-K filed on June 2, 2009 |
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(14) |
|
Previously filed as an exhibit to our Form 8-K filed on June 5, 2009 |
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(15) |
|
Previously filed as an exhibit to our Form 8-K filed on September 30, 2009 |
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(16) |
|
Previously filed as an exhibit to our Form 10-Q for the quarter ended June 30, 2009 |
|
(17) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on January 24, 2008 |
105
|
|
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(18) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on July 17, 2009 |
|
(19) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on June 29, 2007 |
|
(20) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on October 26, 2007 |
|
(21) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on April 17, 2009 |
|
(22) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on July 24, 2009 |
|
(23) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 8-K filed on December 22, 2006 |
|
(24) |
|
Previously filed as an exhibit to our Form S-8 filed on September 30, 2009 |
|
(25) |
|
Previously filed as an exhibit to Atlas Energy Resources, LLCs Form 10-Q for the quarter
ended June 30, 2009 |
106
SIGNATURES
Pursuant to the requirements 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.
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|
ATLAS ENERGY, INC.
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|
Date: November 9, 2009 |
By: |
/s/ EDWARD E. COHEN
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|
|
Edward E. Cohen |
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|
|
Chairman of the Board and Chief Executive Officer |
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|
|
Date: November 9, 2009 |
By: |
/s/ MATTHEW A. JONES
|
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|
|
Matthew A. Jones |
|
|
|
Chief Financial Officer |
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Date: November 9, 2009 |
By: |
/s/ SEAN P. MCGRATH
|
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|
|
Sean P. McGrath |
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|
|
Chief Accounting Officer |
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107