UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2007
OR
o | 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: 1-33193
ATLAS ENERGY RESOURCES, LLC
(Exact name of registrant as specified in its charter)
Delaware | 75-3218520 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Westpointe Corporate Center | |
1550 Coraopolis Heights Road, 2nd FL | |
Moon Township, PA | 15108 |
(Address of principal executive offices) | (Zip code) |
Registrant's telephone number, including area code: (412) 262-2830
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer o Non-accelerated filer x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x
ATLAS ENERGY RESOURCES, LLC
INDEX TO QUARTERLY REPORT ON FORM 10-Q
Page | ||
PART I | FINANCIAL INFORMATION | |
Item 1. | Financial Statements | |
Consolidated Balance Sheets – September 30, 2007 and December 31, 2006 | 3 | |
Combined and Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2007 and 2006 | 4 | |
Consolidated Statement of Changes in Members’ Equity for the Nine Months Ended September 30, 2007 | 5 | |
Combined and Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006 | 6 | |
Notes to Combined and Consolidated Financial Statements | 7 | |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 22 |
Item 3. | Quantitative and Qualitative Disclosures about Market Risk | 34 |
Item 4. | Controls and Procedures | 36 |
PART II | OTHER INFORMATION | |
Item 6. | Exhibits | 37 |
SIGNATURES | 38 |
PART I FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
ATLAS ENERGY RESOURCES, LLC
CONSOLIDATED BALANCE SHEETS
(in thousands)
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
(Unaudited) | (Audited) | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 8,332 | $ | 8,833 | |||
Accounts receivable | 54,775 | 31,280 | |||||
Current portion of hedge asset | 40,384 | 27,618 | |||||
Prepaid expenses and other | 5,825 | 3,251 | |||||
Total current assets | 109,316 | 70,982 | |||||
Property and equipment, net | 1,642,811 | 277,814 | |||||
Other assets, net | 16,494 | 2,447 | |||||
Long-term hedge asset | 23,854 | 23,843 | |||||
Intangible assets, net | 4,598 | 5,211 | |||||
Goodwill | 35,166 | 35,166 | |||||
$ | 1,832,239 | $ | 415,463 | ||||
LIABILITIES AND MEMBERS’ EQUITY | |||||||
Current liabilities: | |||||||
Current portion of long-term debt | $ | 42 | $ | 38 | |||
Accounts payable | 53,476 | 37,931 | |||||
Liabilities associated with drilling contracts | 63,090 | 89,526 | |||||
Advances from affiliate | 14,702 | 12,502 | |||||
Current portion of hedge liability | 2,457 | 172 | |||||
Accrued liabilities | 23,538 | 18,773 | |||||
Total current liabilities | 157,305 | 158,942 | |||||
Long-term debt | 739,040 | 30 | |||||
Partnership hedge payable | 4,852 | 13,248 | |||||
Long-term hedge liability | 11,369 | 3,835 | |||||
Asset retirement obligations | 43,958 | 26,726 | |||||
Commitments and contingencies (Note 12) | |||||||
Members’ equity: | |||||||
Class A unit holders | 5,784 | 3,825 | |||||
Class B common unit holders | 419,980 | 187,769 | |||||
Class D unit holders | 425,032 | — | |||||
Accumulated other comprehensive income | 24,919 | 21,088 | |||||
Total members’ equity | 875,715 | 212,682 | |||||
$ | 1,832,239 | $ | 415,463 |
See accompanying notes to combined and consolidated financial statements
3
ATLAS ENERGY RESOURCES, LLC
COMBINED AND CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per unit data)
(Unaudited)
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
REVENUES | |||||||||||||
Well construction and completion | $ | 103,324 | $ | 50,641 | $ | 240,841 | $ | 135,329 | |||||
Gas and oil production | 63,265 | 21,888 | 109,840 | 66,696 | |||||||||
Administration and oversight | 5,364 | 2,990 | 13,347 | 8,487 | |||||||||
Well services | 4,845 | 3,346 | 12,721 | 9,498 | |||||||||
Gathering | 3,471 | 2,328 | 10,509 | 6,902 | |||||||||
Gain on mark-to-market derivatives | — | — | 26,257 | — | |||||||||
Total Revenues | 180,269 | 81,193 | 413,515 | 226,912 | |||||||||
COSTS AND EXPENSES | |||||||||||||
Well construction and completion | 89,847 | 44,037 | 209,427 | 117,677 | |||||||||
Gas and oil production | 11,960 | 3,709 | 20,307 | 10,550 | |||||||||
Well services | 2,515 | 1,752 | 6,705 | 5,540 | |||||||||
Gathering fees-Atlas Pipeline | 3,336 | 6,995 | 10,374 | 22,878 | |||||||||
General and administrative | 9,062 | 7,715 | 27,319 | 18,384 | |||||||||
Depreciation, depletion and amortization | 19,013 | 6,124 | 31,688 | 16,311 | |||||||||
Total operating expenses | 135,733 | 70,332 | 305,820 | 191,340 | |||||||||
OPERATING INCOME | 44,536 | 10,861 | 107,695 | 35,572 | |||||||||
OTHER INCOME (EXPENSE): | |||||||||||||
Interest expense | (13,032 | ) | (8 | ) | (14,972 | ) | (50 | ) | |||||
Other – net | 108 | 613 | 495 | 1,012 | |||||||||
Total other income (expense) | (12,924 | ) | 605 | (14,477 | ) | 962 | |||||||
Net income | $ | 31,612 | $ | 11,466 | $ | 93,218 | $ | 36,534 | |||||
Allocation of net income attributable to members’ interest/owners: | |||||||||||||
Portion applicable to owner’s interest (period prior to the initial public offering on December 18, 2006) | $ | — | $ | 11,466 | $ | — | $ | 36,534 | |||||
Portion applicable to members’ interests (period subsequent to the initial public offering on December 18, 2006) | 31,612 | — | 93,218 | — | |||||||||
$ | 31,612 | $ | 11,466 | $ | 93,218 | $ | 36,534 | ||||||
Allocation of net income attributable to members’ interests: | |||||||||||||
Class A units | $ | 1,416 | $ | 2,648 | |||||||||
Class B common units | 21,888 | 81,859 | |||||||||||
Class D units | 8,308 | 8,711 | |||||||||||
Net income attributable to members’ interests | $ | 31,612 | $ | 93,218 | |||||||||
Net income per Class B common and Class D units: | |||||||||||||
Basic | $ | 0.50 | $ | 2.02 | |||||||||
Diluted | $ | 0.49 | $ | 1.99 | |||||||||
Weighted Average Class B common and Class D unit: | |||||||||||||
Basic | 60,710 | 44,933 | |||||||||||
Diluted | 61,502 | 45,480 |
See accompanying notes to combined and consolidated financial statements
4
ATLAS ENERGY RESOURCES, LLC
CONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY
NINE MONTHS ENDED SEPTEMBER 30, 2007
(in thousands, except unit data)
(Unaudited)
Accumulated | |||||||||||||||||||||||||
Other | Total | ||||||||||||||||||||||||
Class A Units | Class B Common Units | Class D Units | Comprehensive | Members’ | |||||||||||||||||||||
Units | Amount | Units | Amount | Units | Amount | Income | Equity | ||||||||||||||||||
Balance, January 1, 2007 | 748,456 | $ | 3,825 | 36,626,746 | $ | 187,769 | — | $ | — | $ | 21,088 | $ | 212,682 | ||||||||||||
Units issued | 490,530 | 7,380,800 | 181,179 | 16,702,828 | 416,321 | 597,500 | |||||||||||||||||||
Distribution to members | (689 | ) | (33,737 | ) | (34,426 | ) | |||||||||||||||||||
Distribution paid on unissued units under incentive plan | (472 | ) | (472 | ) | |||||||||||||||||||||
Stock-based compensation | 3,382 | 3,382 | |||||||||||||||||||||||
Net income | 2,648 | 81,859 | 8,711 | 93,218 | |||||||||||||||||||||
Other comprehensive income | 3,831 | 3,831 | |||||||||||||||||||||||
Balance, September 30, 2007 | 1,238,986 | $ | 5,784 | 44,007,546 | $ | 419,980 | 16,702,828 | $ | 425,032 | $ | 24,919 | $ | 875,715 |
See accompanying notes to combined and consolidated financial statements
5
ATLAS ENERGY RESOURCES, LLC
COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
Nine Months Ended | |||||||
September 30, | |||||||
2007 | 2006 | ||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||
Net income | $ | 93,218 | $ | 36,534 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Amortization of deferred finance costs | 858 | — | |||||
Depreciation, depletion and amortization | 31,688 | 16,311 | |||||
Non-cash compensation on long-term incentive plans | 3,382 | 1,251 | |||||
Gain (loss) on asset dispositions | 119 | (35 | ) | ||||
Advances from affiliate | 2,200 | 32,074 | |||||
Non-cash (gain) on derivatives | (19,754 | ) | — | ||||
Changes in operating assets and liabilities (net of acquisition): | |||||||
Decrease (increase) in accounts receivable and prepaid expenses | 9,237 | (792 | ) | ||||
Decrease in accounts payable and accrued expenses | (3,916 | ) | (4,490 | ) | |||
(Decrease) increase in liabilities associated with drilling contracts | (23,675 | ) | 6,369 | ||||
Change in other operating assets and liabilities | 7,165 | 2,457 | |||||
Net cash provided by operating activities | 100,522 | 89,679 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||
Net cash paid for acquisition | (1,267,977 | ) | — | ||||
Capital expenditures | (125,428 | ) | (54,076 | ) | |||
Proceeds from sale of assets | 1,071 | 43 | |||||
(Increase) decrease in other assets | (104 | ) | 107 | ||||
Net cash used in investing activities | (1,392,438 | ) | (53,926 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||
Borrowings | 882,936 | — | |||||
Principal payments on borrowings | (143,922 | ) | (65 | ) | |||
Net proceeds from Class B common and Class D units issued | 597,500 | — | |||||
Distribution to unit holders | (34,898 | ) | — | ||||
(Increase) decrease in deferred financing costs and other | (10,201 | ) | — | ||||
Net cash provided (used in) by financing activities | 1,291,415 | (65 | ) | ||||
(Decrease) increase in cash and cash equivalents | (501 | ) | 35,688 | ||||
Cash and cash equivalents at beginning of period | 8,833 | 20,918 | |||||
Cash and cash equivalents at end of period | $ | 8,332 | $ | 56,606 |
See accompanying notes to combined and consolidated financial statements
6
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2007
(Unaudited)
NOTE 1 – BASIS OF PRESENTATION
Business Description
Atlas Energy Resources, LLC (the “Company”) is an independent developer and producer of natural gas and oil, with operations in northern Michigan’s Antrim Shale and the Appalachian Basin. The Company is also the leading sponsor of direct investment natural gas and oil partnerships in the United States. The Company’s northern Michigan operations are newly acquired (See Note 3). In northern Michigan, the Company drills wells for its own account. In the Appalachian Basin, it sponsors and manages tax-advantaged investment partnerships (the “Partnerships”), in which it coinvests, to finance the exploitation and development of its acreage.
