Exhibit 99.1
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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F-1
Report of Independent Registered Public Accounting Firm
Legacy Reserves LP
Midland, Texas
Midland, Texas
We have audited the accompanying consolidated balance sheets of Legacy Reserves LP (formerly the Moriah Group, as defined in Note 1 (a)), as of December 31, 2006 and 2007 and the related consolidated statements of operations, unitholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Legacy Reserves LP at December 31, 2006 and 2007 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
/s/BDO SEIDMAN, LLP
Houston, Texas
March 13, 2008, except for Note 18
which is as of April 3, 2008
March 13, 2008, except for Note 18
which is as of April 3, 2008
F-2
LEGACY RESERVES LP
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2006 AND 2007
(dollars in thousands)
(dollars in thousands)
| 2006 | 2007 | |||||||
ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 1,062 | $ | 9,604 | ||||
| Accounts receivable, net: | ||||||||
| Oil and natural gas | 7,600 | 19,025 | ||||||
| Joint interest owners | 4,345 | 4,253 | ||||||
| Affiliated entities and other (Notes 3 and 6) | 21 | 26 | ||||||
| Fair value of derivatives (Note 9) | 5,102 | 310 | ||||||
| Prepaid expenses and other current assets | 91 | 340 | ||||||
| Total current assets | 18,221 | 33,558 | ||||||
| Oil and natural gas properties, at cost: | ||||||||
| Proved oil and natural gas properties, at cost, using the successful efforts method of accounting (Note 14): | 289,519 | 512,396 | ||||||
| Unproved properties | 68 | 78 | ||||||
| Accumulated depletion, depreciation and amortization | (42,007 | ) | (72,294 | ) | ||||
| 247,580 | 440,180 | |||||||
| Other property and equipment, net of accumulated depreciation and amortization of $51 and $251, respectively | 304 | 775 | ||||||
| Operating rights, net of amortization of $295 and $865, respectively (Note 1(k)) | 6,721 | 6,151 | ||||||
| Other assets, net of amortization of $167 and $391, respectively | 542 | 822 | ||||||
| Investment in equity method investee (Note 5) | — | 92 | ||||||
| $ | 273,368 | $ | 481,578 | |||||
See accompanying notes to consolidated financial statements.
F-3
LEGACY RESERVES LP
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2006 AND 2007
(dollars in thousands)
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2006 AND 2007
(dollars in thousands)
| 2006 | 2007 | |||||||
LIABILITIES AND UNITHOLDERS’ EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 2,932 | $ | 2,320 | ||||
| Accrued oil and natural gas liabilities | 5,882 | 10,102 | ||||||
| Fair value of derivatives (Note 9) | — | 26,761 | ||||||
| Asset retirement obligation (Note 11) | 553 | 845 | ||||||
| Other (Note 13) | 1,467 | 3,429 | ||||||
| Total current liabilities | 10,834 | 43,457 | ||||||
| Long-term debt (Note 3) | 115,800 | 110,000 | ||||||
| Asset retirement obligation (Note 11) | 5,939 | 15,075 | ||||||
| Fair value of derivatives (Note 9) | 2,006 | 57,316 | ||||||
| Total liabilities | 134,579 | 225,848 | ||||||
| Commitments and contingencies (Note 7) | ||||||||
| Unitholders’ equity: | ||||||||
| Limited partners’ equity - 18,395,233 and 29,670,887 units issued and outstanding at December 31, 2006 and 2007, respectively | 138,653 | 255,663 | ||||||
| General partner’s equity (approximately 0.1%) | 136 | 67 | ||||||
| Total unitholders’ equity | 138,789 | 255,730 | ||||||
| Total liabilities and unitholders’ equity | $ | 273,368 | $ | 481,578 | ||||
See accompanying notes to consolidated financial statements.
F-4
LEGACY RESERVES LP
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2006 AND 2007
(dollars in thousands, except per unit data)
(dollars in thousands, except per unit data)
| 2005 | 2006 | 2007 | ||||||||||
| Revenues: | ||||||||||||
| Oil sales | $ | 18,225 | $ | 45,351 | $ | 83,301 | ||||||
| Natural gas liquid sales | — | — | 7,502 | |||||||||
| Natural gas sales | 7,318 | 14,446 | 21,433 | |||||||||
| Total revenues | 25,543 | 59,797 | 112,236 | |||||||||
| Expenses: | ||||||||||||
| Oil and natural gas production | 6,376 | 15,938 | 27,129 | |||||||||
| Production and other taxes | 1,636 | 3,746 | 7,889 | |||||||||
| General and administrative | 1,354 | 3,691 | 8,392 | |||||||||
| Depletion, depreciation, amortization and accretion | 2,291 | 18,395 | 28,415 | |||||||||
| Impairment of long-lived assets | — | 16,113 | 3,204 | |||||||||
| Loss on disposal of assets | 20 | 42 | 527 | |||||||||
| Total expenses | 11,677 | 57,925 | 75,556 | |||||||||
| Operating income | 13,866 | 1,872 | 36,680 | |||||||||
| Other income (expense): | ||||||||||||
| Interest income | 185 | 130 | 321 | |||||||||
| Interest expense (Notes 3 and 9) | (1,584 | ) | (6,645 | ) | (7,118 | ) | ||||||
| Equity in income (loss) of partnerships (Note 5) | (495 | ) | (318 | ) | 77 | |||||||
| Realized gain (loss) on oil, NGL and natural gas swaps (Note 9) | (3,531 | ) | (262 | ) | 211 | |||||||
| Unrealized gain (loss) on oil, NGL and natural gas swaps (Note 9) | (2,628 | ) | 9,551 | (85,367 | ) | |||||||
| Other | 45 | 29 | (129 | ) | ||||||||
| Income (loss) before non-controlling interest and income taxes | 5,858 | 4,357 | (55,325 | ) | ||||||||
| Non-controlling interest | 1 | — | — | |||||||||
| Income (loss) before income taxes | 5,859 | 4,357 | (55,325 | ) | ||||||||
| Income taxes | — | — | (337 | ) | ||||||||
| Net income (loss) | $ | 5,859 | $ | 4,357 | $ | (55,662 | ) | |||||
| Net income (loss) per unit — basic and diluted (Note 12) | $ | 0.62 | $ | 0.26 | $ | (2.13 | ) | |||||
| Weighted average number of units used in computing net income (loss) per unit - | ||||||||||||
| basic | 9,488,921 | 16,567,287 | 26,155,439 | |||||||||
| diluted | 9,488,921 | 16,568,879 | 26,155,439 | |||||||||
See accompanying notes to consolidated financial statements.
F-5
LEGACY RESERVES LP
CONSOLIDATED STATEMENT OF UNITHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2005, 2006 AND 2007
(dollars in thousands)
(dollars in thousands)
| Total | ||||||||||||||||
| Number of | Limited | General | Unitholders' | |||||||||||||
| Limited Partner Units | Partner | Partner | Equity | |||||||||||||
| Balance December 31, 2004 | 9,488,921 | $ | 12,010 | $ | 12 | $ | 12,022 | |||||||||
| Capital contributions | — | 144 | — | 144 | ||||||||||||
| Deemed capital distribution | — | 155 | — | 155 | ||||||||||||
| Distributions to partners | — | (8,263 | ) | (8 | ) | (8,271 | ) | |||||||||
| Net income | — | 5,853 | 6 | 5,859 | ||||||||||||
| Balance December 31, 2005 | 9,488,921 | 9,899 | 10 | 9,909 | ||||||||||||
| Capital contributions | — | 19 | — | 19 | ||||||||||||
| Net distributions to owners | — | (2,295 | ) | (2 | ) | (2,297 | ) | |||||||||
| Deemed dividend to Moriah Group owners | — | (3,874 | ) | (4 | ) | (3,878 | ) | |||||||||
| Net proceeds from private equity offering | 5,000,000 | 76,707 | 77 | 76,784 | ||||||||||||
| Redemption of Founding Investors’ units | (4,400,000 | ) | (69,868 | ) | (70 | ) | (69,938 | ) | ||||||||
| Units issued to MBN Properties LP in exchange for the non-controlling interests’ share of oil and natural gas properties | 1,867,290 | 31,712 | 32 | 31,744 | ||||||||||||
| Units issued to the Brothers Group in exchange for oil and natural gas properties and other assets | 6,200,358 | 105,301 | 105 | 105,406 | ||||||||||||
| Units issued to H2K Holdings Ltd in exchange for oil and natural gas properties | 83,499 | 1,418 | 1 | 1,419 | ||||||||||||
| Dividend — reimbursement of offering costs paid by MBN Management LLC | — | (1,199 | ) | (1 | ) | (1,200 | ) | |||||||||
| Units issued to Henry Holding LP in exchange for oil and natural gas properties | 146,415 | 2,489 | — | 2,489 | ||||||||||||
| Units issued to Legacy Board of Directors for services | 8,750 | 149 | — | 149 | ||||||||||||
| Compensation expense on unit options granted to employees | — | 115 | — | 115 | ||||||||||||
| Compensation expense on restricted unit awards issued to employees | — | 270 | — | 270 | ||||||||||||
| Distributions to unitholders, $0.8974 per unit | — | (16,542 | ) | (16 | ) | (16,558 | ) | |||||||||
| Net income | — | 4,352 | 4 | 4,356 | ||||||||||||
| Balance, December 31, 2006 | 18,395,233 | 138,653 | 136 | 138,789 | ||||||||||||
| Net proceeds from initial public equity offering | 6,900,000 | 121,554 | — | 121,554 | ||||||||||||
| Net proceeds from private placement equity offering | 3,642,369 | 73,073 | — | 73,073 | ||||||||||||
| Units issued to Legacy Board of Directors for services | 7,000 | 149 | — | 149 | ||||||||||||
| Compensation expense on restricted unit awards issued to employees | — | 341 | — | 341 | ||||||||||||
| Vesting of Restricted Units | 20,038 | — | — | — | ||||||||||||
| Units issued to Greg McCabe in exchange for oil and natural gas properties | 95,000 | 2,271 | — | 2,271 | ||||||||||||
| Units issued to Nielson & Associates, Inc. in exchange for oil and natural gas properties | 611,247 | 15,752 | — | 15,752 | ||||||||||||
| Reclass prior period compensation cost on unit options granted to employees to adjust for conversion to liability method as described in FAS 123-R | — | (115 | ) | — | (115 | ) | ||||||||||
| Distributions to unitholders, $1.67 per unit | — | (40,388 | ) | (34 | ) | (40,422 | ) | |||||||||
| Net loss | — | (55,627 | ) | (35 | ) | (55,662 | ) | |||||||||
| Balance, December 31, 2007 | 29,670,887 | $ | 255,663 | $ | 67 | $ | 255,730 | |||||||||
See accompanying notes to consolidated financial statements.