The Company was formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (“AAI”) (NASDAQ: ATLS). In December 2006, the Company completed an initial public offering of 7,273,750 Class B common units, representing a 19.4% interest, at a price of $21.00 per common unit. The net proceeds of the offering of $139.9 million, after deducting underwriting discounts and costs, were distributed to the Company’s parent, AAI, in the form of a non-taxable dividend and to repay debt. Atlas Energy Management, Inc., a wholly-owned subsidiary of AAI, is the managing member of the Company and owns 1,238,986 Class A units, or a 2% interest, through which it manages and effectively controls the Company. After the private placement of Class B common and Class D units on June 29, 2007, AAI also owns 29,352,996 units or 48.4% of the Class B common and Class D units (See Note 15).
Principles of Combination and Consolidation
The combined and consolidated financial statements of the Company before the date of its initial public offering have been prepared from the separate records maintained by AAI and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Transactions between the Company and other AAI entities have been identified in the combined and consolidated financial statements as transactions between affiliates (see Note 8). In accordance with established practice in the oil and gas industry, the Company includes its pro rata share of assets, liabilities, revenues and costs and expenses of the Partnerships in which it has an interest. All significant intercompany balances and transactions within the Company have been eliminated.
The accompanying combined and consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2006 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 management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim combined and consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. The results of operations for the three month and nine month period ended September 30, 2007 may not necessarily be indicative of the results of operations for the full year ending December 31, 2007.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Reference is hereby made to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, which contains a summary of significant accounting policies followed by the Company in the preparation of its combined and consolidated financial statements. These policies were also followed in preparing the quarterly report included herein.
Use of Estimates
Preparation of the combined and consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates.
7
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
September 30, 2007
(Unaudited)
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)
Receivables
In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its customers. At September 30, 2007 and December 31, 2006, the Company’s credit evaluation indicated that it had no need for an allowance for possible losses.
Reclassifications
Certain reclassifications have been made to the Consolidated Balance Sheet as of December 31, 2006 and to the three months and nine months ended September 30, 2006 combined and consolidated statements of income to conform to the current period presentation.
Revenue Recognition
Because there are timing differences between the delivery of natural gas and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at September 30, 2007 and December 31, 2006 of $50.6 million and $19.4 million, respectively, which are included in accounts receivable on its consolidated balance sheets.
Capitalized Interest
The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and gas wells and other capital projects. Interest is capitalized only during the periods in which these assets are brought to their intended use.
The weighted average interest rate used to capitalize interest was 7.3% and 6.6% for the three months and nine months ended September 30, 2007, which resulted in interest capitalized of $722,000 and $1.6 million for the respective periods. There was no interest capitalized for the three months and nine months ended September 30, 2006.
Recently Issued Financial Accounting Standards
In April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 39-1, amendment of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FIN 39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of FIN 39-1 to have an impact on its financial position or results of operations.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The statement offers various options in electing to apply its provisions and at this time the Company has not made any decision as to its application and is evaluating the impact of the adoption of SFAS 159 on the Company’s financial position and results of operations.
8
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
September 30, 2007
(Unaudited)
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – (Continued)
In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, “Accounting for Registration Payment Arrangements.” FSP EITF 00-19-2 requires an issuer of financial instruments, such as debt, convertible debt, equity shares or warrants, to account for a contingent obligation to transfer consideration under a registration payment arrangement in accordance with Financial Accounting Standards No. 5, “Accounting for Contingencies” (“Statement 5”), and FASB Interpretation 14, “Reasonable Estimation of the Amount of a Loss.” The accounting applies regardless of whether the registration payment arrangement is a provision in a financial instrument or a separate agreement. The FSP requires issuers to make certain disclosures for each registration payment arrangement or group of similar arrangements. The FSP is effective for fiscal years beginning after December 15, 2006 for registration payment arrangements and financial instruments subject to those arrangements that are entered into prior to December 21, 2006. The Company applied the consensus in FSP EITF 00-19-2 effective January 1, 2007. The Company reviewed the penalty terms in the registration rights agreement related to its private placement entered into on June 29, 2007 (See Note 15), pursuant to the guidance in the FSP, and determined that the probability of payment is remote under Statement 5 based upon the Company’s status of current related filings. As a result, the application of FSP EITF 00-19-2 did not have an effect on the Company’s financial position or results of operations.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for the Company beginning January 1, 2008. The Company is currently evaluating the impact of the adoption of SFAS 157 on its financial position and results of operations.
NOTE 3 – ACQUISITION OF DTE GAS & OIL COMPANY
On June 29, 2007, the Company acquired all of the outstanding equity interests of DTE Gas & Oil Company (“DGO”) from DTE Energy Company (NYSE:DTE) and MCN Energy Enterprises for $1.268 billion, including adjustments for working capital of $10.4 million and current year capital expenditures of $19.0 million. Assets acquired include interests in approximately 2,150 natural gas wells with estimated proved reserves of approximately 613.7 billion cubic feet of natural gas equivalents located in the northern lower peninsula of Michigan, 228,000 developed acres, and 66,000 undeveloped acres. With this acquisition, the Company increased its natural gas and oil production as well as entered into a new region that offers additional opportunities to expand its operations. Subsequent to the acquisition of DGO, the Company changed its name to Atlas Gas & Oil Company (“AGO”).
9
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
September 30, 2007
(Unaudited)
NOTE 3 – ACQUISITION OF DTE GAS & OIL COMPANY (Continued)
To fund the acquisition, the Company borrowed $713.9 million on its new credit facility (See Note 9) and received net proceeds of $597.5 million from a private placement of its Class B common and new Class D units (See Note 15). Proceeds of $52.5 million were used to pay the outstanding balance of the Company’s credit facility with Wachovia Bank. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, Business Combinations (“SFAS No. 141”). The following table presents the preliminary purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilities assumed based on their estimated fair market value at the date of acquisition (in thousands):
Accounts receivable | $ | 33,412 | ||
Prepaid expenses | 515 | |||
Leaseholds, wells and related equipment | 1,269,839 | |||
Total assets acquired | 1,303,766 | |||
Accounts payable and accrued liabilities | (21,869 | ) | ||
Asset retirement obligations | (13,920 | ) | ||
(35,789 | ) | |||
Net assets acquired | $ | 1,267,977 |
Due to its recent date of acquisition, the purchase price allocation is based on preliminary data that is subject to adjustment and could change significantly as the Company continues to evaluate this allocation. AGO’s operations are included within the Company’s combined and consolidated financial statements beginning June 29, 2007.
The following data presents pro forma revenues, net income and basic and diluted net income per unit for the Company as if the AGO acquisition, Class B common unit and Class D equity offerings (See Note 15) and new revolving credit facility (See Note 9) had occurred on January 1, 2006. The Company has prepared these pro forma financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Company had completed the acquisition at January 1, 2006 or the results that will be attained in the future. Net income for the three months and nine months ended September 30, 2006 are periods prior to the Company’s initial public offering on December 18, 2006, and therefore, no earnings per unit has been presented (in thousands, except per unit amounts):
Nine Months Ended | ||||||||||
September 30, 2007 | ||||||||||
As | Pro Forma | Pro | ||||||||
Reported | Adjustments | Forma | ||||||||
Revenues | $ | 413,515 | $ | 15,888 | $ | 429,403 | ||||
Net income | 93,218 | (60,159 | ) | 33,059 | ||||||
Net income per Class B common and Class D unit outstanding – basic | 2.02 | $ | (1.48 | ) | $ | .54 | ||||
Weighted average Class B common and Class D units outstanding - basic | 44,933 | 15,777 | 60,710 | |||||||
Net income per Class B common and Class D unit – diluted | $ | 1.99 | $ | (1.45 | ) | $ | .54 | |||
Weighted average Class B common and Class D units outstanding – diluted | 45,480 | 16,022 | 61,502 |
Three Months Ended | Nine Months Ended | ||||||||||||||||||
September 30, 2006 | September 30, 2006 | ||||||||||||||||||
As | Pro Forma | Pro | As | Pro Forma | Pro | ||||||||||||||
Reported | Adjustments | Forma | Reported | Adjustments | Forma | ||||||||||||||
Revenues | $ | 81,193 | $ | 89,000 | $ | 170,193 | $ | 226,912 | $ | 231,000 | $ | 457,912 | |||||||
Net income | 11,466 | 59,710 | 71,176 | 36,534 | 117,254 | 153,788 |
Pro forma adjustments to revenues include substantial losses on derivatives realized by AGO. All such derivatives were canceled upon the acquisition of AGO by the Company and the Company entered into new derivative contracts covering future AGO production. Pro forma adjustments include financial hedges between AGO and its affiliate.
10
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 4 - COMPREHENSIVE INCOME
Comprehensive income 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. These changes, other than net income, are referred to as “other comprehensive income” and, for the Company, include only changes in the fair value of unrealized hedging gains and losses. A reconciliation of the Company’s comprehensive income for the periods indicated is as follows (in thousands):
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Net income | $ | 31,612 | $ | 11,466 | $ | 93,218 | $ | 36,534 | |||||
Other comprehensive income: | |||||||||||||
Unrealized holding gain on hedging contracts | 32,537 | 16,608 | 13,429 | 26,016 | |||||||||
Less reclassification adjustment for gains realized in net income | (4,844 | ) | (2,024 | ) | (9,598 | ) | (4,940 | ) | |||||
Total other comprehensive income | 27,693 | 14,584 | 3,831 | 21,076 | |||||||||
Comprehensive income | $ | 59,305 | $ | 26,050 | $ | 97,049 | $ | 57,610 |
NOTE 5 – NET INCOME PER COMMON UNIT
At September 30, 2007, the Company had three classes of units issued and outstanding: (i) Class A units, representing AAI’s management units, (ii) Class B common units representing limited liability company interests listed on the New York Stock Exchange under the symbol “ATN”, and (iii) Class D units. See Note 15 for details regarding the Class D units.
Basic earnings per unit for Class B and Class D units is computed by dividing net income, after the deduction of net income allocable to the Class A units, attributable to unit holders by the weighted average number of units outstanding during each period. The Class A unit holder’s allocable share of net income is calculated on a quarterly basis based upon AAI’s 2% interest and incentive distributions. Since it is assumed that the conversion of the Class D units into Class B common units will occur, the units have been combined for purposes of presenting net income and net income per unit has been allocated on an equal basis.
Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of the Company’s restricted unit and unit option awards, as calculated by the treasury stock method. Restricted units and unit options consist of common units issuable under the terms of the Company’s Long-Term Incentive Plan (See Note 14). The following table sets forth the reconciliation of the Company’s weighted average number of common units as of September 30, 2007 used to compute basic net income per unit with those used to compute diluted net income per unit (in thousands):
Weighted Average Class B common and Class D units outstanding:
Three Months | Nine Months | ||||||
Ended | Ended | ||||||
September 30, 2007 | September 30, 2007 | ||||||
Basic units outstanding | 60,710 | 44,933 | |||||
Add effect of dilutive unit incentive awards | 792 | 547 | |||||
Diluted units outstanding | 61,502 | 45,480 |
11
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 6 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL
Other Assets
The following table provides information about other assets at the dates indicated (in thousands):
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Deferred finance costs, net of accumulated amortization of $525 and $3 | $ | 9,536 | $ | 194 | |||
Long-term hedge receivable from Partnerships | 6,732 | 2,131 | |||||
Other | 226 | 122 | |||||
$ | 16,494 | $ | 2,447 |
Deferred finance costs relate to the Company’s new credit facility (see Note 9) and are recorded at cost and are amortized over 5 years, under the terms of the Company’s revolving credit agreement. Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized hedge loss on contracts that has been reallocated to the Partnerships.
Intangible Assets
Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which were recorded at fair value on their acquisition dates. The Company amortizes contracts acquired on the declining balance and straight-line methods over their respective estimated lives, ranging from five to thirteen years. Amortization expense for these contracts for the three months ended September 30, 2007 and 2006 was $205,000 and $220,000, and for the nine months ended September 30, 2007 and 2006 was $613,000 and $659,000, respectively.
The aggregate estimated annual amortization expense of partnership management and operating contracts for the next five years ending September 30 is as follows: 2008—$788,000; 2009—$751,000; 2010—$718,000, 2011—$689,000 and 2012—$287,000
The following table provides information about intangible assets at the dates indicated (in thousands):
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Cost | $ | 14,343 | $ | 14,343 | |||
Accumulated amortization | (9,745 | ) | (9,132 | ) | |||
$ | 4,598 | $ | 5,211 |
Goodwill
The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”), which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at December 31, 2006 indicated there was no impairment loss and no impairment indicators arose during the nine months ended September 30, 2007. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the statements of income in the period in which the impairment is indicated.
12
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 7 – PROPERTY AND EQUIPMENT
Property and equipment is stated at cost. Depreciation, depletion and amortization are based on cost less estimated salvage value primarily using the unit-of-production or straight-line method over the assets estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.
Property and equipment consists of the following at the dates indicated (in thousands):
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Mineral interests: | |||||||
Proved properties | $ | 12,870 | $ | 1,290 | |||
Unproved properties | 1,002 | 1,002 | |||||
Leaseholds, wells and related equipment | 1,729,282 | 348,742 | |||||
Land, building and improvements | 4,152 | 4,169 | |||||
Support equipment | 6,547 | 5,541 | |||||
Other | 5,874 | 4,698 | |||||
1,759,727 | 365,442 | ||||||
Accumulated depreciation, depletion and amortization: | |||||||
Oil and gas properties | (112,392 | ) | (83,216 | ) | |||
Other | (4,524 | ) | (4,412 | ) | |||
(116,916 | ) | (87,628 | ) | ||||
$ | 1,642,811 | $ | 277,814 |
On June 29, 2007, the Company acquired all of the outstanding equity interests in AGO for approximately $1.268 billion including acquisition costs of $11.0 million (See Note 3). Due to the recent date of the acquisition, the purchase price allocation is based upon estimated values and could change significantly as the Company continues to evaluate this preliminary allocation. At September 30, 2007, the portion of the purchase price allocation to property, plant and equipment for the AGO acquisition of $1.268 billion are included in the Leaseholds, wells and related equipment category within the above table.
NOTE 8 – 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 AAI. The employees supporting the Company’s operations are employees of AAI. AAI provides centralized corporate functions on behalf of the Company, including legal, finance, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Company and Atlas Pipeline Partners, L.P. (“Atlas Pipeline”) comprise substantially all of Atlas America’s operations, and therefore the Company and Atlas Pipeline bear substantially all of those costs which are reflected in general and administrative expense in the Company’s combined and consolidated statements of income.
The Company participates in AAI’s cash management program. Any cash activity performed by AAI on behalf of the Company has been recorded as parent advances and included in Advances from affiliate on the Company’s consolidated balance sheets.
Relationship with Company 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 managing general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As a general partner, the Company is liable for Partnership 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 and reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.
13
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)
Relationship with Atlas Pipeline. The Company has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates in Appalachia. This agreement generally provides for the Company to pay Atlas Pipeline 16% of the sales price received for natural gas produced from wells located on Atlas Pipeline’s gathering systems. AAI has agreed to assume the Company’s obligation to pay gathering fees to Atlas Pipeline and the Company has remitted to AAI the gathering fees it receives. These fees are shown as Gathering fees—Atlas Pipeline on the Company’s combined and consolidated statements of income. The Company charges rates to wells connected to these gathering systems, substantially all of which are owned by the Partnerships, generally ranging from $.29 to $.35 per Mcf or a percentage of the sales price received for the natural gas transported and pays this amount to AAI.
NOTE 9 - DEBT
Total debt consists of the following at the dates indicated (in thousands):
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Revolving credit facility | $ | 739,000 | $ | — | |||
Other debt | 82 | 68 | |||||
739,082 | 68 | ||||||
Less current maturities | 42 | 38 | |||||
$ | 739,040 | $ | 30 |
Revolving Credit Facility. Upon the closing of its acquisition of DTE Gas & Oil (See Note 3), the Company replaced its Wachovia Bank credit facility with a new 5-year, $850.0 million credit facility with J.P. Morgan Chase Bank, N.A. (“J.P. Morgan”) as administrative agent, Wachovia Bank, N. A. as syndication agent, and other lenders.. The revolving credit facility has a current borrowing base of $850.0 million which will be redetermined semiannually on April 1 and October 1 subject to changes in the Company’s oil and gas reserves. The initial borrowing base is also scheduled to be reduced to $735.0 million at the earlier of June 29, 2008 or the issuance by the Company of equity or debt securities of at least $200.0 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by the Company’s assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR plus the applicable margin, elected at the Company’s option. At September 30, 2007, the weighted average interest rate on outstanding borrowings was 7.5%.
The base rate for any day equals the higher of the federal funds rate plus 0.50% or the J.P. Morgan prime rate. 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. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans.
The J.P. Morgan credit facility requires the Company to maintain specified financial ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness. The facility limits the distributions payable by the Company if an event of default has occurred and is continuing or would occur as a result of such distribution. The Company is in compliance with these covenants as of September 30, 2007. The facility terminates in June 2012, when all outstanding borrowings must be repaid. At September 30, 2007 and December 31, 2006, $739.0 million and $0.0, respectively, were outstanding under this facility and the previous Wachovia Bank credit facility. In addition, letters of credit of $1.1 million and $495,000 were outstanding at each date which are not reflected as borrowings on the Company’s consolidated balance sheets.
14
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 9 - DEBT (Continued)
Annual principal debt payments over the next five years ending September 30 are as follows (in thousands)
2008 | $ | 42 | ||
2009 | 17 | |||
2010 | 11 | |||
2011 | 12 | |||
2012 | 739,000 | |||
$ | 739,082 |
NOTE 10 - ASSET RETIREMENT OBLIGATIONS
The Company accounts for asset retirement obligations under FAS No. 143, “Accounting for Retirement Asset Obligations” (“SFAS 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”, (“FIN 47”), which require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset. The Company has asset retirement obligations related to the plugging and abandonment of its oil and gas wells. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depreciation, depletion and amortization.
A reconciliation of the Company’s 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, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Asset retirement obligations, beginning of period | $ | 41,792 | $ | 19,760 | $ | 26,726 | $ | 18,499 | |||||
Liabilities acquired (See Note 3) | 505 | — | 13,920 | — | |||||||||
Liabilities incurred | 997 | 490 | 2,024 | 1,616 | |||||||||
Liabilities settled | (9 | ) | (67 | ) | (30 | ) | (180 | ) | |||||
Accretion expense | 673 | 124 | 1,318 | 372 | |||||||||
Asset retirement obligations, end of period | $ | 43,958 | $ | 20,307 | $ | 43,958 | $ | 20,307 |
The above accretion expense is included in depreciation, depletion and amortization in the Company’s Combined and Consolidated Statements of Income.
NOTE 11 - DERIVATIVE INSTRUMENTS
The Company formally documents all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. The Company assesses, 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 the hedged items. Historically these contracts have qualified and been designated as cash flow hedges and 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. Such gains and losses are charged or credited to Accumulated other comprehensive income (loss) and recognized as a component of gas revenues in the month the hedged gas 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 gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.
15
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 11 – DERIVATIVE INSTRUMENTS (Continued)
At September 30, 2007, the Company had 384 open natural gas futures contracts related to natural gas sales covering 147.5 million MMBtus of natural gas (which includes 76.9 million MMBtu covering natural gas produced by assets acquired from AGO), maturing through December 31, 2012 at a combined average settlement price of $8.04 per MMBtu.
On May 18, 2007, the Company signed a definitive agreement to acquire AGO (see Note 3). In connection with the financing of this transaction, the Company agreed as a condition precedent to closing that it would hedge 80% of its projected natural gas volumes for no less than three years from the closing date of the transaction. During May 2007, the Company entered into derivative instruments to hedge 80% of the projected production of the assets to be acquired as required under the financing agreement. The production volume of the assets to be acquired was not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, the Company recognized the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative value recorded within revenues in its consolidated statements of income. The Company recognized non-cash income of $26.3 million related to the change in value of these derivatives from May 22, 2007 to June 28, 2007, which is shown as “Gain on mark-to-market derivatives” in the Combined and Consolidated Statements of Income for the nine months ended September 30, 2007. Upon closing of the acquisition on June 29, 2007, the production volume of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and the Company evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133. In addition, the Company recognized gains on settled contracts covering natural gas production of $4.9 million and $2.0 million for the three months ended September 30, 2007 and 2006, and $9.6 million and $4.9 million for nine months ended September 30, 2007 and 2006, respectively. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its natural gas, there were no gains or losses recognized during the three months and nine months ended September 30, 2007 and 2006, respectively and for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges
Of the $24.9 million net gain in Accumulated other comprehensive income at September 30, 2007, the Company will reclassify $16.6 million of gains to its Combined and Consolidated Statements of Income over the next twelve-month period as these contracts expire, and $8.3 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.
As of September 30, 2007, the Company had the following natural gas volumes hedged:
Fixed Price Swaps
Twelve Month | Average | Fair Value | ||||||||
Period Ending | Volumes | Fixed Price | Asset (Liability) | |||||||
September 30, | (MMBtu) | (per MMBtu) | (in thousands) (1) | |||||||
2008 | 35,470,000 | $ | 8.15 | $ | 37,289 | |||||
2009 | 33,530,000 | 8.32 | 11,310 | |||||||
2010 | 25,430,000 | 8.02 | 517 | |||||||
2011 | 18,950,000 | 7.75 | (790 | ) | ||||||
2012 | 11,150,000 | 7.62 | 821 | |||||||
2013 | 2,250,000 | 7.67 | 346 | |||||||
$ | 49,493 |
16
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 11 – DERIVATIVE INSTRUMENTS (Continued)
Costless Collars
Twelve Month | Average | Fair Value | |||||||||||
Period Ending | Volumes | Floor and Cap | Asset (Liability) | ||||||||||
September 30, | Option Type | (MMBtu) | (per MMBtu) | (in thousands) (1) | |||||||||
2008 | Puts purchased | 450,000 | $ | 7.50 | $ | 314 | |||||||
2008 | Calls sold | 450,000 | 8.60 | — | |||||||||
2008 | Puts purchased | 1,170,000 | 7.50 | 325 | |||||||||
2008 | Calls sold | 1,170,000 | 9.40 | — | |||||||||
2009 | Puts purchased | 390,000 | 7.50 | — | |||||||||
2009 | Calls sold | 390,000 | 9.40 | (32 | ) | ||||||||
2010 | Puts purchased | 2,160,000 | 7.75 | 144 | |||||||||
2010 | Calls sold | 2,160,000 | 8.75 | — | |||||||||
2011 | Puts purchased | 720,000 | 7.75 | (4 | ) | ||||||||
2011 | Calls sold | 720,000 | 8.75 | — | |||||||||
2011 | Puts purchased | 5,400,000 | 7.50 | 240 | |||||||||
2011 | Calls sold | 5,400,000 | 8.45 | — | |||||||||
2012 | Puts purchased | 1,800,000 | 7.50 | — | |||||||||
2012 | Calls sold | 1,800,000 | 8.45 | (25 | ) | ||||||||
2012 | Puts purchased | 6,480,000 | 7.50 | — | |||||||||
2012 | Calls sold | 6,480,000 | 8.45 | (24 | ) | ||||||||
2013 | Puts purchased | 2,160,000 | 7.00 | — | |||||||||
2013 | Calls sold | 2,160,000 | 8.37 | (19 | ) | ||||||||
919 | |||||||||||||
Total net asset | $ | 50,412 |
(1) | Fair value based on forward NYMEX natural gas prices. |
The fair value of the derivatives is included in the Company’s Consolidated Balance Sheets as of the dates indicated is as follows (in thousands):
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Current portion of hedge asset | $ | 40,384 | $ | 27,618 | |||
Long-term hedge asset | 23,854 | 23,843 | |||||
Current portion of hedge liability | (2,457 | ) | (172 | ) | |||
Long-term hedge liability | (11,369 | ) | (3,835 | ) | |||
$ | 50,412 | $ | 47,454 |
In addition, $5.7 million and $26.4 million of unrealized hedge gains has been allocated to the Partnerships and included in the Consolidated Balance Sheets as of the dates indicated is as follows (in thousands):
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Unrealized hedge loss – short-term | $ | 1,457 | $ | 96 | |||
Other assets – long-term | 6,732 | 2,131 | |||||
Accrued liabilities – short-term | (9,076 | ) | (15,345 | ) | |||
Unrealized hedge gain - long-term | (4,852 | ) | (13,248 | ) | |||
$ | (5,739 | ) | $ | (26,366 | ) |
17
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 12 - COMMITMENTS AND CONTINGENCIES
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 its financial condition or results of operations.
One of the Company’s subsidiaries, Resource Energy, LLC, together with Resource America, Inc., (the former parent of AAI), was a defendant in a class action originally filed in February 2000 in the New York Supreme Court, Chautauqua County, by individuals, putatively on their own behalf and on behalf of similarly situated individuals, who leased property to the Company. The complaint alleged that the Company was not paying landowners the proper amount of royalty revenues with respect to natural gas produced from the leased properties. The complaint was seeking damages in an unspecified amount for the alleged difference between the amount of royalties actually paid and the amount of royalties that allegedly should have been paid. In April 2007, a settlement of this lawsuit was approved by the court. Pursuant to the settlement terms, the Company paid $300,000 in May 2007, upgraded certain gathering systems and capped certain transportation expenses chargeable to the land owners. The Company is indemnified by AAI for this matter.
Atlas Gas & Oil Company LLC, as successor to DTE Gas & Oil Company, is one of four defendants in a personal injury action filed in Antrim County Circuit Court in northern Michigan in August, 2006. The complaint alleges that plaintiff suffered serious personal injuries as a result of the defendants’ negligence. A tentative settlement of this lawsuit was reached, the terms of which are subject to final approval by the court. Pursuant to the settlement terms, the Company paid $125,000 to the plaintiff in October 2007.
The Company has begun construction of a new $2.9 million field operations building and yard in Fayette County, Pennsylvania of which $1.7 million remains committed at September 30, 2007.
NOTE 13 - OPERATING SEGMENT INFORMATION
The Company’s operations include two reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows (in thousands):
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Gas and oil production: | |||||||||||||
Revenues | $ | 63,265 | $ | 21,888 | $ | 136,097 | $ | 66,696 | |||||
Costs and expenses | 11,960 | 3,709 | 20,307 | 10,550 | |||||||||
Segment profit | $ | 51,305 | $ | 18,179 | $ | 115,790 | $ | 56,146 | |||||
Partnership management: | |||||||||||||
Revenues | $ | 117,004 | $ | 59,305 | $ | 277,418 | $ | 160,216 | |||||
Costs and expenses | 95,698 | 52,784 | 226,506 | 146,095 | |||||||||
Segment profit | $ | 21,306 | $ | 6,521 | $ | 50,912 | $ | 14,121 |
18
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 13 – OPERATING SEGMENT INFORMATION (Continued)
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Reconciliation of segment profit to net income | |||||||||||||
Segment profit | |||||||||||||
Gas and oil production | $ | 51,305 | $ | 18,179 | $ | 115,790 | $ | 56,146 | |||||
Partnership management | 21,306 | 6,521 | 50,912 | 14,121 | |||||||||
Total segment profit | 72,611 | 24,700 | 166,702 | 70,267 | |||||||||
General and administrative | (9,062 | ) | (7,715 | ) | (27,319 | ) | (18,384 | ) | |||||
Depreciation, depletion and amortization | (19,013 | ) | (6,124 | ) | (31,688 | ) | (16,311 | ) | |||||
Interest expense | (13,032 | ) | (8 | ) | (14,972 | ) | (50 | ) | |||||
Other - net | 108 | 613 | 495 | 1,012 | |||||||||
Net income | $ | 31,612 | $ | 11,466 | $ | 93,218 | $ | 36,534 | |||||
Capital expenditures | |||||||||||||
Gas and oil production | |||||||||||||
Acquisition of AGO | $ | 2,183 | $ | — | $ | 1,269,839 | $ | —- | |||||
Other | 68,768 | 16,382 | 122,049 | 52,533 | |||||||||
70,951 | 16,382 | 1,391,888 | 52,533 | ||||||||||
Partnership management | 1,134 | 203 | 2,384 | 1,126 | |||||||||
Furniture, fixtures, and data processing | 445 | 205 | 995 | 417 | |||||||||
$ | 72,530 | $ | 16,790 | $ | 1,395,267 | $ | 54,076 |
September 30, | December 31, | ||||||
2007 | 2006 | ||||||
Balance sheets: | |||||||
Goodwill | |||||||
Gas and oil production | $ | 21,527 | $ | 21,527 | |||
Partnership management | 13,639 | 13,639 | |||||
$ | 35,166 | $ | 35,166 | ||||
Total assets: | |||||||
Gas and oil production | $ | 1,782,990 | $ | 377,807 | |||
Partnership management | 27,147 | 26,474 | |||||
Corporate | 22,102 | 11,182 | |||||
$ | 1,832,239 | $ | 415,463 |
For the three and nine months ended September 30, 2007 and 2006, there were no operating segments that had revenues from a single customer which exceeded 10% of total revenues.
19
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 14 - BENEFIT PLANS
Incentive Plan. In December 2006, the Company adopted a Long-Term Incentive Plan (“ATN LTIP”), which provides performance incentive awards to officers, employees and board members and employees of its affiliates, consultants and joint-venture partners. The ATN LTIP is administered by the AAI compensation committee, which may grant awards of restricted units, phantom units or unit options for an aggregate of 3,742,000 common units.
Restricted and Phantom Units. A restricted unit is a common unit that is subject to forfeiture prior to vesting. A phantom unit represents the right to receive one of the Company’s common units upon vesting or the fair market value thereof in cash. Units will vest over a four- year service period. The fair value of the grants is based on the closing price of the common units or cash equivalent to the then fair market value of a common unit on the grant date, and is being charged to operations over the requisite service periods. Upon termination of service by a grantee, all non-vested units are forfeited. The Company recognized $963,000 and $2.6 million in compensation expense related to restricted and phantom units for the three months and nine months ended September 30, 2007, respectively. At September 30, 2007, the Company had approximately $12.8 million of unrecognized compensation expense related to the non-vested portion of these units.
The following table summarizes the activity of restricted and phantom units for the nine months ended September 30, 2007.
Weighted | |||||||
Average | |||||||
Grant Date | |||||||
Units | Fair Value | ||||||
Non-vested units outstanding, December 31, 2006 | 47,619 | $ | 21.00 | ||||
Granted | 590,950 | 24.63 | |||||
Vested | (11,904 | ) | 21.00 | ||||
Forfeited | (2,000 | ) | 23.06 | ||||
Non-vested units outstanding, September 30, 2007 | 624,665 | $ | 24.42 |
Options. Option awards expire 10 years from the date of grant, and will vest over a four-year service period. The Company uses the Black-Scholes option pricing model to estimate the weighted average fair value per option granted with the following assumptions:
Date | Options | Expected | Risk-Free | Expected | Expected | Weighted Average | |||||||||||||
Granted | Granted | Dividend Yield | Interest Rate | Volatility | Life | Fair Value | |||||||||||||
December 2006 | 373,752 | 8.0 | % | 4.4 | % | 25.0 | % | 6.25 years | $ | 2.14 | |||||||||
January 2007 | 1,296,400 | 8.0 | % | 4.7 | % | 25.0 | % | 6.25 years | $ | 2.41 | |||||||||
June 2007 | 100,000 | 5.1 | % | 4.7 | % | 25.0 | % | 6.25 years | $ | 5.93 | |||||||||
July 2007 | 135,600 | 5.1 | % | 4.7 | % | 25.0 | % | 6.25 years | $ | 6.07 |
The Company recognized $329,000 and $820,000 in compensation expense related to options granted for the three months and nine months ended September 30, 2007, respectively. At September 30, 2007, the Company had approximately $4.3 million of unrecognized compensation expense related to the non-vested portion of the options.