F-6
LEGACY RESERVES LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2005, 2006 AND 2007
(dollars in thousands)
(dollars in thousands)
| 2005 | 2006 | 2007 | ||||||||||
| Cash flows from operating activities: | ||||||||||||
| Net income (loss) | $ | 5,859 | $ | 4,357 | $ | (55,662 | ) | |||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
| Depletion, depreciation, amortization and accretion | 2,291 | 18,395 | 28,415 | |||||||||
| Amortization of debt issuance costs | 94 | 361 | �� | 224 | ||||||||
| Impairment of long-lived assets | — | 16,113 | 3,204 | |||||||||
| (Gain) loss on derivatives | 6,159 | (9,289 | ) | 86,652 | ||||||||
| Equity in (income) loss of partnership | 495 | 318 | (77 | ) | ||||||||
| Accrued interest on subordinated notes payable — partners | 818 | — | — | |||||||||
| Accrued interest on subordinated notes receivable — partners | (25 | ) | — | — | ||||||||
| Amortization of unit-based compensation | — | 534 | 166 | |||||||||
| Non-controlling interest | (1 | ) | — | — | ||||||||
| Loss on disposal of assets | 21 | 42 | 527 | |||||||||
| Changes in assets and liabilities: | — | — | ||||||||||
| Increase in accounts receivable, oil and natural gas | (3,412 | ) | (5,796 | ) | (11,425 | ) | ||||||
| (Increase) decrease in accounts receivable, joint interest owners | 605 | (4,481 | ) | 92 | ||||||||
| Increase in accounts receivable, other | (91 | ) | (458 | ) | (5 | ) | ||||||
| Increase in prepaid expenses and other current assets | (88 | ) | (565 | ) | (250 | ) | ||||||
| Increase (decrease) in accounts payable | 395 | 2,694 | (611 | ) | ||||||||
| Increase in accrued oil and natural gas liabilities | 1,107 | 4,227 | 4,221 | |||||||||
| Increase in due to affiliates | 195 | 1,059 | — | |||||||||
| Increase (decrease) in other current liabilities | (13 | ) | 2,079 | 1,676 | ||||||||
| Total adjustments | 8,550 | 25,233 | 112,809 | |||||||||
| Net cash provided by operating activities | 14,409 | 29,590 | 57,147 | |||||||||
| Cash flows from investing activities: | ||||||||||||
| Investment in oil and natural gas properties | (66,910 | ) | (55,907 | ) | (196,031 | ) | ||||||
| Investment in other equipment | (4 | ) | (243 | ) | (671 | ) | ||||||
| Investment in operating rights | — | (7,017 | ) | — | ||||||||
| Investment in notes receivable | (900 | ) | — | — | ||||||||
| Collection of notes receivable | 2,380 | 924 | — | |||||||||
| Net cash settlements on oil and natural gas swaps | (3,531 | ) | (262 | ) | 211 | |||||||
| Investment in equity method investee | — | — | (14 | ) | ||||||||
| Net cash used in investing activities | (68,965 | ) | (62,505 | ) | (196,505 | ) | ||||||
| Cash flows from financing activities: | ||||||||||||
| Proceeds from long-term debt | 56,573 | 121,800 | 183,000 | |||||||||
| Payments of long-term debt | (6,100 | ) | (73,190 | ) | (188,800 | ) | ||||||
| Payments of debt issuance costs | (868 | ) | (293 | ) | (505 | ) | ||||||
| Proceeds from subordinated notes payable — partners | 14,264 | — | — | |||||||||
| Proceeds from issuance of units, net | — | 76,784 | 194,627 | |||||||||
| Redemption of Founding Investors’ units | — | (69,938 | ) | — | ||||||||
| Dividend — reimbursement of offering costs paid by MBN Management LLC | — | (1,200 | ) | — | ||||||||
| Capital contributed by owner | 144 | 19 | — | |||||||||
| Cash not acquired in Legacy formation transactions | — | (3,104 | ) | — | ||||||||
| Distributions to unitholders | (8,271 | ) | (18,856 | ) | (40,422 | ) | ||||||
| Net cash provided by financing activities | 55,742 | 32,022 | 147,900 | |||||||||
| Net increase(decrease)in cash and cash equivalents | 1,186 | (893 | ) | 8,542 | ||||||||
| Cash and cash equivalents, beginning of period | 769 | 1,955 | 1,062 | |||||||||
| Cash and cash equivalents, end of period | $ | 1,955 | $ | 1,062 | $ | 9,604 | ||||||
See accompanying notes to consolidated financial statements.
F-7
LEGACY RESERVES LP
CONSOLIDATED STATEMENTS OF CASH FLOWS — Continued
FOR THE YEARS ENDED DECEMBER 31, 2005, 2006 AND 2007
(dollars in thousands)
CONSOLIDATED STATEMENTS OF CASH FLOWS — Continued
FOR THE YEARS ENDED DECEMBER 31, 2005, 2006 AND 2007
(dollars in thousands)
| 2005 | 2006 | 2007 | ||||||||||
| Non—Cash Investing and Financing Activities: | ||||||||||||
| Asset retirement obligation costs and liabilities | $ | 12 | $ | 2,273 | $ | 6,296 | ||||||
| Asset retirement obligations associated with property acquisitions | $ | 445 | $ | 1,889 | $ | 3,034 | ||||||
| Contributed offering costs | $ | 155 | $ | — | $ | — | ||||||
| Non-controlling interests’ share of net financing costs of MBN Properties LP capitalized to oil and natural gas properties | $ | — | $ | 164 | $ | — | ||||||
| Units issued to MBN Properties LP in exchange for the non-controlling interests’ share of oil and natural gas properties | $ | — | $ | 31,744 | $ | — | ||||||
| Units issued to Brothers Group in exchange for: | ||||||||||||
| Oil and natural gas properties | $ | — | $ | 105,299 | $ | — | ||||||
| Other property and equipment | $ | — | $ | 107 | $ | — | ||||||
| Units issued to H2K Holdings Ltd. in exchange for oil and natural gas properties | $ | — | $ | 1,419 | $ | — | ||||||
| Oil and natural gas hedge liabilities assumed from the Brothers Group and H2K Holdings Ltd. | $ | — | $ | 3,147 | $ | — | ||||||
| Units issued in exchange for oil and natural gas properties | $ | — | $ | 2,489 | $ | 18,023 | ||||||
| Deemed dividend to Moriah Group owners for accounts not acquired in Legacy formation transaction: | ||||||||||||
| Accounts receivable, oil and natural gas | $ | — | $ | 4,248 | $ | — | ||||||
| Accounts receivable, joint interest owners | $ | — | $ | 250 | $ | — | ||||||
| Accounts receivable, other | $ | — | $ | 540 | $ | — | ||||||
| Other assets | $ | — | $ | 891 | $ | — | ||||||
| Accounts payable | $ | — | $ | (214 | ) | $ | — | |||||
| Accrued oil and natural gas liabilities | $ | — | $ | (1,521 | ) | $ | — | |||||
| Due to affiliates | $ | — | $ | (1,254 | ) | $ | — | |||||
| Other liabilities | $ | — | $ | (2,166 | ) | $ | — | |||||
See accompanying notes to consolidated financial statements.
F-8
LEGACY RESERVES LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
(a) Organization, Basis of Presentation and Description of Business
On March 15, 2006, Legacy Reserves LP (“LRLP,” “Legacy” or the “Partnership”), as the successor entity to the Moriah Group (defined below), completed a private equity offering in which it (1) issued 5,000,000 limited partnership units at a gross price of $17.00 per unit, netting $76.8 million after initial purchaser’s discount, placement agent’s fee and expenses, (2) acquired certain oil and natural gas properties (Note 4) and (3) redeemed 4.4 million units for $69.9 million from certain of its Founding Investors. The Moriah Group has been treated as the acquiring entity in this transaction, hereinafter referred to as the “Legacy Formation.” Because the combination of the businesses that comprised the Moriah Group was a reorganization of entities under common control, the combination of these businesses has been reflected retroactively at carryover basis in these consolidated financial statements. The accounts presented for periods prior to the Legacy Formation transaction are those of the Moriah Group.
LRLP and its affiliated entities are referred to as Legacy in these financial statements.
LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and it owns an approximately 0.1% general partner interest in LRLP.
Significant information regarding rights of the limited partners includes the following:
| • | Right to receive distributions of available cash within 45 days after the end of each quarter. | ||
| • | No limited partner shall have any management power over our business and affairs; the general partner shall conduct, direct and manage LRLP’s activities. | ||
| • | The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRLP’s general partner and its affiliates. | ||
| • | Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year |
In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRLP’s general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation.
As used herein, the term Moriah Group refers to Moriah Resources, Inc. (“MRI”), Moriah Properties, Ltd. (“MPL”), the oil and natural gas interests individually owned by Dale A. and Rita Brown and the accounts of MBN Properties LP on a consolidated basis unless the context specifies otherwise. Prior to March 15, 2006, the accompanying financial statements include the accounts of the Moriah Group. From March 15, 2006, the accompanying financial statements also include the results of operations of the oil and natural gas properties acquired in the Legacy Formation transaction. All significant intercompany accounts and transactions have been eliminated. The Moriah Group consolidated MBN Properties LP as a variable interest entity under FASB FIN 46R since the Moriah Group was the primary beneficiary of MBN Properties LP. The partners, shareholders and owners of these entities have other investments, such as real estate, that are held either individually or through other legal entities that are not presented as part of these financial statements. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.
MRI was organized as a sub-chapter S corporation on September 28, 1992 under the laws of the State of Texas, and serves as the 1% general partner to MPL. MPL was organized as a limited partnership on July 1, 1999 under the laws of the State of Texas. Dale A. Brown, an individual, has owned oil and natural gas working interests since 1981. Dale A. Brown, who along with his son, Cary D. Brown, are the sole owners of MRI and MPL. The assets of Moriah Properties New Mexico, Ltd. (“MNM”), a limited partnership organized under the laws of the State of Texas on October 17, 2003, were assigned into MPL effective September 1, 2005, in order to streamline the business of the limited partnerships with identical ownership and a shared general partner, MRI, and the accounts of MNM have been reflected retroactively in the financial statements of MPL. Effective October 1, 2005, Dale and Rita Brown assigned the selected oil and natural gas properties included in these consolidated financial statements to DAB Resources, Ltd., a Texas limited partnership they own.