20
ATLAS ENERGY RESOURCES, LLC
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2007
(Unaudited)
NOTE 14 - BENEFIT PLANS (Continued)
The following table summarizes the activity of options for the nine months ended September 30, 2007.
Weighted | |||||||||||||
Average | Aggregate | ||||||||||||
Weighted | Remaining | Intrinsic | |||||||||||
Average | Contractual | Value | |||||||||||
Units | Exercise Price | Term (in years) | (in thousands) | ||||||||||
Outstanding, December 31, 2006 | 373,752 | $ | 21.00 | 8.50 | |||||||||
Granted | 1,532,000 | 24.84 | 9.33 | ||||||||||
Forfeited or expired | (10,100 | ) | 23.06 | — | |||||||||
Outstanding, September 30, 2007 | 1,895,652 | $ | 24.09 | 9.16 | $ | 14,228 | |||||||
Options exercisable, September 30, 2007 | 93,438 | ||||||||||||
Available for grant | 1,209,779 |
NOTE 15 – PRIVATE PLACEMENT OF CLASS B COMMON AND CLASS D UNITS
To partially fund the acquisition of AGO, the Company completed a private placement of 7,298,181 Class B common units and 16,702,828 Class D units to a group of institutional investors at a weighted average price of $25.00 per unit for net proceeds of $597.5 million. The private placement of the Class B common and Class D units was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. The Class D units are a new class of equity security which automatically converts to common units on a one-to-one basis with the consent of the Company’s unit holders. The Company plans to obtain the consent by November 11, 2007. The Class D units have no voting rights and are subordinated to the Class A and Class B common units in the payment of dividends and on dissolution or liquidation. The Company entered into a registration rights agreement in connection with the sale of the units. The agreement requires the Company to prepare and file a registration statement covering the resale of such units by January 31, 2008 and have such registration statement declared effective by May 30, 2008. The Company could be required to pay certain amounts as defined in the agreement in the event the registration deadlines are not met. The potential payments would be approximately 0.25% of the gross proceeds of the offerings or $1.5 million for the first 30-day period after the deadline, increasing by an additional 0.25% per 30-day period, up to a maximum of 1.0% of the gross proceeds of the offerings per 30-day period.
NOTE 16 - CASH DISTRIBUTIONS
The Company is required to distribute, within 45 days after the end of each quarter, all of its available cash (as defined in its limited liability agreement) for that quarter. Distributions declared by the Company from inception are as follows:
Date Cash Distribution Paid or Payable | For Quarter Ended | Cash Distribution per Common Unit | Total Cash Distribution to Common Unit Holders(3) | Total Cash Distribution to the Manager | |||||||||
(in thousands) | (in thousands) | ||||||||||||
February 14, 2007 | December 31, 2006 | $ | 0.06(1 | ) | $ | 2,231 | $ | 45 | |||||
May 15, 2007 | March 31, 2007 | $ | 0.43 | $ | 15,989 | $ | 322 | ||||||
August 14, 2007 | June 30, 2007 | $ | 0.43 | $ | 15,989 | $ | 322 | ||||||
November 14, 2007 | September 30, 2007 | $ | 0.55 | $ | 33,697 | $ | 681(2 | ) |
(1) | Represents a prorated distribution of $0.42 per unit for the period from December 18, 2006, the date of the Company’s initial public offering through December 31, 2006. |
(2) | Does not include $784,000 in incentive distributions payable to the manager if certain distribution levels are obtained in accordance with our limited liability company agreement. |
(3) | Includes distributions paid on unissued units under the Company’s employee incentive plan. |
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)
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, under the caption “Risk Factors”, in our annual report on Form 10-K for fiscal 2006. These risks and uncertainties could cause actual results to differ materially. 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
We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in northern Michigan and the Appalachian Basin. In northern Michigan, we drill wells for our own account. In the Appalachian Basin, we sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance the exploitation and development of our acreage.
We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America (NASDAQ: ATLS). We are managed by Atlas Energy Management, a wholly-owned subsidiary of Atlas America. Through our manager, Atlas America personnel are responsible for managing our assets and raising capital.
As of and for the three months ended September 30, 2007, we had the following key assets:
In our Appalachia gas and oil operations:
· | direct and indirect working interests in approximately 7,454 gross producing gas and oil wells; |
· | overriding royalty interests in approximately 626 gross producing gas and oil wells; |
· | net daily production of 32 MMcfe per day; |
· | approximately 758,300 gross (711,000 net) acres, of which approximately 476,100 gross (467,800 net) acres, are undeveloped; and |
· | an interest in a joint venture that gives us the right to drill up to 77 additional net wells before December 31, 2007 on approximately 212,000 acres in Tennessee. |
In our Michigan gas and oil operations:
· | direct and indirect working interests in approximately 2,234 gross producing gas and oil wells; |
· | overriding royalty interests in approximately 93 gross producing gas and oil wells; |
· | net daily production of 59 MMcfe per day; and |
· | approximately 366,500 gross (299,500 net) acres, of which approximately 78,900 gross (65,600 net) acres, are undeveloped. |
Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.
RECENT EVENTS
Acquisition of DTE Antrim Assets
On June 29, 2007, we acquired DTE Gas & Oil Company, now referred to as Atlas Gas & Oil or AGO for $1.268 billion, including related expenses, subject to final post-closing adjustments. Atlas Gas & Oil owns interests in approximately 2,210 natural gas wells producing from the Antrim Shale, located in Michigan’s northern lower peninsula. The Antrim Shale is a mature play characterized by long-lived reserves and predictable production rates. Atlas Gas & Oil has 610.6 Bcfe of proved reserves on its approximately 299,500 net developed acres and 65,600 net undeveloped acres as of September 30, 2007. These assets will further diversify our reserve base.
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In order to produce methane from the Antrim Shale, water must be drawn off first, a process that takes 3 to 12 months. As a result, we don't believe our Michigan business unit wells are compatible with our investment partnerships and intend to drill those wells for our own account.
Private Equity Offering
We financed a portion of the purchase price for the AGO acquisition with the proceeds of a private offering, completed on June 29, 2007, of 7,298,181 Class B common units and 16,702,828 Class D units at a weighted average price of $25.00 for net proceeds of $597.5 million. The Class D units represent a new class of our equity securities that may convert into common units if the conversion is approved by our unitholders. We have agreed to hold a meeting of our unitholders to consider, or obtain the consent of our unitholders as soon as reasonably practicable, but no later than November 11, 2007. Atlas America and Atlas Energy Management currently own approximately 68% of our units entitled to vote on the conversion. In connection with the private placement, Atlas America and Atlas Energy Management entered into a voting agreement pursuant to which they agreed to vote their units in favor of the conversion of the Class D units. Once the conversion is approved, the Class D units will automatically convert to common units on a one-for-one basis. The Class D units have no voting rights and are subordinated to the Class B common units in the payment of dividends and on dissolution or liquidation. We could be required to pay certain amounts as defined in the agreement in the event the registration deadlines are not met. The potential payments would be approximately 0.25% of the gross proceeds of the offerings or $1.5 million for the first 30-day period after the deadline, increasing by an additional 0.25% per 30-day period, up to a maximum of 1.0% of the gross proceeds of the offerings per 30-day period.
New Credit Facility
Upon the closing of the AGO acquisition, we replaced our credit facility with a new 5-year, $850.0 million credit facility administered by JPMorgan Chase Bank, N.A. The credit facility has a current borrowing base of $850.0 million which may be redetermined subject to changes in our oil and gas reserves. The initial borrowing base is also scheduled to be reduced to $735.0 million at the earlier of June 29, 2008 or the issuance by us of equity or debt securities of at least $200 million. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by our assets and bears interest at either the base rate plus the applicable margin or at adjusted LIBOR rate plus the applicable margin, elected at our option. The base rate for any day equals the higher of the federal funds rate plus 0.50% of the JPMorgan prime rate. 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. The applicable margin ranges from 0.0% to 1.25% for base rate loans and 1.00% to 2.25% for LIBOR loans. At September 30, 2007, $740.1 million was outstanding under this facility at a weighted average interest rate of 7.5%., including letters of credit of $1.1 million, which are not reflected as borrowings on our consolidated balance sheets.
BUSINESS SEGMENTS
We operate two business segments:
· | Our gas and oil production segment, which consists of our interests in oil and gas properties. |
· | Our partnership management segment, which consists of well construction and completion, administration and oversight, well services and gathering activities. |
Gas and Oil Production
At September 30, 2007, we owned interests in approximately 8,080 gross wells in Appalachia, of which we operated approximately 6,880. On average during the quarter ended September 30, 2007, gross production from our wells was approximately 87.9 Mmcfe/d, or approximately 12.9 Mcfe/d per well. Through the nine months ended September 30, 2007, we have drilled 860.0 gross wells, 99% of which were successful in producing natural gas in commercial quantities. In Michigan, as of September 30, 2007, we owned interests in approximately 2,234 gross wells of which we operated approximately 1,680.
We have a joint venture in Tennessee with Knox Energy, LLC that gave us an exclusive right to drill up to 200 additional net wells through December 31, 2007 on approximately 212,000 acres owned by Knox Energy. This agreement was amended and extended, giving us the right to drill an additional 77 net wells until December 31, 2007. As of September 30, 2007, we had drilled 263 net wells under this agreement.
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In the fourth quarter of 2006 we and our investment partnerships began drilling wells to multiple pay zones, including the Marcellus Shale of Western Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 6,000 and 8,500 feet and ranges in thickness from 75 to 150 feet on our acreage in Western Pennsylvania. We currently hold approximately 239,500 acres of prospective Marcellus acreage in these counties. Much of this acreage is held by production, meaning that it is covered by a continuing lease due to production from the property. We have currently drilled 13 wells and intend to drill 120 vertical Marcellus Shale wells during the next 18 months.
Partnership Management
We generally fund our drilling activities, other than those of our Michigan business unit, through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $199.4 million in the nine months ended September 30, 2007 and $218.5 million in fiscal 2006. During the nine months ended September 30, 2007, our investment partnerships invested $313.3 million in drilling and completing wells, of which we contributed $72.5 million.
We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. 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. We receive an interest in our investment partnerships proportionate to the amount of capital and the value of the leasehold acreage we contribute, typically 27% to 30% of the overall capitalization in a particular partnership. We also receive an additional interest in each partnership, typically 7%, for which we do not make any additional capital contribution.
We generally agree to subordinate up to 50% of our share of production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003. We do not believe any amounts which may be subordinated in the future will be material to our operations.