F-9
On July 22, 2005, MPL advanced $1,649,132 which was recorded as paid in capital and subordinated notes receivable to MBN Properties LP which utilized the capital to fund a deposit with The Prospective Investment and Trading Company, Ltd. (“PITCO”) and its affiliates for the purchase of oil and natural gas properties described below. MPL also advanced $654,099 to fund the expenses of MBN Management LLC, the general partner of MBN Properties LP. Of this amount, $467 was for paid in capital and the balance of $653,632 was in a note receivable from MBN Management LLC. MBN Properties LP, a Delaware limited partnership, and MBN Management LLC, a Delaware limited liability company, (collectively the “MBN Group”) were formed to acquire and operate oil and natural gas producing properties in partnership with Brothers Production Properties, Ltd., and certain third party investors. Cary D. Brown, the Executive Vice President of MRI and its 50% owner, is the Chief Executive Officer and a Director of MBN Management LLC. On September 14, 2005, MBN Properties LP purchased oil and natural gas producing properties located in the Permian Basin from PITCO and its affiliates for $66,151,723 (the “PITCO Acquisition”), subject to post-closing adjustments. While MBN Management LLC is a variable interest entity, the Moriah Group accounted for its interest in that entity using the equity method since it is not the primary beneficiary of MBN Management LLC under the expected losses test of paragraph 14 of FAS FIN 46R.
Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin of West Texas and southeast New Mexico. Legacy has acquired oil and natural gas producing properties and drilled leasehold.
(b) Cash Equivalents
For purposes of the consolidated statement of cash flows, Legacy considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
(c) Trade Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10).
(d) Oil and Natural Gas Properties
Legacy accounts for oil and natural gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition of and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.
Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. FAS No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by the Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, Legacy follows FAS No. 143. Under FAS No. 143, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates.
Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized
F-10
costs to estimated undiscounted future net cash flows using oil and natural gas prices as of the last day of the statement period held constant. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2005, the estimated undiscounted future cash flows for Legacy’s proved oil and natural gas properties exceeded the net capitalized costs, and no impairment was required to be recognized. For the year ended December 31, 2006, Legacy recognized $16.1 million of impairment expense on 41 separate producing fields related primarily to the decline in natural gas and oil prices from the dates at which the purchase prices for the PITCO acquisition and the formation transaction were allocated among the purchased properties. As of December 31, 2007, Legacy recognized $3.2 million of impairment expense on 43 separate producing fields related primarily to the decline in performance on individual properties.
Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Costs related to unproved mineral interests that are individually insignificant are amortized over the shorter of the exploratory period or the lease/concession holding period which is typically three years in the Permian Basin.
(e) Oil and Natural Gas Reserve Quantities
Legacy’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche Petroleum Consultants, Ltd. prepares a reserve and economic evaluation of all Legacy’s properties on a well-by-well basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties.
Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.
(f) Income Taxes
Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes.
In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaced the existing franchise tax. This new tax is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. This franchise tax report covers our taxable activities for the year ended December 31, 2007.
Legacy recorded income tax expense of $337,000 for the year ended December 31, 2007 which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes.
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the difference between the Partnership’s net book basis and the Partnership’s net tax basis is $189.2 million.
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(g) Derivative Instruments and Hedging Activities
Legacy periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations and interest rate changes. Legacy accounts for these activities pursuant to FAS No. 133 —Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.
Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rate changes. Therefore, the cash settlements and mark-to-market of oil, NGL and natural gas derivatives are recorded in current earnings. Interest rate derivative effects are recorded in interest expense (see Note 9).
(h) Use of Estimates
Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization and asset retirement obligations.
(i) Revenue Recognition
Sales of crude oil, natural gas liquids and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry.
Legacy currently uses the “net-back” method of accounting for transportation arrangements of its natural gas sales. Legacy sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by its purchasers and reflected in the wellhead price. Legacy’s contracts with respect to the sale of its natural gas produced, with one immaterial exception, provide Legacy with a net price payment. That is, Legacy is paid for its natural gas by its purchasers, Legacy receives a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of Legacy’s contracts, the payment statements Legacy receives from its purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, Legacy’s revenues are recorded at this single net price.
Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2005, 2006 or 2007.
Legacy is paid a monthly operating fee for each well it operates for outside owners. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted
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against general and administrative expense.
(j) Investments
Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition.
(k) Intangible assets
Legacy has capitalized certain operating rights acquired in the acquisition of oil and gas properties (Note 4). The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment will be assessed on a quarterly basis or when there is a material change in the remaining useful life. The expected amortization expense for 2008, 2009, 2010, 2011 and 2012 is $547,000, $537,000, $522,000, $510,000 and $502,000, respectively.
(l) Environmental
Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments are fixed and readily determinable.
(m) Earnings (Loss) Per Unit
Legacy computes its earnings (loss) per unit in accordance with SFAS No. 128,Earnings per Share, which requires the presentation of basic and diluted earnings per unit on the face of the income statement. Basic earnings per unit amounts are calculated using the weighted average number of units outstanding during each period. Diluted earnings per unit also gives effect to dilutive unvested restricted units and unit options (calculated based upon the treasury stock method).
Basic and diluted earnings per unit for the year ended December 31, 2005 were computed based on the 9,488,921 units issued to the Moriah Group on March 15, 2006 in exchange for oil and natural gas properties contributed by it (including its indirect interest in oil and natural gas properties contributed by MBN Properties, LP) in conjunction with the closing of the Legacy Formation on the same date.
(n) Redemption of Units
Units redeemed are recorded at cost.
(o) Segment Reporting
Legacy’s management treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes.
(p) Unit-Based Compensation
Concurrent with the Formation Transaction on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created and
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Legacy adopted SFAS No. 123(R), Share-Based Payment. Due to Legacy’s history of cash settlements for option exercises, Legacy accounts for unit options under the liability method of SFAS No. 123(R). This method requires the Partnership to recognize the fair value of each unit option at the end of each period. Expense is recognized as a change in the liability from period to period. Pursuant to the provisions of SFAS 123(R), Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2007 does not include 45,078 units related to unvested restricted unit awards.
(q) Recently Issued Accounting pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157,Fair Value Measurements.Statement No. 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted account principles and expands disclosure related to the use of fair value measures in financial statements. The Statement is to be effective for Legacy’s financial statements issued in 2008. Although we do not expect any impact to be significant the Statement will affect fair value measurements we make after adoption.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115.Statement No. 159 permits entities to choose to measure certain financial instruments and 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. Unrealized gains and losses on any items for which Legacy elects the fair value measurement option would be reported in earnings. Statement No. 159 is effective for fiscal years beginning after November 15, 2007. Legacy does not expect to elect the fair value option for any eligible financial instruments and other items.
In April 2007, the FASB issued FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 clarifies that a reporting entity that is party to a master netting arrangement can offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement. FSP FIN 39-1 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Adoption of FSP FIN 39-1 is not expected to have a material impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the Partnership’s fiscal year 2009. The impact, if any, will depend on the nature and size of business combinations we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements—an amendments of ARB No. 51 “(SFAS 160).” SFAS 160 requires that accounting and reporting for minority interests will be re-characterized as non-controlling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be the Partnership’s fiscal year 2009. Based upon the December 31, 2007 balance sheet, the statement would have no impact.
(r) Prior Year Financial Statement Presentation
Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this annual report on Form 10-K.
(2) Fair Values of Financial Instruments
The estimated fair values of Legacy’s financial instruments closely approximate the carrying amounts as discussed below:
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Cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities.The carrying amounts approximate fair value due to the short maturity of these instruments.
Notes receivable.The carrying amounts approximate fair value due to the comparability of the interest rate to market interest rates for instruments of similar terms and credit quality.
Debt.The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings.
Commodity price derivatives.The fair market values of commodity derivative instruments are estimated based upon the current market price of the respective commodities at the date of valuation. It represents the amount which Legacy would be required to pay or able to receive, based upon the differential between a fixed and a variable commodity price as specified in the hedge contracts.
Interest rate derivatives.The fair market values of interest rate derivative instruments are estimated based upon the current market LIBOR rates for the respective notional amount at the date of valuation. It represents the difference between the fixed rate as specified in the hedge contracts and the floating rate applicable to the notional amounts.
(3) Credit Facility
On September 13, 2005, the Moriah Group replaced its Credit Agreement with a new Senior Credit Facility (the New Facility) with a new lending group that permitted borrowings in the lesser amount of (i) the borrowing base, or (ii) $75 million. The borrowing base under the New Facility, initially set at $40 million, was subject to re-determination every six months and was subject to adjustment based upon changes in the fair market value of the Moriah Group’s oil and natural gas assets. Interest on the New Facility was payable monthly and was charged in accordance with the Moriah Group’s selection of a LIBOR rate plus 1.5% to 2.0%, or prime rate up to prime rate plus 0.5%, dependent on the percentage of the borrowing base which was drawn. Borrowings under this New Facility were due in September 2009. The New Facility contained certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. On September 13, 2005, the Moriah Group borrowed $22,123,000 from the new lending group to provide for general corporate purposes, to fund a $4.2 million distribution to Cary Brown and Dale Brown and to advance additional subordinated notes receivable in the amount of $17,598,000 to MBN Properties LP, which purchased oil and natural gas producing properties from PITCO. The Moriah Group’s interest rate at December 31, 2005 was 6.0%. The Moriah Group paid interest expense on this debt of $220,638 for the year ended December 31, 2005 and $264,062 for the period from January 1, 2006 through March 15, 2006. At December 31, 2005, the Moriah Group was in compliance with all aspects of the Agreement. All amounts outstanding under this agreement at March 15, 2006 were repaid in full on that date as part of the formation transactions.
On September 13, 2005, MBN Properties LP entered into a Credit Agreement with a new Senior Credit Facility (the MBN Facility) with a lending group that permitted borrowings in the lesser amount of (i) the borrowing base, or (ii) $75 million. The borrowing base under the MBN Facility, initially set at $35 million, was subject to re- determination every six months and was subject to adjustment based upon changes in the fair market value of the MBN Properties LP’s oil and natural gas assets. Interest on the MBN Facility was payable monthly and was charged in accordance with MBN Properties LP’s selection of a LIBOR rate plus 1.5% to 2.0%, or prime rate up to prime rate plus 0.50%, dependent on the percentage of the borrowing base which was drawn. Borrowings under this MBN Facility were due in September 2007. The MBN Facility contained certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. On September 13, 2005, MBN Properties LP borrowed $33,750,000 from the new lending group to purchase oil and natural gas producing properties from PITCO. The MBN Properties LP’s interest rate at December 31, 2005 was 6.33%. MBN Properties LP paid interest expense of $431,085 on this debt for the period from inception to December 31, 2005 and $1,300,727 for the period from January 1, 2006 through March 15, 2006. At December 31, 2005, MBN Properties LP was in compliance with all aspects of the Agreement. All amounts outstanding under this agreement at March 15, 2006 were repaid in full on that date as part of the formation transactions.
As an integral part of the Legacy Formation, Legacy entered into a new credit agreement with a new senior credit facility (the “Legacy Facility”) with the same lending group that participated in the New Facility of the Moriah Group. Legacy’s oil and natural gas properties are pledged as collateral for any borrowings under the Legacy Facility. Borrowings under the Legacy Facility are due on March 15, 2010. The terms of the Legacy Facility permits borrowings in the lesser amount of (i) the borrowing base, or (ii) $500 million. The borrowing base under the Legacy Facility, which was initially set at $130 million, is re-determined every six months and will be adjusted based upon changes in the fair market value of the Partnership’s oil and natural gas assets. Interest on the Legacy Facility is payable monthly and is charged in accordance with the Partnership’s selection of a LIBOR rate plus 1.25% to 1.875%, or prime rate up to prime rate plus 0.375%, dependent on the percentage of the borrowing base which is drawn. On March 15, 2006, Legacy borrowed $65.8 million from the new lending group as part of the Legacy Formation. On May 3, 2007, Legacy’s bank group increased Legacy’s borrowing base to $150 million as part of the semi-annual re-determination. On October 24, 2007, the Legacy Facility was amended, increasing the borrowing base to $225 million
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and the borrowing capacity to $500 million. Pursuant to this amendment, interest on debt outstanding is charged based on Legacy’s selection of a LIBOR rate plus 1.00% to 1.75%, or the alternate base rate which equals the higher of the prime rate or the Federal funds effective rate plus 0.50%, plus an applicable margin between 0% and 0.25%.
On January 18, 2007, Legacy closed its initial public offering of 6,900,000 units representing limited partner interests at an initial public offering price of $19.00 per unit. Net proceeds to the partnership after underwriting discounts and estimated offering expenses were approximately $122 million, all of which was used to repay all indebtedness outstanding under the Legacy Facility and for general partnership purposes.
As of December 31, 2007, Legacy had outstanding borrowings of $110 million at an interest rate of 6.50%. Thus, Legacy had approximately $115 million of availability remaining. For the year ended December 31, 2007, Legacy paid $5,090,148 of interest expense on the Legacy Facility. The Legacy Facility contains certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. At December 31, 2007, Legacy was in compliance with all aspects of the Legacy Facility.
Long-term debt consists of the following at December 31, 2006 and 2007:
| December 31, | ||||||||
| 2006 | 2007 | |||||||
| Legacy facility- due March 2010 | $ | 115,800,000 | $ | 110,000,000 | ||||
(4) Acquisitions
PITCO Acquisition
On September 14, 2005, MBN Properties LP purchased oil and natural gas producing properties located in the Permian Basin from PITCO and its affiliates for $66,151,723 (the “PITCO Acquisition”), subject to post-closing adjustments of approximately $2.8 million. The all cash acquisition was funded from borrowings of $33,750,000 under MBN Properties LP’s existing credit facility and from loans from MPL and the Brothers Group (see Note 3). Including direct expenses associated with the PITCO acquisition, MBN Properties LP has recorded a purchase price of approximately $63.9 million, all of which has been allocated to the oil and natural gas properties purchased. In addition, MBN Properties LP has recorded a $445,000 asset retirement obligation (“ARO”) and related ARO asset under the guidelines of FAS 143. The results of operations from the properties acquired in the PITCO acquisition have been included in Legacy’s statements of operations beginning September 14, 2005.
Legacy Formation Acquisition
On March 15, 2006, LRLP completed a private equity offering in which it issued 5,000,000 limited partnership units at a gross price of $17.00 per unit, netting $76.8 million after initial purchaser’s discount, placement agent fees and expenses. Simultaneous with the completion of this offering, Legacy purchased the oil and natural gas properties of the Moriah Group, Brothers Group, H2K Holdings Ltd. and the Charitable Support Foundations, Inc. and its affiliates. Legacy also purchased the oil and natural gas properties owned by MBN Properties, LP. In the case of the Moriah Group, the Brothers Group and H2K Holdings Ltd. those entities exchanged their oil and natural gas properties for limited partnership units. The purchase of the oil and natural gas properties owned by the charitable foundations was solely for cash of $7.7 million. The owners of the Moriah Group, the Brothers Group and H2K Holdings Ltd. (the “Founding Investors”) exchanged 4.4 million of their units for $69.9 million in cash. The Moriah Group has been treated as the acquiring entity in the Legacy Formation. Accordingly, the accounts of the businesses acquired from the Moriah Group have been reflected retroactively at carryover basis in the consolidated financial statements, and the units issued to acquire them have been accounted for as a recapitalization. The net assets of the other businesses acquired and the units issued in exchange for them have been reflected at fair value and included in the statement of operations from the date of acquisition. With the exception of its assumption of liabilities associated with the oil and natural gas swaps it acquired, the other depreciable assets of the Brothers Group (office furniture and equipment and vehicles) and certain unamortized deferred financing costs of the Moriah Group, LRLP did not acquire any other assets or liabilities of the Moriah Group, the Brothers Group, H2K Holdings Ltd. or the Charitable Support Foundations, Inc. and its affiliates. The removal of the other assets and liabilities of the Moriah Group was reflected as a deemed dividend in Legacy’s December 31, 2006 consolidated statement of unitholders’ equity.
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The following table sets forth the units issued in the Legacy Formation transaction:
| Number of units | ||||
| MPL | 7,334,070 | |||
| DAB Resources, Ltd. | 859,703 | |||
| Moriah Group | 8,193,773 | |||
| Brothers Group | 6,200,358 | |||
| H2K Holdings Ltd. | 83,499 | |||
| MBN Properties LP | 3,162,438 | |||
| LRLP units | 600,000 | |||
| Total units issued at Legacy Formation | 18,240,068 | |||
In addition to the 18,240,068 units issued at Legacy Formation, 52,616 restricted management units were issued to employees of Legacy concurrent with, but not as a part of, the Legacy Formation (Note 13).
The following table sets forth the purchase price of the oil and natural gas properties purchased from the Brothers Group, H2K Holdings Ltd. and three charitable foundations, which included the assumption of liabilities associated with oil and natural gas swaps as of March 14, 2006:
| Number of Units | Purchase Price | |||||||
| at $17.00 per unit | of Assets Acquired | |||||||
| Brothers Group | 6,200,358 | $ | 105,406,069 | |||||
| H2K Holdings Ltd. | 83,499 | 1,419,483 | ||||||
| Cash paid to three charitable foundations | — | 7,682,854 | ||||||
| Total purchase price before liabilities assumed | 114,508,406 | |||||||
| Plus: | ||||||||
| Oil and natural gas swap liabilities assumed | 3,147,152 | |||||||
| Asset retirement obligations incurred | 1,467,241 | |||||||
| Less: | ||||||||
| Office furniture, equipment and vehicles acquired | (107,275 | ) | ||||||
| Total purchase price allocated to oil and natural gas properties acquired | $ | 119,015,524 | ||||||
In addition to the 3,162,438 common units issued to MBN Properties LP as part of the Legacy Formation transaction, LRLP paid $65.3 million in cash to MBN Properties LP to acquire that portion of the oil and natural gas properties of MBN Properties LP it did not already own by virtue of the Moriah Group’s ownership of a 46.22% limited partnership interest in MBN Properties LP. In addition, LRLP paid $1,980,468 to MBN Management LLC to reimburse expenses incurred by that entity in anticipation of the Legacy Formation. The following table sets forth the calculation of the step-up of oil and natural gas property basis with respect to this interest acquired:
| Number of Units | Purchase Price of | |||||||
| at $17.00 per unit | Assets Acquired | |||||||
| Units issued to MBN Properties LP | 3,162,438 | $ | 53,761,446 | |||||
| Cash paid to MBN Properties LP | — | 65,300,000 | ||||||
| Total purchase price before liabilities assumed | 119,061,446 | |||||||
| Plus: | ||||||||
| Oil and natural gas swap liabilities assumed | 2,539,625 | |||||||
| ARO liabilities assumed | 453,913 | |||||||
| Less: | ||||||||
| Net book value of other property and equipment on MBN Properties LP at March 14, 2006 | (39,056 | ) | ||||||
| 122,015,928 | ||||||||
| Less: | ||||||||
| Net book value of oil and gas assets on MBN Properties LP at March 14, 2006 | (62,990,390 | ) | ||||||
| Purchase price in excess of net book value of assets | 59,025,538 | |||||||
| Less: | ||||||||
| Share already owned by Moriah via consolidation of MBN Properties LP | 46.22 | % | (27,281,604 | ) | ||||
| Non-controlling interest share to record(a) | 31,743,934 | |||||||
| Plus: | ||||||||
| Elimination of deferred financing costs related to non-controlling interests’ share of MBN Properties LP | 164,202 | |||||||
| Reimbursement of Brothers Group’s share of MBN Management LLC losses from inception through March 14, 2006 | 780,239 | |||||||
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| Number of Units | Purchase Price of | |||||||
| at $17.00 per unit | Assets Acquired | |||||||
| MBN Properties LP purchase price to allocate to oil and natural gas properties | $ | 32,688,375 | ||||||
| Units related to purchase of non-controlling interest(a) | 1,867,290 | |||||||
| Units related to interest previously owned by Moriah Group | 1,295,148 | |||||||
| Total units issued to MBN Properties LP | 3,162,438 | |||||||
Larron Acquisition
On June 29, 2006, Legacy purchased a 100% working interest and an approximate 82% net revenue interest in producing leases located in the Farmer Field for $5,700,000. The conveyance of the leases is effective April 1, 2006. The $5.6 million net purchase price was allocated with $4.6 million recorded as lease and well equipment and $1.0 million of leasehold costs. Asset retirement obligations in the amount of $328,867 were recognized in connection with this acquisition. The operations of these Farmer Field properties are included from their acquisition on June 29, 2006 in Legacy’s statement of operations for the year ended December 31, 2006.
South Justis Unit Acquisition
On June 29, 2006, Legacy purchased Henry Holding LP’s 15.0% working interest and a 13.1% net revenue interest in the South Justis Unit (“SJU”), two leases not in the unit, each with one well, adjacent to the SJU and the right to operate these properties. The stated purchase price was $14 million cash plus the issuance of 138,000 units on June 29, 2006 and 8,415 units on November 10, 2006 at their estimated fair value of $17.00 per unit ($2,346,000 and $143,055, respectively) less final adjustments of approximately $624,000. The effective date of Legacy’s ownership was May 1, 2006. The operating results from this acquisition have been included from July 1, 2006. The properties acquired are located in Lea County, New Mexico where Legacy owns other producing properties. Legacy has been elected operator of the SJU following the closing of the transaction, which entitles Legacy to a contractual overhead reimbursement of approximately $127,500 per month from its partners in the SJU. The $15.9 million net purchase price was allocated with $2.9 million recorded as lease and well equipment, $6.0 million of leasehold costs and $7.0 million capitalized as an intangible asset relating to the contract operating rights. The capitalized operating rights will be amortized over the estimated total well months the wells in the SJU are expected to be operated. Asset retirement obligations in the amount of $137,453 were recognized in connection with this acquisition. The operations of the South Justis Unit are included from the acquisition on June 29, 2006 in Legacy’s statement of operations for the year ended December 31, 2006.