Our investment partnerships provide tax advantages to their investors because an investor’s share of the partnership’s intangible drilling cost deduction may be used to offset ordinary income. Intangible drilling costs include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling. Historically, under our partnership agreements, approximately 90% of the subscription proceeds received by each partnership have been used to pay 100% of the partnership’s intangible drilling costs. For example, an investment of $10,000 has generally permitted the investor to deduct approximately $9,000 in the year in which the investor invests.
GENERAL TRENDS AND OUTLOOK
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.
Commodity Prices
Significant factors that may impact future commodity prices include developments in the issues currently impacting Iraq and Iran and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; and overall North American gas supply and demand fundamentals, including the impact of increasing liquefied natural gas deliveries to the United States. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for commodities that we produce will generally approximate market prices in the geographic region of the production.
In order to address, in part, volatility in commodity prices, we have implemented a hedging program that is intended to reduce the volatility in our revenues. Under that program, we had financial hedges in place for approximately 84% of our expected production for the twelve months ended September 30, 2008. This policy mitigates, but does not eliminate, our sensitivity to short-term changes in commodity prices. Please read “— Quantitative and Qualitative Disclosures About Market Risk.”
Natural Gas Supply and Outlook
We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States 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. The areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.
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While we anticipate continued high levels of exploration and production activities 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.
Reserve Outlook
Our future oil and gas reserves, production, cash flow and our ability to make payments on borrowings and distributions depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. In order to sustain and grow our level of distributions, we will need to make acquisitions that are accretive to distributable cash flow per unit. We intend to pursue acquisitions of producing oil and gas properties from third parties. In addition, we reserve a portion of our cash flow from operations to allow us to develop our oil and gas properties at a level that will allow us to maintain a flat production profile and reserve levels.
Impact of Inflation
Inflation in the United States did not have a material impact on our results of operations for the three-year period ended September 30, 2007. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. To the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees.
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RESULTS OF OPERATIONS
GAS AND OIL PRODUCTION
The following table sets forth information relating to our production revenues, production volumes, sales prices, production costs and depletion for the periods indicated:
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Production revenues (in thousands): | |||||||||||||
Gas (1) (6) | $ | 60,302 | $ | 19,402 | $ | 102,439 | $ | 59,332 | |||||
Oil | $ | 2,938 | $ | 2,489 | $ | 7,357 | $ | 7,323 | |||||
Production volume:(2) | |||||||||||||
Appalachia | |||||||||||||
Gas (Mcf/day) (1) | 29,324 | 25,955 | 26,220 | 24,064 | |||||||||
Oil (Bbls/day) | 443 | 416 | 422 | 415 | |||||||||
Michigan(5) | |||||||||||||
Gas (Mcf/day) | 59,304 | — | 59,325 | — | |||||||||
Oil (Bbls/day) | 3 | — | 3 | — | |||||||||
Total (Mcfe/day) (5) | 91,304 | 28,451 | 88,095 | 26,554 | |||||||||
Average sales prices: | |||||||||||||
Gas (per Mcf) (3) (7) | $ | 8.19 | $ | 8.13 | $ | 8.55 | $ | 9.03 | |||||
Oil (per Bbl) | $ | 71.63 | $ | 65.01 | $ | 63.75 | $ | 64.59 | |||||
Production costs:(4) | |||||||||||||
As a percent of production revenues | 13 | % | 11 | % | 12 | % | 10 | % | |||||
Per Mcfe | $ | .99 | $ | .93 | $ | .95 | $ | .92 | |||||
Depletion per Mcfe | $ | 2.19 | $ | 2.14 | $ | 2.24 | $ | 2.04 |
(1) | Excludes sales of residual gas and sales to landowners. |
(2) | 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 partnership’s proportionate net revenue interest in these wells. |
(3) | Our average sales price before the effects of financial hedging were $6.55 and $7.32 per Mcf for the three months ended September 30, 2007 and 2006, and $7.12 and $8.10 per Mcf for the nine months ended September 30, 2007 and 2006, respectively. |
(4) | Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance and production overhead. |
(5) | Amounts represent production volumes related to AGO from the acquisition date (June 29, 2007) to September 30, 2007. |
(6) | Excludes non-qualifying hedge gains of $26.3 million associated with the AGO acquisition in the nine months ended September 30, 2007. |
(7) | Includes $6.5 million in derivative proceeds which were not included as revenue in the three months and nine months ended September 30, 2007. |
Three Months Ended September 30, 2007 Compared to the Three Months Ended September 30, 2006
Our natural gas revenues were $60.3 million in the three months ended September 30, 2007, an increase of $40.9 million (211%) from $19.4 million in the three months ended September 30, 2006. The increase was attributable to volumes associated with our Michigan operations acquired on June 29, 2007 and a 13% increase in the production volumes in our Appalachian operating area. The $40.9 million increase in natural gas revenues consisted of $42.6 million attributable to increases in production volumes and $1.7 million attributable to decreases in natural gas prices.
We believe that gas volumes will continue to be favorably impacted in the remainder of 2007 with the contribution of our Michigan business unit and as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.
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Our oil revenues were $2.9 million in the three months ended September 30, 2007, an increase of $449,000 (18%) from $2.5 million during the three months ended September 30, 2006. This increase resulted from a 7% increase in production volumes, and a 10% increase in the average sales price. The $449,000 increase consisted of $254,000 attributable to increases in sales prices, and $195,000 attributable to volume increases, due to an increase in the number of new wells placed into production during the three months ended September 30, 2007 and volumes associated with our Michigan operations.
Our production costs were $12.0 million in the three months ended September 30, 2007, an increase of $8.3 million (222%) from $3.7 million in the three months ended September 30, 2006. The $8.3 million increase is attributable to $7.2 million of production costs associated with our acquisition of AGO on June 29, 2007, of which $2.0 million relates to production taxes. The remaning $1.1 million increase is a result in increases in transportation charges, labor and maintenance costs associated with an increase in the number of wells we own in Appalachia from the prior year period.
Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006
Our natural gas revenues were $102.4 million in the nine months ended September 30, 2007, an increase of $43.1 million (73%) from $59.3 million in the nine months ended September 30, 2006. The increase was attributable to an 11% decrease in the average sales price of natural gas partially offset by a 94% increase in production volumes. The 94% increase in our production volumes was 85% attributable to our Michigan operations which began on June 29, 2007 and 9% attributable to our Appalachian operations. The $43.1 million increase in natural gas revenues consisted of $49.6 million attributable to increases in production volumes and $6.5 million attributable to decreases in natural gas sales prices.
The increase in our gas production volumes of 61,481 Mcf/d resulted from our acquisition of AGO on June 29, 2007 and production associated with new wells drilled for our investment partnerships. We believe that gas volumes will continue to be favorably impacted in the remainder of 2007 with the contribution of our Michigan business unit and as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline are completed and wells drilled are connected in these areas of expansion.
Our oil revenues were $7.4 million in the nine months ended September 30, 2007, an increase of $34,000 (.5%) from $7.3 million during the nine months ended September 30, 2006. The increase resulted from a 1% decrease in the average sales price of oil and a 2% increase in production volumes. The $34,000 increase consisted of $95,000 attributable to decreases in sales prices and $129,000 attributable to volume increases.
Our production costs were $20.3 million in the nine months ended September 30, 2007, an increase of $9.8 million (93%) from $10.5 million in the nine months ended September 30, 2006. The $9.8 million increase is attributable to $7.4 million of production costs associated with our acquisition of AGO on June 29, 2007 and a $2.4 million increase in transportation charges, labor and maintenance costs associated with an increase in the number of wells we own in Appalachia from the prior year period. The transportation fees charged to our wells connected to Atlas Pipeline’s gathering system were generally increased as a percent of gas revenues beginning in January 2007.
PARTNERSHIP MANAGEMENT
Well Construction and Completion
Our 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 during the periods indicated (dollars in thousands):
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Average construction and completion revenue per well | $ | 361 | $ | 301 | $ | 322 | $ | 295 | |||||
Average construction and completion cost per well | 314 | 262 | 280 | 256 | |||||||||
Average construction and completion gross profit per well | $ | 47 | $ | 39 | $ | 42 | $ | 39 | |||||
Gross profit margin | $ | 13,477 | $ | 6,604 | $ | 31,414 | $ | 17,652 | |||||
Gross profit percent | 13 | % | 13 | % | 13 | % | 13 | % | |||||
Net wells drilled | 286 | 168 | 748 | 459 |
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Three Months Ended September 30, 2007 Compared to the Three Months Ended September 30, 2006
Our well construction and completion segment margin was $13.5 million in the three months ended September 30, 2007, an increase of $6.9 million (104%) from $6.6 million in the three months ended September 30, 2006. During the three months ended September 30, 2007, the increase of $6.9 million in segment margin was attributable to an increase in the number of wells drilled ($5.6 million) and an increase in the gross profit per well ($1.3 million). The increase in the number of wells drilled of 118 is the result of an increase in our fundraising in 2007. It should be noted that “Liabilities associated with drilling contracts” on our balance sheet includes $37.7 million of funds raised in the first nine months of calendar 2007 that have not been applied to the completion of wells as of September 30, 2007 due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue in the fourth quarter of fiscal 2007. During fiscal 2006 we raised $218.5 million and plan to raise approximately $340.0 million in fiscal 2007. We anticipate favorable oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the remainder of fiscal 2007.
Nine Months Ended September 30, 2007 Compared to the Nine Months Ended September 30, 2006
Our well construction and completion segment margin was $31.4 million in the nine months ended September 30, 2007, an increase of $13.7 million (78%) from $17.7 million in the nine months ended September 30, 2006. During the nine months ended September 30, 2007, the increase of $13.7 million in segment margin was attributable to an increase in the number of wells drilled ($12.1 million) and an increase in the gross profit per well ($1.6 million). The increase in the number of wells drilled of 289 is the result of an increase in our fundraising in fiscal 2007.
Administration and Oversight
Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships.
Our administration and oversight fees were $5.4 million in the three months ended September 30, 2007, an increase of $2.4 million (79%) from $3.0 million in the three months ended September 30, 2006. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in the three months ended September 30, 2007 as compared to the prior year period.
Our administration and oversight fees were $13.3 million in the nine months ended September 30, 2007, an increase of $4.8 million (57%) from $8.5 million in the nine months ended September 30, 2006. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in the nine months ended September 30, 2007 as compared to the prior year period.
Well Services
Our well services revenues were $4.8 million in the three months ended September 30, 2007, an increase of $1.5 million (45%) from $3.3 million in the three months ended September 30, 2006. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended September 30, 2007.
Our well services expenses were $2.5 million in the three months ended September 30, 2007, an increase of $763,000 (44%) from $1.8 million in the three months ended September 30, 2006. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.
Our well services revenues were $12.7 million in the nine months ended September 30, 2007, an increase of $3.2 million (34%) from $9.5 million in the nine months ended September 30, 2006. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended September 30, 2007.