Kinder Morgan Acquisition
On July 31, 2006, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Kinder Morgan for a net purchase price of $17.2 million. The effective date of this purchase was July 1, 2006. The $17.2 million purchase price was allocated with $4.1 million recorded as lease and well equipment and $13.1 million of leasehold costs. Asset retirement obligations of $1,383,180 were recorded in connection with this acquisition. The operations of these Kinder Morgan Acquisition properties are included from their acquisition on July 31, 2006 in Legacy’s statement of operations for the year ended December 31, 2006.
Binger Acquisition
On April 16, 2007, Legacy purchased certain oil and natural gas properties and other interests in the East Binger (Marchand) Unit in Caddo County, Oklahoma from Nielson & Associates, Inc. for a net purchase price of $44.2 million (“Binger Acquisition”). The purchase price was paid with the issuance of 611,247 units valued at $15.8 million and $28.4 million paid in cash. The effective date of this purchase was February 1, 2007. The $44.2 million purchase price was allocated with $14.7 million recorded as lease and well equipment, $29.4 million of leasehold costs and $0.1 million as investment in equity method investee related to the 50% interest acquired in Binger Operations, LLC. Asset retirement obligations of $184,636 were recorded in connection with this acquisition. The operations of these Binger Acquisition properties have been included from their acquisition on April 16, 2007.
Ameristate Acquisition
On May 1, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Ameristate Exploration, LLC for a net purchase price of $5.2 million (“Ameristate Acquisition”). The effective date of this purchase was January 1, 2007. The $5.2 million purchase price was allocated with $0.5 million recorded as lease and well equipment and $4.7 million of leasehold costs. Asset retirement obligations of $51,414 were recorded in connection with this acquisition. The operations of these Ameristate Acquisition properties have been included from their acquisition on May 1, 2007.
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TSF Acquisition
On May 25, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Terry S. Fields for a net purchase price of $14.7 million (“TSF Acquisition”). The effective date of this purchase was March 1, 2007. The $14.7 million purchase price was allocated with $1.8 million recorded as lease and well equipment and $12.9 million of leasehold costs. Asset retirement obligations of $99,094 were recorded in connection with this acquisition. The operations of these TSF Acquisition properties have been included from their acquisition on May 25, 2007.
Raven Shenandoah Acquisition
On May 31, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Raven Resources, LLC and Shenandoah Petroleum Corporation for a net purchase price of $13.0 million (“Raven Shenandoah Acquisition”). The effective date of this purchase was May 1, 2007. The $13.0 million purchase price was allocated with $6.0 million recorded as lease and well equipment and $7.0 million of leasehold costs. Asset retirement obligations of $378,835 were recorded in connection with this acquisition. The operations of these Raven Shenandoah Acquisition properties have been included from their acquisition on May 31, 2007.
Raven OBO Acquisition
On August 3, 2007, Legacy purchased certain oil and natural gas properties located primarily in the Permian Basin from Raven Resources, LLC and private parties for a net purchase price of $20.0 million (“Raven OBO Acquisition”). The effective date of this purchase was July 1, 2007. The $20.0 million purchase price was allocated with $1.6 million recorded as lease and well equipment and $18.4 million of leasehold costs. Asset retirement obligations of $224,329 were recorded in connection with this acquisition. The operations of these Raven OBO Acquisition properties have been included from their acquisition on August 3, 2007.
TOC Acquisition
On October 1, 2007, Legacy purchased certain oil and natural gas properties located in the Texas Panhandle from The Operating Company, et al, for a net purchase price of $60.6 million (TOC Acquisition”). The effective date of this purchase was September 1, 2007. The $60.6 million purchase price was allocated with $23.7 million recorded as lease and well equipment and $36.9 million of leasehold costs. Asset retirement obligations of $1.6 million were recorded in connection with this acquisition. The operations of these TOC Acquisition properties have been included from their acquisition on October 1, 2007.
Summit Acquisition
Also on October 1, 2007, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Summit Petroleum Management Corporation for a net purchase price of $13.5 million (“Summit Acquisition”). The effective date of this purchase was September 1, 2007. The $13.5 million purchase price was allocated with $2.1 million recorded as lease and well equipment and $11.3 million as leasehold cost. Asset retirement obligations of $128,705 were recorded in connection with this acquisition. The operations of these Summit Acquisition properties have been included from their acquisition on October 1, 2007.
Pro Forma Operating Results
The following table reflects the unaudited pro forma results of operations as though the PITCO, Formation Transactions, Farmer Field, South Justis Unit, and Kinder Morgan acquisitions had occurred on January 1, 2005. The table also reflects the unaudited pro forma results of operations as though the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit acquisitions had each occurred on January 1, 2006 and 2007. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:
F-19
| December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| (dollars in thousands, except per unit data) | ||||||||||||
| Revenues | $ | 64,128 | $ | 115,414 | $ | 133,628 | ||||||
| Net income (loss) | $ | 6,295 | $ | 12,844 | $ | (53,261 | ) | |||||
| Earnings per unit — basic: | ||||||||||||
| Income from continuing operations | $ | 0.34 | $ | 0.68 | $ | (2.02 | ) | |||||
| Net income | $ | 0.34 | $ | 0.68 | $ | (2.02 | ) | |||||
| Earnings per unit — diluted: | ||||||||||||
| Income from continuing operations | $ | 0.34 | $ | 0.68 | $ | (2.02 | ) | |||||
| Net income | $ | 0.34 | $ | 0.68 | $ | (2.02 | ) | |||||
| Units used in computing earnings per unit: | ||||||||||||
| basic | 18,386,482 | 19,004,035 | 26,331,107 | |||||||||
| diluted | 18,386,482 | 19,005,627 | 26,331,107 | |||||||||
(5) Partnership Investments
MBN Properties LP, a Delaware limited partnership, and its 1% general partner, MBN Management LLC, a Delaware limited liability company, (collectively the “MBN Group”) were formed in 2005 to acquire and operate oil and natural gas producing properties in partnership with Brothers Production Properties, Ltd., and certain third party investors. On July 22, 2005, MPL advanced $1,649,132 in the form of $462 of paid in capital (46.2% partnership equity interest) and subordinated notes receivable of $1,648,670 to MBN Properties LP which utilized the capital to fund a deposit with The Prospective Investment and Trading Company, Ltd. (“PITCO”) and its affiliates for the purchase of oil and natural gas properties described in Note 4 above. On September 13, 2005, MPL advanced MBN Properties LP an additional $17,598,000 under the subordinated note receivable in conjunction with the closing of the PITCO acquisition described in Note 4 above. The subordinated note receivable from MBN Properties LP was due on July 15, 2012 and bore interest payable quarterly at the rate the Moriah Group paid under its New Facility plus 4%. The other investors in MBN Properties, LP loaned money on similar terms. The notes payable to the other investors were not eliminated in consolidation. MPL also advanced $654,099 to fund the expenses of MBN Management LLC, the general partner of MBN Properties LP. Of this amount, $467 was for paid in capital (46.7% partnership equity interest) and the balance of $653,632 was in a subordinated note receivable from MBN Management LLC due July 15, 2012 and bearing interest at 7%. At December 31, 2005, MBN Properties LP had a payable to MBN Management LLC in the amount of $194,907 related to advances made to MBN Properties LP during the period from inception through December 31, 2005. All amounts owned by MBN Properties LP and MBN Management LLC to Legacy were repaid on March 15, 2006 in connection with the Formation Transactions.
The following tables reflect condensed balance sheet and net loss information for MBN Management LLC on a gross basis:
| December 31, | ||||
| 2005 | ||||
| Current assets | $ | 1,233,338 | ||
| Other assets | 31,899 | |||
| Total assets | $ | 1,265,237 | ||
| Current liabilities | $ | 640,727 | ||
| Notes payable — affiliated entities | 1,952,753 | |||
| Members’ capital | (1,328,243 | ) | ||
| Total liabilities and members’ capital | $ | 1,265,237 | ||
F-20
| From Inception | ||||||||
| Through | January 1, 2006 | |||||||
| December 31, | to March 14, | |||||||
| 2005 | 2006 | |||||||
| General and administrative expenses | $ | (1,278,685 | ) | $ | (522,569 | ) | ||
| Operating loss | (1,278,685 | ) | (522,569 | ) | ||||
| Other expense | (50,558 | ) | (21,961 | ) | ||||
| Net loss | $ | (1,329,243 | ) | $ | (544,530 | ) | ||
(6) Related Party Transactions
Cary Brown and Dale Brown, as owners of the Moriah Group, and the Brothers Group own a combined non-controlling 4.16% interest as limited partners in the partnership which owns the building that Legacy occupies. Monthly rent is $14,808, without respect to property taxes and insurance. Prior to the Legacy Formation, the Moriah Group’s portion of this rent was reimbursed by the Moriah Group to Petroleum Strategies, Inc., an affiliated entity which is owned by Cary Brown and Dale Brown. The lease expires in August 2011.
The Moriah Group did not directly employ any persons or directly incur any office overhead. Substantially all general and administrative services were provided by Petroleum Strategies, Inc. which employed all personnel and paid for all employee salaries, benefits, and office expenses. Petroleum Strategies Inc. charged the Moriah Group for such services in an amount which was intended to be equal to the actual expenses it incurred. Amounts charged were $838,899, $445,267 and $0 for the years ended December 31, 2005, 2006 and 2007, respectively. On April 1, 2006 following the Legacy Formation, certain employees of Petroleum Strategies, Inc. and Brothers Production Company Inc. became employees of Legacy. For the period from March 15, 2006 to December 31, 2006, Brothers Production Company Inc. provided $47,236 of transition administrative services to Legacy.
Legacy uses Lynch, Chappell and Alsup for legal services. Alan Brown, son of Dale Brown and brother of Cary Brown, is a less than ten percent shareholder in this firm. Legacy paid legal fees of $23,472, $40,392 and $127,313 for the years ended December 31, 2005, 2006 and 2007, respectively.
(7) Commitments and Contingencies
From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes, if determined in a manner adverse to Legacy, could have a potential material adverse effect on its financial condition, results of operations or cash flows. Legacy believes the likelihood of such a future event to be remote.
Additionally, Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected.
Legacy has employment agreements with its officers that specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits.
(8) Business and Credit Concentrations
Cash
Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash.
Revenue and Trade Receivables
Substantially all Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil
F-21
and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2005, 2006, or 2007. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10.
(9) Derivative Financial Instruments
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the price of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
All of these price risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133 —Accounting for Derivative Instruments and Hedging Activities.These derivative instruments are intended to mitigate a portion of Legacy’s price-risk and may be considered hedges for economic purposes but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings.
By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates repayment risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
For the years ended December 31, 2005, 2006, and 2007, Legacy recognized realized and unrealized losses related to its oil, NGL and natural gas derivatives. The impact on net income from hedging activities was as follows:
| December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| Crude oil derivative contract settlements | $ | (3,530,651 | ) | $ | (6,666,755 | ) | $ | (3,627,050 | ) | |||
| Natural gas liquid derivative contract settlements | — | — | (619,466 | ) | ||||||||
| Natural gas derivative contract settlements | — | 6,404,533 | 4,457,519 | |||||||||
| Total derivative contract settlements | (3,530,651 | ) | (262,222 | ) | 211,003 | |||||||
| Unrealized change in fair value — oil contracts | (910,738 | ) | 4,338,459 | (76,484,184 | ) | |||||||
| Unrealized change in fair value — natural gas liquid contracts | — | — | (3,228,274 | ) | ||||||||
| Unrealized change in fair value — natural gas contracts | (1,717,476 | ) | 5,212,233 | (5,654,577 | ) | |||||||
| Total unrealized change in fair value | (2,628,214 | ) | 9,550,692 | (85,367,035 | ) | |||||||
| Total effect of derivative contracts | $ | (6,158,865 | ) | $ | 9,288,470 | $ | (85,156,032 | ) | ||||
In June 2005, Legacy paid its counterparty approximately $3.5 million to cancel and reset 2006 oil swaps from $51.31 to $59.38 per barrel. On July 22, 2005 Legacy paid approximately $0.8 million for an option to enter into a $55.00 per barrel oil swap related to the PITCO acquisition that was not exercised.
In September 2006, Legacy paid its counterparty $4 million to cancel and reset oil swaps for 372,000 barrels in 2007 from $60.00 to $65.82 per barrel and for 348,000 barrels in 2008 from $60.50 to $66.44 per barrel.
As of December 31, 2007, Legacy had the following NYMEX West Texas Intermediate crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
F-22
| Annual | Average | Price | ||||||||||
| Calendar Year | Volumes (Bbls) | Price per Bbl | Range per Bbl | |||||||||
| 2008 | 1,068,449 | $ | 69.31 | $ | 62.25 - $86.75 | |||||||
| 2009 | 986,413 | $ | 67.43 | $ | 61.05 - $86.75 | |||||||
| 2010 | 919,445 | $ | 66.10 | $ | 60.15 - $86.75 | |||||||
| 2011 | 698,640 | $ | 70.97 | $ | 67.33 - $86.75 | |||||||
| 2012 | 580,800 | $ | 70.94 | $ | 67.72 - $86.75 | |||||||
As of December 31, 2007, Legacy had the following NYMEX Henry Hub, ANR-OK and Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
| Annual | Average | Price | ||||||||||
| Calendar Year | Volumes (MMBtu) | Price per MMBtu | Range per MMBtu | |||||||||
| 2008 | 2,533,770 | $ | 8.14 | $ | 6.85 - $10.58 | |||||||
| 2009 | 2,331,470 | $ | 7.99 | $ | 6.85 - $10.17 | |||||||
| 2010 | 2,065,955 | $ | 7.73 | $ | 6.85 - $9.73 | |||||||
| 2011 | 788,824 | $ | 7.25 | $ | 6.85 - $7.57 | |||||||
| 2012 | 493,236 | $ | 7.16 | $ | 6.85 - $7.57 | |||||||
As of December 31, 2007, Legacy had the following gas basis swaps in which we receive floating NYMEX prices less a fixed basis differential and pay prices on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our natural gas sales follow Waha more closely than NYMEX:
| Annual | Basis | |||||||
| Calendar Year | Volumes (MMBtu) | Range per Mcf | ||||||
| 2008 | 1,422,000 | ($0.84 | ) | |||||
| 2009 | 1,320,000 | ($0.68 | ) | |||||
| 2010 | 1,200,000 | ($0.57 | ) | |||||
As of December 31, 2007, Legacy had the following Mont Belvieu, Non-Tet OPIS natural gas liquids swaps paying floating natural gas liquids prices and receiving fixed prices for a portion of its future natural gas liquids production as indicated below:
| Annual | Average | Price | ||||||||||
| Calendar Year | Volumes (Gal) | Price per Gal | Range per Gal | |||||||||
| 2008 | 6,458,004 | $ | 1.27 | $ | 0.66 - $1.62 | |||||||
| 2009 | 2,265,480 | $ | 1.15 | $ | 1.15 | |||||||
On August 29, 2007, Legacy entered into LIBOR interest rate swaps beginning in October of 2007 and extending through November 2011. The swap transaction has Legacy paying its counterparty fixed rates ranging from 4.8075% to 4.82%, per annum, and receiving floating rates on a total notional amount of $54 million. The swaps are settled on a quarterly basis, beginning in January of 2008 and ending in November of 2011.
Legacy accounts for these interest rate swaps pursuant to FAS No. 133 —Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments be recorded at fair market value and included in the balance sheet assets or liabilities.
As the term of Legacy’s interest rate swaps extend through November of 2011, a period that extends beyond the term of the credit agreement, which expires on March 15, 2010, Legacy did not specifically designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments, which amounts to $1.5 million in 2007, is recorded in current earnings. The table below summarizes the interest rate swap position as of December 31, 2007.
F-23
| Estimated | ||||||||||
| Fair Market Value | ||||||||||
| Fixed | Effective | Maturity | at December 31, | |||||||
| Notional Amount | Rate | Date | Date | 2007 | ||||||
| $29,000,000 | 4.8200% | 10/16/2007 | 10/16/2011 | $ | (797,823 | ) | ||||
| $13,000,000 | 4.8100% | 11/16/2007 | 11/16/2011 | (366,241 | ) | |||||
| $12,000,000 | 4.8075% | 11/28/2007 | 11/28/2011 | (331,698 | ) | |||||
| Total Fair Market Value | $ | (1,495,762 | ) | |||||||
(10) Sales to Major Customers
Legacy operates as one business segment within the Permian Basin region. It sold oil, NGL and natural gas production representing 10% or more of total revenues for the years ended December 31, 2005, 2006 and 2007 as shown below:
| 2005 | 2006 | 2007 | ||||||||||
| Conoco Phillips | 10 | % | 4 | % | 3 | % | ||||||
| Navajo Crude Oil Marketing | 16 | % | 12 | % | 11 | % | ||||||
| Plains Marketing, LP | 18 | % | 14 | % | 13 | % | ||||||
| Teppco Crude Oil, LP | 5 | % | 5 | % | 13 | % | ||||||
In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of the Legacy’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Legacy believes that the loss of any of its major purchasers would not have a long-term material adverse effect on its operations.
(11) Asset Retirement Obligation
In June 2001, the FASB issued FAS No. 143, which requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at Legacy’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
The following table reflects the changes in the ARO during the years ended December 31, 2005, 2006, and 2007.
| December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| Asset retirement obligation — beginning of period | $ | 1,952,866 | $ | 2,302,147 | $ | 6,492,780 | ||||||
| Liabilities incurred in Legacy formation | — | 1,467,241 | — | |||||||||
| Liabilities incurred with properties acquired | 446,901 | 1,888,954 | 3,033,501 | |||||||||
| Liabilities incurred with properties drilled | — | 22,882 | 114,317 | |||||||||
| Liabilities settled during the period | (53,852 | ) | (213,343 | ) | (372,611 | ) | ||||||
| Current period accretion | 109,429 | 242,432 | 470,002 | |||||||||
| Current period revisions to accretion expense | (163,281 | ) | — | — | ||||||||
| Current period revisions to oil and natural gas properties | 10,084 | 782,467 | 6,181,660 | |||||||||
| Asset retirement obligation — end of period | $ | 2,302,147 | $ | 6,492,780 | $ | 15,919,649 | ||||||
The discount rate used in calculating the ARO was 6.0% at December 31, 2005, 7.25% at December 31, 2006 and 6.47% at December 31, 2007. These rates approximate Legacy’s borrowing rates.
F-24
(12) Earnings (Loss) Per Unit
The following table sets forth the computation of basic and diluted net earnings (loss) per unit (dollars in thousands, except per unit):
| December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| Income (loss) available to unitholders | $ | 5,859 | $ | 4,357 | $ | (55,662 | ) | |||||
| Weighted average number of units outstanding | 9,488,921 | 16,567,287 | 26,155,439 | |||||||||
| Effect of dilutive securities: | ||||||||||||
| Unit options | — | — | — | |||||||||
| Restricted units | — | 1,592 | — | |||||||||
| Weighted average units and potential units outstanding | 9,488,921 | 16,568,879 | 26,155,439 | |||||||||
| Basic earnings per unit | $ | 0.62 | $ | 0.26 | $ | (2.13 | ) | |||||
| Diluted earnings per unit | $ | 0.62 | $ | 0.26 | $ | (2.13 | ) | |||||
At December 31, 2006, options to purchase 260,000 units at exercise prices ranging from $17.00 to $17.25 per unit were outstanding, but were not included in the computation of diluted earnings per share due to their anti-dilutive effect. At December 31, 2007, 45,078 restricted units and options to purchase 252,306 units at exercise prices ranging from $17.00 to $27.84 per unit were outstanding, but were not included in the computation of diluted earnings per share due to their anti-dilutive effect.
(13) Unit-Based Compensation
Long Term Incentive Plan
Concurrent with the Formation Transaction on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created and Legacy adopted SFAS No. 123(R), Share-Based Payment. Legacy adopted the Legacy Reserves LP Long-Term Incentive Plan for its employees, consultants and directors, its affiliates and its general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights. The long-term incentive plan permits the grant of awards covering an aggregate of 2,000,000 units. As of December 31, 2007 grants of awards net of forfeitures covering 505,576 units have been made, comprised of 422,460 unit options and unit appreciation rights awards, 65,116 restricted unit awards and 18,000 phantom unit awards. The LTIP is administered by the compensation committee of the board of directors of its general partner.
SFAS No. 123(R), Share-Based Payment requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the-vesting period of the award. Prior to April of 2007, Legacy utilized the equity method of accounting as described in SFAS No. 123(R) to recognize the cost associated with unit options. However, SFAS No. 123(R) stipulates that “if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument.”
The initial vesting of options occurred on March 15, 2007, with initial option exercises occurring in April 2007. At the time of the initial exercise Legacy settled these exercises in cash and determined it was likely to do so for future option exercises. Consequently, in April 2007, Legacy began accounting for unit option grants by utilizing the liability method as described in SFAS No. 123(R). The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of the period. Compensation cost is recognized based on the change in the liability between periods.
Unit Options and Unit Appreciation Rights
During the year ended December 31, 2006, Legacy issued 273,000 unit option awards to officers and employees which vest ratably over a three-year period. During the year ended December 31, 2007, Legacy issued 113,000 unit option awards to employees which vest ratably over a three-year period. During the year ended December 31, 2007, Legacy issued 66,116 unit option awards which cliff-vest at the end of a three-year period. All options granted in 2007 expire five years from the grant date and are exercisable when they vest.