Our well services expenses were $6.7 million in the nine months ended September 30, 2007, an increase of $1.2 million (21%) from $5.5 million in the nine months ended September 30, 2006. This increase was attributable to an increase in wages, benefits, fuel and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships
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Gathering
We charge transportation fees to our investment partnership wells that are connected to Atlas Pipeline’s Appalachian gathering systems. Prior to our initial public offering, our predecessor paid these fees, plus an additional amount to bring the total transportation charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with their gathering agreements with it. In connection with the completion of our initial public offering, Atlas America assumed our obligation to pay gathering fees to Atlas Pipeline. We are obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses within our partnership management segment net to $0. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production expense. During the three months and nine months ended September 30, 2007, we also received $135,000 in transportation and natural gas liquid revenues from our Michigan operations.
Our gathering fee paid to Atlas Pipeline was $3.3 million for the three months ended September 30, 2007, a decrease of $3.7 million (52%) from $7.0 million in the three months ended September 30, 2006. The decrease in the three months ended September 30, 2007 is primarily a result of the assumption by Atlas America of our obligation to pay Atlas Pipeline under our gas gathering agreement with it.
Our gathering fee to Atlas Pipeline was $10.4 million for the nine months ended September 30, 2007, a decrease of $12.5 million (55%) from $22.9 million in the nine months ended September 30, 2006. The decrease in the nine months ended September 30, 2007 is primarily a result of the assumption by Atlas America of our obligation to pay Atlas Pipeline under our gas gathering agreement with it
ALL OTHER INCOME, COSTS AND EXPENSES
Gain on Mark-to-Market Derivatives
Our gain on mark-to-market derivatives represents non-cash gains and losses recognized on derivatives. We recognized a $26.3 million non-cash gain related to the change in value of derivative contracts associated with the acquisition of AGO on June 29, 2007. The contracts entered into were derivative contracts to hedge the projected production volume of AGO before the closing of the acquisition. The production volumes of the assets to be acquired were not considered to be “probable forecasted production” under SFAS No. 133 at the date these derivatives were entered into because the acquisition of the assets had not yet been completed. Accordingly, we recorded the instruments as non-qualifying for hedge accounting at inception with subsequent changes in the derivative values recorded within our consolidated statements of income. Upon closing of the acquisition, the production volumes of the assets acquired was considered “probable forecasted production” under SFAS No. 133 and we evaluated these derivatives under the cash flow hedge criteria in accordance with SFAS No. 133.
For the three months and nine months ended September 30, 2007, we realized $9.3 million on production volumes settled related to $6.5 million in non-cash hedge gains, for a net gain shown in gas revenues of $2.8 million.
General and Administrative
Our general and administrative expenses were $9.1 million in the three months ended September 30, 2007, an increase of $1.4 million (17%) from $7.7 million in the three months ended September 30, 2006. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate office, partnership syndication activities and outside services. The increase of $1.4 million in the three months ended September 30, 2007 is principally attributed to the following:
· | Salaries and wages increased $2.8 million due to an increase of $1.3 million related to our long-term incentive plan and $1.5 million related to an increase in the number of employees to manage our business operations, including $1.1 million from our Michigan operations. |
· | Land and geology costs decreased $1.4 million due to reimbursements of costs from our partnership syndication activities related to our land and geology department during the three months ended September 30, 2006. |
Our general and administrative expenses were $27.3 million in the nine months ended September 30, 2007, an increase of $8.9 million (49%) from $18.4 million in the nine months ended September 30, 2006. These expenses include, among other things, salaries and benefits not allocated to a specific segment, costs of running our corporate office, partnership syndication activities and outside services. The increase of $8.9 million in the nine months ended September 30, 2007 is principally attributed to the following:
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· | Professional fees including audit, tax preparation, insurance and consulting fees increased $2.3 million; and |
· | Salaries and wages increased $6.1 million due to an increase of $3.1 million related to our long-term incentive plan and an increase of $3.0 million in employee costs ($1.1 million related to our Michigan operations) as we continue to increase the number of employees to manage our business operations. |
Depletion
Our depletion of oil and gas properties as a percentage of oil and gas revenues was 29% in the three months ended September 30, 2007, compared to 26% in the three months ended September 30, 2006. Depletion expense per Mcfe was $2.19 in the three months ended September 30, 2007, an increase of $.05 (2%) per Mcfe from $2.14 in the three months ended September 30, 2006. Increases in our depletable basis and production volumes caused depletion expense to increase $12.8 million (228%) to $18.4 million in the three months ended September 30, 2007 compared to $5.6 million in the three months ended September 30, 2006. The variances from period to period are directly attributable to 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 of oil and gas properties as a percentage of oil and gas revenues was 27% in the nine months ended September 30, 2007, compared to 22% in the nine months ended September 30, 2006. Depletion expense per Mcfe was $2.24 in the nine months ended September 30, 2007, an increase of $.20 (9%) per Mcfe from $2.04 in the nine months ended September 30, 2006. Increases in our depletable basis and production volumes caused depletion expense to increase $15.2 million (103%) to $30.0 million in the nine months ended September 30, 2007 compared to $14.8 million in the nine months ended September 30, 2006.
Liquidity and Capital Resources
General. We fund our operations with a combination of cash generated by operations, capital raised through investment partnerships, issuance of our units and use of our credit facility.
On June 29, 2007, we entered into a new $850.0 million revolving credit facility administered by J.P. Morgan, which replaced our previous $250.0 million credit facility administered by Wachovia Bank, N.A. For more information on the terms of our credit facility, please read Item 2: “Management’s Discussion and Analysis of Financial Condition and Results of Operations – RECENT EVENTS – New Credit Facility.”
We had $8.3 million in cash and cash equivalents at September 30, 2007, as compared to $8.8 million at December 31, 2006. We had a working capital deficit of $48.0 million at September 30, 2007, an increase in working capital of $40.0 million from a working capital deficit of $88.0 million at December 31, 2006. The increase in our working capital is due to an increase of $23.5 million in accounts receivable, due primarily to the AGO acquisition, and an increase of $12.8 million in our current portion of our hedge asset. At September 30, 2007, we have $109.9 million available under our credit facility to fund working capital obligations.
Cash flows from operating activities. Cash provided by operations is an important source of short-term liquidity for us. It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to raise funds from our drilling investment partnerships. Net cash provided by operating activities increased $10.8 million in the nine months ended September 30, 2007 to $100.5 million from $89.7 million in the nine months ended September 30, 2006, substantially as a result of the following:
• | an increase in net income before depreciation and amortization of $72.9 million in the nine months ended September 30, 2007 as compared to the prior year period, principally as a result of income from well construction and completion profits and administration and oversight and well services margins; | ||
• | a decrease in the adjustment to add back non-cash items of $17.6 related to our compensation expense resulting from grants under long-term incentive plans and non-cash gains of derivatives; | ||
• | we received $2.2 million in advances from AAI during the nine months ended September 30, 2007 as compared to $32.1 received during the nine months ended September 30, 2006, which decreased operating cash flows by $29.9 million; and | ||
• | changes in operating assets and liabilities decreased operating cash flow by $14.7 million in the nine months ended September 30, 2007, compared to the nine months ended September 30, 2006. |
The change in operating assets and liabilities is primarily a result of the following:
• | An increase of $10.0 million in accounts receivable and prepaid expenses; |
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• | An increase of $574,000 in accounts payable and accrued expenses; | ||
• | An increase of $4.7 million in other operating assets and liabilities; partially offset by, | ||
• | An increase of $30.0 million in liabilities associated with our drilling contracts. Our level of liabilities associated with drilling contracts is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our investment partnerships. |
Cash flows used in investing activities. Cash used in our investing activities increased $1.339 billion in the nine months ended September 30, 2007 to $1.392 billion from $53.9 million in the nine months ended September 30, 2006 primarily from our $1.268 billion acquisition of AGO and a $71.4 million increase in capital expenditures related to the increase in the number of wells we drilled.
Cash flows from financing activities. Cash provided by our financing activities increased $1.291 billion in the nine months ended September 30, 2007 to $1.291 billion from cash used of $65,000 in the nine months ended September 30, 2006, as a result of the following:
• | to fund the acquisition of AGO on June 29, 2007, we borrowed $713.9 million on our credit facility; | ||
• | we borrowed additional funds on our credit facility, net of repayments of $25.2 million; | ||
• | we received proceeds of $597.5 million from the issuance of Class B common and Class D units; | ||
• | we paid $10.2 million in debt issue costs; and | ||
• | we paid $34.9 million in distributions to our unit holders in the nine months ended September 30, 2007. |
Capital Requirements: During the nine months ended September 30, 2007, our capital expenditures consisted of maintenance capital expenditures and expansion capital expenditures, as defined below:
• | maintenance capital expenditures are those capital expenditures we made on an ongoing basis to maintain our capital asset base and our current production volumes at a steady level; and | ||
• | expansion capital expenditures are those capital expenditures we made 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 our investments in our drilling partnerships. |
The level of capital expenditures we devote to our land and production operations depends upon acquisitions made and the level of funds raised through our investment partnerships. We have budgeted to raise up to $340 million ($199.4 million raised as of September 30, 2007) in fiscal 2007. We believe cash flows from operations and amounts available under our credit facility will be adequate to fund all 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 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.
The following table summarizes maintenance and expansion capital expenditures for the periods indicated (in thousands):
Three Months Ended | Nine Months Ended | ||||||||||||
September 30, | September 30, | ||||||||||||
2007 | 2006 | 2007 | 2006 | ||||||||||
Maintenance capital expenditures | $ | 12,975 | $ | — | $ | 30,475 | $ | — | |||||
Expansion capital expenditures | 59,555 | — | 1,364,792 | — | |||||||||
Total | $ | 72,530 | $ | 16,790(1 | ) | $ | 1,395,267 | $ | 54,076(1 | ) |
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(1) | We did not characterize capital expenditures as maintenance or expansion and did not plan capital expenditures in a manner intended to maintain or expand our asset base or production before our initial public offering on December 18, 2006. Cash distributions. Our limited liability company agreement requires that we distribute 100% of available cash to our unit holders within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all of our cash receipts, less cash disbursements and net additions to reserves, plus cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. All cash we distribute to unit holders will be characterized as either operating surplus or capital surplus, as defined in our limited liability company agreement and is subject to different distribution rules. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We do not anticipate distributing any cash from capital surplus. Available cash is initially distributed 98% to our Class B common and Class D unit holders and 2% to AEM. These distribution percentages are modified to provide for incentive distributions (any distribution paid to AEM in excess of 2% of the aggregate amount of cash being distributed) to be paid to AEM if quarterly distributions to the Class B common and Class D unit holders exceed specified targets as defined in our limited liability company agreement. |
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual obligations at September 30, 2007.