F-25
For the year ended December 31, 2007, Legacy recorded $826,406 of compensation expense based on its use of the Black Scholes model to estimate the December 31, 2007 fair value of these unit option awards and the exercise date fair value of options exercised during the period. As of December 31, 2007, there was a total of $919,028 of unrecognized compensation costs related to the un-exercised and non-vested portion of these unit option awards. At December 31, 2007, this cost was expected to be recognized over a weighted-average period of 2.0 years. Compensation expense is based upon the fair value as of December 31, 2007 and is recognized as a percentage of the service period satisfied. Since Legacy is a newly public company and has minimal trading history, it has used an estimated volatility factor of approximately 41% based upon a representative group of publicly-traded companies in the energy industry and employed the fair value method to estimate the December 31, 2007 fair value to be realized as compensation cost based on the percentage of the service period satisfied. In the absence of historical data, Legacy has assumed an estimated forfeiture rate of 5%. As required by SFAS No. 123(R), the Partnership will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $1.80 per unit.
A summary of option activity for the year ended December 31, 2007 is as follows:
| Weighted | ||||||||||||
| Weighted | Average | |||||||||||
| Average | Remaining | |||||||||||
| Exercise | Contractual | |||||||||||
| Units | Price | Term | ||||||||||
| Outstanding at January 1, 2007 | 260,000 | $ | 17.01 | |||||||||
| Granted | 179,116 | $ | 23.09 | |||||||||
| Exercised | (23,038 | ) | $ | 17.00 | ||||||||
| Forfeited | (16,656 | ) | $ | 17.09 | ||||||||
| Outstanding at December 31, 2007 | 399,422 | $ | 19.73 | 3.6 years | ||||||||
| Options exercisable at December 31, 2007 | 62,800 | $ | 17.04 | 3.3 years | ||||||||
The following table summarizes the status of the Partnership’s non-vested stock options since January 1, 2007:
| Non-Vested Options | ||||||||
| Weighted- | ||||||||
| Number of | Average Fair | |||||||
| Units | Value | |||||||
| Non-vested at January 1, 2007 | 260,000 | $ | 2.62 | |||||
| Granted | 179,116 | 3.40 | ||||||
| Vested — Unexercised | (62,800 | ) | 4.65 | |||||
| Vested — Exercised | (23,038 | ) | 10.14 | |||||
| Forfeited | (16,656 | ) | 9.56 | |||||
| Non-vested at December 31, 2007 | 336,622 | $ | 4.09 | |||||
Legacy has used a weighted-average risk free interest rate of 3.5% in its Black Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at December 31, 2007. Expected life represents the period of time that options are expected to be outstanding and is based on the Partnership’s best estimate. The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model:
| Year Ended | ||||
| December 31, | ||||
| 2007 | ||||
| Expected life (years) | 5 | |||
| Annual interest rate | 3.5 | % | ||
| Annual distribution rate per unit | $ | 1.80 | ||
| Volatility | 41 | % | ||
F-26
Restricted and Phantom Units
As described below, Legacy has also issued phantom units under the LTIP. Because Legacy’s current intent is to settle these awards in cash, Legacy is accounting for the phantom units by utilizing the liability method.
On June 27, 2007, Legacy granted 3,000 phantom units to an employee which vest ratably over a five year period, beginning at the date of grant. On July 16, 2007, Legacy granted 5,000 phantom units to an employee which vest ratably over a five year period, beginning at the date of grant. On December 3, 2007, Legacy granted 10,000 phantom units to an employee. The phantom units awarded vest ratably over a three year period, beginning on the date of grant. In conjunction with these grants, the employees are entitled to dividend equivalent rights (“DERs”) for unvested units held at the date of dividend payment. Compensation expense related to the phantom units and associated DERs was $52,273 for the year ended December 31, 2007.
On August 20, 2007, the board of directors of Legacy’s general partner, upon recommendation from the Compensation Committee, approved phantom unit awards which may award up to 175,000 units to five key executives of Legacy based on achievement of targeted annual MLP distribution levels over a base amount of $1.64 per unit. These awards are to be determined annually based solely on the annualized level of per unit distributions for the fourth quarter of each calendar year and subsequently vested over a 3 year period. There is a range of 0% to 100% of the distribution levels at which the performance condition may be met. For each quarter, management recommends to the board an appropriate level of per unit distribution based on available cash of Legacy. This level of distribution is approved by the board subsequent to management’s recommendation. Probable issuances for the purposes of calculating compensation expense associated therewith are determined based on management’s determination of probable future distribution levels for interim periods and based on actual distributions for annual periods as described above. Expense associated with vesting is recognized over the period from the date vesting becomes probable to the end of the three year vesting period beginning at each year end. Compensation expense related to the phantom units was $44,381 for the year ended December 31, 2007.
On March 15, 2006, Legacy issued 52,616 units of restricted unit awards to two employees. The restricted units awarded vest ratably over a three-year period, beginning on the date of grant. On May 5, 2006, Legacy issued 12,500 units of restricted unit awards to an employee. The restricted units awarded vest ratably over a five-year period, beginning on the date of grant. Compensation expense related to restricted units was $270,039 and $340,656 for the years ended December 31, 2006 and 2007, respectively. As of December 31, 2007, there was a total of $496,275 of unrecognized compensation costs related to the non-vested portion of these restricted units. At December 31, 2007, this cost was expected to be recognized over a weighted-average period of 1.8 years.
On May 1, 2006, Legacy granted and issued 1,750 units to each of its five non-employee directors as part of their annual compensation for serving on Legacy’s board. The value of each unit was $17.00 at the time of grant. On November 26, 2007, Legacy granted and issued 1,750 units to each of its four non-employee directors as part of their annual compensation for serving on Legacy’s board. The value of each unit was $21.32 at the time of grant.
(14) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities
Costs incurred by Legacy in oil and natural gas property acquisition and development are presented below:
| Year Ended December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| Development costs | $ | 1,958,455 | $ | 17,325,052 | $ | 22,967,534 | ||||||
| Exploration costs | — | — | — | |||||||||
| Acquisition costs: | ||||||||||||
| Proved properties | 65,405,917 | 187,006,693 | 200,399,637 | |||||||||
| Unproved properties | 2,928 | — | — | |||||||||
| Total acquisition, development and exploration costs | $ | 67,367,300 | $ | 204,331,745 | $ | 223,367,171 | ||||||
Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.
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(15) Net Proved Oil and Natural Gas Reserves (Unaudited)
The proved oil and natural gas reserves of Legacy have been estimated by an independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., as of December 31, 2005, 2006 and 2007. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices and costs. The table below includes the reserves associated with the PITCO acquisition in September 2005 which is reflected in the December 31, 2005 balances, the Legacy Formation acquisition in March 2006, the Farmer Field and South Justis acquisitions in June 2006 and the Kinder Morgan acquisition in July 2006 which are reflected in the December 31, 2006 balances and the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit acquisitions which are reflected in the December 31, 2007 balances. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:
| Natural | ||||||||||||
| Oil | NGL | Gas | ||||||||||
| (MBbls) | (MBbls) | (MMcf) | ||||||||||
Total Proved Reserves: | ||||||||||||
| Balance, December 31, 2004 | 4,109 | — | 10,470 | |||||||||
| Purchases of minerals-in-place | 3,541 | — | 12,800 | |||||||||
| Revisions of previous estimates due to infill drilling, recompletions and stimulations | 794 | — | 1,258 | |||||||||
| Revisions of previous estimates due to prices and performance | 28 | — | 956 | |||||||||
| Production | (354 | ) | — | (1,027 | ) | |||||||
| Balance, December 31, 2005(a) | 8,118 | — | 24,457 | |||||||||
| Purchases of minerals-in-place | 6,352 | — | 11,871 | |||||||||
| Extensions and discoveries | 75 | — | 207 | |||||||||
| Revisions of previous estimates due to infill drilling, recompletions and stimulations | 233 | — | 494 | |||||||||
| Revisions of previous estimates due to prices and performance | (657 | ) | — | (2,296 | ) | |||||||
| Production | (749 | ) | — | (2,200 | ) | |||||||
| Balance, December 31, 2006 | 13,372 | — | 32,533 | |||||||||
| Purchases of minerals-in-place | 6,367 | 3,971 | 19,417 | |||||||||
| Sales of minerals-in-place | (1 | ) | — | (2 | ) | |||||||
| Revisions from drilling and recompletions | 220 | — | 386 | |||||||||
| Revisions of previous estimates due to price and performance | 810 | 180 | 1,578 | |||||||||
| Production | (1,179 | ) | (126 | ) | (3,052 | ) | ||||||
| Balance, December 31, 2007 | 19,589 | 4,025 | 50,860 | |||||||||
Proved Developed Reserves: | ||||||||||||
| December 31, 2004 | 4,109 | — | 10,470 | |||||||||
| December 31, 2005 | 6,380 | — | 20,618 | |||||||||
| December 31, 2006 | 11,132 | — | 28,126 | |||||||||
| December 31, 2007 | 17,434 | 3,954 | 45,455 | |||||||||
| (a) | Includes 3.2 MMBls of oil and 13.0 Bcf of natural gas held by MBN Properties, LP of which 1.7 MMBls and 7.0 Bcf of natural gas was owned by the non-controlling interest. |
(16) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)
Summarized in the following table is information for Legacy inclusive of MBN/PITCO acquisition properties from September 2005, the Legacy Formation acquisition properties from March 2006, the Farmer Field and South Justis acquisition properties from June 2006 and the Kinder Morgan acquisition properties from July 2006, and the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit acquisition properties in 2007 with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying year-end prices relating to the Legacy’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are derived based
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on current costs assuming continuation of existing economic conditions. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Legacy’s future federal income taxes have not been deducted from future production revenues in the calculation of standardized measure as each partner is separately taxed on their share of Legacy’s taxable income. In addition, Texas margin taxes and the federal income taxes associated with a corporate subsidiary, as discussed in Note 1(f), have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure.
| December 31, | ||||||||||||
| 2005(a) | 2006 | 2007 | ||||||||||
| (thousands) | ||||||||||||
| Future production revenues | $ | 684,021 | $ | 947,914 | $ | 2,431,492 | ||||||
| Future costs: | ||||||||||||
| Production | (242,796 | ) | (387,238 | ) | (925,450 | ) | ||||||
| Development | (27,609 | ) | (43,419 | ) | (68,745 | ) | ||||||
| Future net cash flows before income taxes | 413,616 | 517,257 | 1,437,297 | |||||||||
| 10% annual discount for estimated timing of cash flows | (221,619 | ) | (276,694 | ) | (746,759 | ) | ||||||
| Standardized measure of discounted net cash flows | $ | 191,997 | $ | 240,563 | $ | 690,538 | ||||||
| (a) | Includes $93.0 million of standardized measure held by MBN Properties LP of which $50.2 million was owned by the non-controlling interest. |
The Standardized Measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:
| December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| Oil (per Bbl) | $ | 57.64 | $ | 56.73 | $ | 91.96 | ||||||
| Natural Gas (per Mcf) | $ | 8.82 | $ | 5.82 | $ | 6.39 | ||||||
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The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows which reflects the PITCO acquisition in 2005, the Legacy Formation in 2006, the Farmer Field, South Justis and the Kinder Morgan acquisitions in 2006 and the Binger, Ameristate, TSF, Raven Shenandoah, Raven OBO, TOC and Summit acquisitions in 2007:
| Year ended December 31, | ||||||||||||
| 2005 | 2006 | 2007 | ||||||||||
| (dollars in thousands) | ||||||||||||
| Increase (decrease): | ||||||||||||
| Sales, net of production costs | $ | (17,532 | ) | $ | (40,113 | ) | $ | (77,260 | ) | |||
| Net change in sales prices, net of production costs | 36,574 | (60,531 | ) | 178,972 | ||||||||
| Changes in estimated future development costs | (21,401 | ) | 4,582 | 1,426 | ||||||||
| Extensions and discoveries, net of future production and development costs | — | 2,723 | — | |||||||||
| Revisions of previous estimates due to infill drilling, recompletions and stimulations | 19,319 | 7,919 | 7,347 | |||||||||
| Revisions of previous quantity estimates due to prices and performance | 3,156 | (12,232 | ) | 4,273 | ||||||||
| Previously estimated development costs incurred | (178 | ) | 9,517 | 7,345 | ||||||||
| Purchases of minerals-in place | 102,289 | 127,009 | 300,907 | |||||||||
| Ownership interest corrections | — | — | 1,480 | |||||||||
| Sales of minerals in place | — | — | (22 | ) | ||||||||
| Other | 4,458 | (2,971 | ) | 2,093 | ||||||||
| Accretion of discount | 4,955 | 12,663 | 23,414 | |||||||||
| Net increase | 131,640 | 48,566 | 449,975 | |||||||||
| Standardized measure of discounted future net cash flows: | ||||||||||||
| Beginning of year | 60,357 | 191,997 | 240,563 | |||||||||
| End of year | $ | 191,997 | $ | 240,563 | $ | 690,538 | ||||||
The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
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(17) Selected Quarterly Financial Data (Unaudited)
For the three-month periods ended:
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
2007 | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil sales | $ | 12,301 | $ | 16,653 | $ | 22,442 | $ | 31,905 | ||||||||
| Natural gas liquids sales | 105 | 1,072 | 1,714 | 4,611 | ||||||||||||
| Natural gas sales | 3,526 | 5,010 | 5,241 | 7,656 | ||||||||||||
| Total revenues | 15,932 | 22,735 | 29,397 | 44,172 | ||||||||||||
| Expenses: | ||||||||||||||||
| Oil and natural gas production | 4,739 | 6,088 | 7,581 | 8,721 | ||||||||||||
| Production and other taxes | 994 | 1,481 | 1,886 | 3,528 | ||||||||||||
| General and administrative | 1,827 | 2,769 | 1,443 | 2,353 | ||||||||||||
| Depletion, depreciation, amortization and accretion | 5,295 | 6,811 | 6,960 | 9,349 | ||||||||||||
| Impairment of long-lived assets | 90 | 190 | 950 | 1,974 | ||||||||||||
| Loss on disposal of assets | — | 231 | 156 | 140 | ||||||||||||
| Total expenses | 12,945 | 17,570 | 18,976 | 26,065 | ||||||||||||
| Operating Income | 2,987 | 5,165 | 10,421 | 18,107 | ||||||||||||
| Interest income | 104 | 47 | 54 | 116 | ||||||||||||
| Interest expense | (625 | ) | (893 | ) | (1,905 | ) | (3,695 | ) | ||||||||
| Equity in income of partnership | — | 11 | 30 | 36 | ||||||||||||
| Realized gain (loss) on oil, NGL and natural gas swaps | 2,466 | 1,362 | 408 | (4,025 | ) | |||||||||||
| Unrealized loss on oil, NGL and natural gas swaps | (9,689 | ) | (7,855 | ) | (6,844 | ) | (60,979 | ) | ||||||||
| Other | — | 1 | — | (130 | ) | |||||||||||
| Net income (loss) before income taxes | (4,757 | ) | (2,162 | ) | 2,164 | (50,570 | ) | |||||||||
| Income taxes | — | — | — | (337 | ) | |||||||||||
| Net income (loss) | $ | (4,757 | ) | $ | (2,162 | ) | $ | 2,164 | $ | (50,907 | ) | |||||
| Net income (loss) per share — basic and diluted | $ | (0.19 | ) | $ | (0.08 | ) | $ | 0.08 | $ | (1.81 | ) | |||||
| Production volumes: | ||||||||||||||||
| Oil (MBbl) | 228 | 273 | 312 | 365 | ||||||||||||
| Natural Gas Liquids (Mgal) | 104 | 856 | 1,345 | 2,991 | ||||||||||||
| Natural Gas (MMcf) | 588 | 718 | 801 | 945 | ||||||||||||
| Total (Mboe) | 329 | 413 | 478 | 594 | ||||||||||||
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For the three-month periods ended:
| March 31 | June 30 | September 30 | December 31 | |||||||||||||
2006 | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil sales | $ | 7,440 | $ | 11,800 | $ | 13,204 | $ | 12,907 | ||||||||
| Natural gas sales | 2,995 | 3,588 | 4,239 | 3,624 | ||||||||||||
| Total revenues | 10,435 | 15,388 | 17,443 | 16,531 | ||||||||||||
| Expenses: | ||||||||||||||||
| Oil and natural gas production | 2,677 | 3,186 | 4,297 | 5,778 | ||||||||||||
| Production and other taxes | 738 | 943 | 1,030 | 1,035 | ||||||||||||
| General and administrative(a) | 956 | 1,253 | 1,057 | 426 | ||||||||||||
| Dry hole costs | — | — | — | — | ||||||||||||
| Depletion, depreciation, amortization and accretion | 2,388 | 4,967 | 5,346 | 5,693 | ||||||||||||
| Impairment of long-lived assets | — | — | 8,573 | 7,540 | ||||||||||||
| Loss on disposal of assets | — | — | — | 42 | ||||||||||||
| Total expenses | 6,759 | 10,349 | 20,303 | 20,514 | ||||||||||||
| Operating Income | 3,676 | 5,039 | (2,860 | ) | (3,983 | ) | ||||||||||
| Interest income | 33 | 5 | 55 | 36 | ||||||||||||
| Interest expense | (1,445 | ) | (1,210 | ) | (1,857 | ) | (2,133 | ) | ||||||||
| Realized gain (loss) on oil, NGL and natural gas swaps | 1,398 | 548 | (4,128 | ) | 1,920 | |||||||||||
| Unrealized gain (loss) on oil, NGL and natural gas swaps | (5,294 | ) | (9,724 | ) | 22,734 | 1,835 | ||||||||||
| Other | (303 | ) | — | — | 14 | |||||||||||
| Net income (loss) | $ | (1,935 | ) | $ | (5,342 | ) | $ | 13,944 | $ | (2,311 | ) | |||||
| Net income (loss) per share — basic and diluted | $ | (0.17 | ) | $ | (0.29 | ) | $ | 0.76 | $ | (0.13 | ) | |||||
| Production volumes: | ||||||||||||||||
| Oil (MBbl) | 129 | 184 | 203 | 233 | ||||||||||||
| Natural Gas (MMcf) | 434 | 594 | 571 | 601 | ||||||||||||
| Total (Mboe) | 201 | 283 | 298 | 333 | ||||||||||||
| (a) | General and administrative expenses for the quarter ended December 31, 2006 reflect an adjustment to reverse certain accruals which had been recorded during the first three quarters and were not deemed necessary. |
(18) Subsequent Events
On January 23, 2008, the board of directors of Legacy’s general partner declared a $0.45 per unit cash distribution for the quarter ended December 31, 2007 to all unitholders of record on February 4, 2008. This distribution was paid on February 14, 2008.
On March 13, 2008, Legacy entered into a definitive purchase agreement to acquire certain oil and natural gas producing properties from a third party for an aggregate purchase price of $82 million, subject to purchase price adjustments. If certain conditions are met, Legacy intends to pay at closing a portion of the purchase price with newly issued units, reducing the cash payment to $55 million, which amount will be subject to closing adjustments. The properties are located in the Permian Basin of West Texas and Southeast New Mexico, Kansas and Oklahoma. The acquisition is subject to customary closing conditions and is expected to close by April 30, 2008. This acquisition will be accounted for as a purchase of oil and natural gas assets.
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On March 13, 2008, Legacy entered into NYMEX WTI Oil swaps and Waha natural gas swaps related to this announced acquisition along with increasing our natural gas fixed price swap exposure on our existing assets in 2011 and 2012. The following tables set forth these new swaps.
The new NYMEX WTI oil swaps are as follows:
| Swap | Contract | |||||||
| Time Period | Volumes | Oil Price | ||||||
| Calendar Contracts | (Bbls.) | ($/Bbl) | ||||||
| June-Dec. 2008 | 90,300 | $ | 101.47 | |||||
| 2009 | 145,200 | $ | 101.47 | |||||
| 2010 | 134,400 | $ | 101.47 | |||||
| 2011 | 124,800 | $ | 101.47 | |||||
| 2012 | 116,400 | $ | 101.47 | |||||
| Total | 611,100 | $ | 101.47 | |||||
Swaps are tabulated below for natural gas fixed price swaps indexed to the Waha hub in West Texas. The Waha hub trades at a discount range of approximately $0.55 - $1.10 to the NYMEX Henry Hub natural gas index. The natural gas prices that we receive for our natural gas sales follow Waha more closely than the NYMEX Henry Hub index.
| Contract | ||||||||
| Swap | Natural | |||||||
| Time Period | Volumes | Gas Price | ||||||
| Calendar Contracts | (MMBtu) | ($/MMBtu) | ||||||
| June-Dec. 2008 | 253,463 | $ | 8.70 | |||||
| 2009 | 399,372 | $ | 8.70 | |||||
| 2010 | 364,404 | $ | 8.70 | |||||
| 2011 | 951,792 | $ | 8.70 | |||||
| 2012 | 719,400 | $ | 8.70 | |||||
| Total | 2,688,431 | $ | 8.70 | |||||
Legacy contemplates the filing of a registration statement on Form S-3 on or about April 4, 2008. Securities being registered include debt securities which may be guaranteed by Legacy’s subsidiaries and are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. Legacy, as the parent company, has no independent assets or operations. Legacy contemplates that if it offers guaranteed debt securities pursuant to the registration statement, all guarantees will be full and unconditional and joint and several, and any subsidiaries of Legacy other than the subsidiary guarantors will be minor. In addition, there are no restrictions on the ability of the Legacy Reserves LP to obtain funds from its subsidiaries by dividend or loan. Finally, there are no restricted assets in any subsidiaries.
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