Payments Due By Period | ||||||||||||||||
(in thousands) | ||||||||||||||||
Less than | 2 – 3 | 4 – 5 | After 5 | |||||||||||||
Contractual cash obligations: | Total | 1 Year | Years | Years | Years | |||||||||||
Long-term debt(1) | $ | 739,082 | $ | 42 | $ | 28 | $ | 739,012 | $ | — | ||||||
Secured revolving credit facilities | — | — | — | — | — | |||||||||||
Operating lease obligations | 7,238 | 1,414 | 2,230 | 1,217 | 2,377 | |||||||||||
Capital lease obligations | — | — | — | — | — | |||||||||||
Unconditional purchase obligations | — | — | — | — | — | |||||||||||
Other long-term obligation | — | — | — | — | — | |||||||||||
Total contractual cash obligations | $ | 746,320 | $ | 1,456 | $ | 2,258 | $ | 740,229 | $ | 2,377 |
(1) | Not included in the table above are estimated interest payments calculated at the rates in effect at September 30, 2007 of: 2008 - $55.1 million; 2009 - $55.1 million; 2010 - $55.1 million; 2011 - $55.1 million and 2012 - $41.1 million. |
Payments Due By Period | ||||||||||||||||
(in thousands) | ||||||||||||||||
Less than | 1 - 3 | 4 - 5 | After 5 | |||||||||||||
Other commercial commitments: | Total | 1 Year | Years | Years | Years | |||||||||||
Standby letters of credit | $ | 1,109 | $ | 1,109 | $ | — | $ | — | $ | — | ||||||
Guarantees | — | — | — | — | — | |||||||||||
Standby replacement commitments | — | — | — | — | — | |||||||||||
Other commercial commitments | 1,741 | 1,741 | — | — | — | |||||||||||
Total commercial commitments | $ | 2,850 | $ | 2,850 | $ | — | $ | — | $ | — |
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues, costs and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to the provision for possible losses, deferred tax assets and liabilities, goodwill and identifiable intangible assets, and certain accrued liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
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For a detailed discussion on the application of policies critical to our business operations and other accounting policies, see our Annual Report on Form 10-K for the year ended December 31, 2006, Note 2 of the "Notes to Combined and Consolidated Financial Statements" and Note 2 to the “Notes to Combined and Consolidated Financial Statements” included in this report.
Recently Issued Financial Accounting Standards
In April 2007, the Financial Accounting Standards Board, or FASB issued FASB Interpretation No. 39-1, amendment of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts”, (“FIN 39-1”). FIN 39-1 amends FIN 39, which allows an entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FIN 39-1 is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of FIN 39-1 to have a significant impact on our financial position or results of operations.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, or SFAS 159. SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The statement offers various options in electing to apply its provisions, and at this time we have not made any decisions on its application and are evaluating the impact of the adoption of SFAS 159 on our financial position and results of operations.
In December 2006, the FASB issued FASB Staff Position (FSP) EITF 00-19-2, “Accounting for Registration Payment Arrangements.” FSP EITF 00-19-2 requires an issuer of financial instruments, such as debt, convertible debt, equity shares or warrants, to account for a contingent obligation to transfer consideration under a registration payment arrangement in accordance with Statement 5, Accounting for Contingencies, and FASB Interpretation 14, Reasonable Estimation of the Amount of a Loss. That accounting applies regardless of whether the registration payment arrangement is a provision in a financial instrument or a separate agreement. The FSP requires issuers to make certain disclosures for each registration payment arrangement or group of similar arrangements. The FSP is effective immediately for registration payment arrangements and financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006, the date FSP EITF 00-19-2 was issued. We applied the consensus in FSP EITF 00-19-2 effective January 1, 2007. We reviewed the penalty terms in the registration rights agreement related to our private placement entered into on June 29, 2007 (See Note 15), pursuant to the guidance in the FSP, and determined that the probability of payment is remote under Statement 5 based upon our status of current related filings. As a result, the application of FSP EITF 00-19-2 did not have an effect on our financial position or results of operations.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”, or SFAS 157. SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for us beginning January 1, 2008. We are currently evaluating the impact of the adoption of SFAS 157 on our financial position and results of operations.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The following discussion is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.
General
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 periodically use derivative financial instruments such as forward contracts and interest rate cap and swap agreements.
The following analysis presents the effect on our earnings, cash flows and financial position as if hypothetical changes in market risk factors occurred on September 30, 2007. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.
Interest Rate Risk. At September 30, 2007, we have an $850 million revolving credit facility of which $740.1 million was outstanding (including $1.1 million in letters of credit). The weighted average interest rate for borrowings under this credit facility was 7.5% at September 30, 2007. Holding all other variables constant, a hypothetical 10% change in the weighted average interest rate would change our net income by approximately $5.5 million.
Commodity Price Risk. Our major market risk exposure to commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for 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 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.
Our risk management objective is to lock in a range of pricing for expected production volumes. Considering those volumes for which we have entered into financial hedge agreements for the twelve months ending September 30, 2008, and current indices, a theoretical 10% upward or downward change in the price of natural gas would result in a change in net income of approximately $3.8 million.
We formally document all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas 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 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. Changes in fair value are recognized in combined equity and recognized within the combined statements of income 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.
As of September 30, 2007, we had financial hedges in place for approximately 84% of our expected production volumes for the twelve months ending September 30, 2008. At September 30, 2007, we had 384 open natural gas futures contracts related to natural gas sales covering 147.5 million MMBtus of natural gas, (which includes 76.9 million MMBtu covering natural gas production assets acquired from AGO), maturing through December 31, 2012 at an average settlement price of $8.04 per MMBtu. We recognized gains of $4.9 million and $2.0 million, for the three months ended September 30, 2007 and 2006 and $9.6 million and $4.9 million on settled contracts covering natural gas production for the nine months ended September 30, 2007 and 2006, respectively. In addition, we recognized a gain of $26.3 million shown as “Gain on mark-to-market derivative” in our Combined and Consolidated Statements of Income for the nine months ended September 30, 2007 related to hedge ineffectiveness as a result of the increase in fair market value of natural gas volumes hedged from May 22, 2007 to June 28 2007 associated with the acquisition of AGO on June 29, 2007. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its natural gas, there were no gains or losses recognized during the three months and nine months ended September 30, 2007 and 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. Of the $50.4 million and $47.5 million net unrealized hedge asset at September 30, 2007 and December 31, 2006, respectively, our portion is $44.6 million (of which $19.8 million has been recognized as ineffective hedging gains). Unrealized hedge gains of $5.8 million and $26.4 million has been allocated to our investment partnerships as of September 30, 2007 and December 31, 2006.
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Of the $24.9 million net gain in accumulated other comprehensive income at September 30, 2007, we will reclassify $16.6 million of gains to our consolidated statements of income over the next twelve month period as these contracts expire and $8.3 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.
As of September 30, 2007, we had the following natural gas volumes hedged:
Fixed Price Swaps
Twelve Month | Average | Fair Value | |||||||||||
Period Ending | Volumes | Fixed Price | Asset (Liability) | ||||||||||
September 30, | (MMBtu) | (per MMBtu) | (in thousands) (1) | ||||||||||
2008 | 35,470,000 | $ | 8.15 | $ | 37,289 | ||||||||
2009 | 33,530,000 | 8.32 | 11,310 | ||||||||||
2010 | 25,430,000 | 8.02 | 517 | ||||||||||
2011 | 18,950,000 | 7.75 | (790 | ) | |||||||||
2012 | 11,150,000 | 7.62 | 821 | ||||||||||
2013 | 2,250,000 | 7.67 | 346 | ||||||||||
$ | 49,493 |
Costless Collars
Twelve Month | Average | Fair Value | |||||||||||
Period Ending | Volumes | Floor and Cap | Asset (Liability) | ||||||||||
September 30, | Option Type | (MMBtu) | (per MMBtu) | (in thousands) (1) | |||||||||
2008 | Puts purchased | 450,000 | $ | 7.50 | $ | 314 | |||||||
2008 | Calls sold | 450,000 | 8.60 | — | |||||||||
2008 | Puts purchased | 1,170,000 | 7.50 | 325 | |||||||||
2008 | Calls sold | 1,170,000 | 9.40 | — | |||||||||
2009 | Puts purchased | 390,000 | 7.50 | — | |||||||||
2009 | Calls sold | 390,000 | 9.40 | (32 | ) | ||||||||
2010 | Puts purchased | 2,160,000 | 7.75 | 144 | |||||||||
2010 | Calls sold | 2,160,000 | 8.75 | — | |||||||||
2011 | Puts purchased | 720,000 | 7.75 | (4 | ) | ||||||||
2011 | Calls sold | 720,000 | 8.75 | — | |||||||||
2011 | Puts purchased | 5,400,000 | 7.50 | 240 | |||||||||
2011 | Calls sold | 5,400,000 | 8.45 | — | |||||||||
2012 | Puts purchased | 1,800,000 | 7.50 | — | |||||||||
2012 | Calls sold | 1,800,000 | 8.45 | (25 | ) | ||||||||
2012 | Puts purchased | 6,480,000 | 7.50 | — | |||||||||
2012 | Calls sold | 6,480,000 | 8.45 | (24 | ) | ||||||||
2013 | Puts purchased | 2,160,000 | 7.00 | — | |||||||||
2013 | Calls sold | 2,160,000 | 8.37 | (19 | ) | ||||||||
$ | 919 | ||||||||||||
Total net asset | $ | 50,412 |
(1) | Fair value based on forward NYMEX natural gas prices. |
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ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in Securities and Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and our 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, 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 our disclosure controls and procedures are effective at the reasonable assurance level.
There have been no significant changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially effect, our internal control over financial reporting during our most recent quarter.
There were no changes during the Company’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibit No. | Description |
3.1 | Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC (1) |
3.2 | Amendment No. 1 to Amended and Restated Operating Agreement of Atlas Energy Resources, LLC (1) |
3.3 | Certificate of Formation of Atlas Energy Resources, LLC (2) |
31.1 | Rule 13(a)-14(a)/15d-14(a) Certification. |
31.2 | Rule 13(a)-14(a)/15d-14(a) Certification. |
32.1 | Section 1350 Certification. |
32.2 | Section 1350 Certification. |
(1) | Previously filed as an exhibit to our Form 8-K filed June 29, 2007. | |
(2) | Previously filed as an exhibit to our registration statement on Form S-1 (Reg. No. 333-136094). |
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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.
ATLAS ENERGY RESOURCES, LLC | ||
(Registrant) | ||
Date: November 6, 2007 | By: | /s/ Matthew A. Jones |
Matthew A. Jones | ||
Chief Financial Officer | ||
Date: November 6, 2007 | By: | /s/Nancy J. McGurk |
Nancy J. McGurk Senior Vice President and Chief Accounting Officer |
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