Legacy Reserves 10-Q 2007 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2007

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from                        to                        

Commission file number 1-33249

Legacy Reserves LP

(Exact name of registrant as specified in its charter)

Delaware	16-1751069
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
303 W. Wall Suite 1400 Midland, Texas	79701
(Address of principal executive offices)	(Zip code)

(432) 689-5200

(Registrant’s telephone number, including area code)

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x Yes  o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filed, or a non-accelerated filer. See definition of “accelerated filer and larger accelerated filer” in Rule 12b-2 of the Exchange Act.:

o Large accelerated filer o Accelerated filer x Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes  x No

26,066,596 units representing limited partner interest in the registrant were outstanding as of May 14, 2007.

TABLE OF CONTENTS

			Page
Glossary of Terms			3
Part I - Financial Information
Item 1.	Financial Statements.
	Condensed Consolidated Balance Sheets as of December 31, 2006 and March 31, 2007 (Unaudited)		6
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2006
		and 2007 (Unaudited)	8
	Condensed Consolidated Statement of Unitholders' Equity for the three months ended March 31,
		2007 (Unaudited)	9
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2006 and
		2007 (Unaudited)	10
	Notes to Condensed Consolidated Financial Statements (Unaudited)		12
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.		23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		33
Item 4.	Controls and Procedures.		34
Part II - Other Information
Item 1.	Legal Proceedings.		35
Item 1A.	Risk Factors.		35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		35
Item 3.	Defaults Upon Senior Securities.		35
Item 4.	Submission of Matters to a Vote of Security Holders.		35
Item 5.	Other Information.		35
Item 6.	Exhibits.		36

2

GLOSSARY OF TERMS

Bbl.  One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf.  Billion cubic feet.

Boe.  One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Boe/d.  Barrels of oil equivalent per day.

Btu.  British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well.  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploitation.  A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

MBbls.  One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe.  One thousand barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf.  One thousand cubic feet.

MMBbls.  One million barrels of crude oil or other liquid hydrocarbons.

MMBoe.  One million barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBtu.  One million British thermal units.

MMcf.  One million cubic feet.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs or natural gas liquids.  The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX.  New York Mercantile Exchange.

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Oil.  Crude oil, condensate and natural gas liquids.

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilotproject or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved developed non-producing or PDNP’s.  Proved oil and natural gas reserves that are developed behind pipe, shut-in or can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved reserves.  Proved oil and natural gas reserves are the estimated quantities of natural gas, crude oil and natural gas liquids that geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

Proved undeveloped drilling location.  A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs.  Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion.  The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserve acquisition cost.  The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.

R/P ratio (reserve life).  The reserves as of the end of a period divided by the production volumes for the same period.

Reserve replacement.  The replacement of oil and natural gas produced with reserve additions from acquisitions, reserve additions and reserve revisions.

Reserve replacement cost.  An amount per Boe equal to the sum of costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural gas prices in recent years have increased the economic life of reserves adding additional reserves with no required capital expenditures. On the other hand, increases in oil and natural gas prices have

4

 increased the cost of reserve purchases and reserves added through exploitation. The reserve replacement cost may not be indicative of the economic value added of the reserves due to differing lease operating expenses per barrel and differing timing of production.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized measure.  The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover.  Operations on a producing well to restore or increase production.

5

Part I – FINANCIAL INFORMATION

Item 1.  Financial Statements.

LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
	December 31,			March 31,
	2006			2007
Current assets:
Cash and cash equivalents	$	1,061,852		$	1,690,443
Accounts receivable, net:
Oil and natural gas		7,599,915			6,974,731
Joint interest owners		4,345,334			5,378,596
Affiliated entities and other (Note 4)		21,336			54,376
Fair value of oil and natural gas swaps (Note 6)		5,102,083			343,995
Prepaid expenses and other current assets		90,609			675,146
Total current assets		18,221,129			15,117,287
Oil and natural gas properties, at cost:
Proved oil and natural gas properties, at cost, using the
successful efforts method of accounting:		289,518,708			295,873,482
Unproved properties		68,275			78,742
Accumulated depletion, depreciation and amortization		(42,006,485	)		(47,124,125	)
		247,580,498			248,828,099
Other property and equipment, net of accumulated depreciaton and
amortization of $51,108 and $77,440, respectively		303,750			289,088
Deposit on pending acquisition		-			2,250,000
Operating rights, net of amortization of $295,314 and $441,877,
respectively		6,721,358			6,574,795
Other assets, net of amortization of $167,179 and $208,758, respectively		541,743			500,165
	$	273,368,478		$	273,559,434
See accompanying notes to condensed consolidated financial statements.

6

LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
	December 31,		March 31,
	2006		2007
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	2,931,627	$	479,606
Accrued oil and natural gas liabilities		5,881,612		4,413,088
Fair value of oil and natural gas swaps (Note 6)		-		244,098
Asset retirement obligation (Note 7)		553,579		533,579
Other		1,466,693		759,244
Total current liabilities		10,833,511		6,429,615
Long-term debt (Note 2)		115,800,000		4,000,000
Asset retirement obligation (Note 7)		5,939,201		6,000,590
Fair value of oil and natural gas swaps (Note 6)		2,006,547		6,692,806
Total liabilities		134,579,259		23,123,011
Commitments and contingencies (Note 5)
Unitholders' equity:
Limited partners' equity - 18,395,233 and 25,407,771 units issued
and outstanding at December 31, 2006 and March 31, 2007, respectively		138,653,452		250,311,651
General partner's equity (approximately 0.1%)		135,767		124,772
Total unitholders' equity		138,789,219		250,436,423
	$	273,368,478	$	273,559,434
See accompanying notes to condensed consolidated financial statements.

7

LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
	Three Months Ended
	March 31,
	2006			2007
Revenues:
Oil sales	$	7,439,840		$	12,405,812
Natural gas sales		2,995,417			3,525,874
Realized and unrealized loss on oil and natural gas swaps (Note 6)		(3,896,182	)		(7,222,669	)
Total revenues		6,539,075			8,709,017
Expenses:
Oil and natural gas production		2,676,767			4,739,552
Production and other taxes		738,157			993,573
General and administrative		955,856			1,827,136
Depletion, depreciation, amortization and accretion		2,387,866			5,295,056
Impairment of long-lived assets		-			89,970
Total expenses		6,758,646			12,945,287
Operating loss		(219,571	)		(4,236,270	)
Other income (expense):
Interest income		33,347			104,308
Interest expense (Note 2)		(1,444,762	)		(625,383	)
Equity in loss of partnership		(317,788	)		-
Other		14,910			680
Net loss	$	(1,933,864	)	$	(4,756,665	)
Loss per unit - basic and diluted	$	(0.17	)	$	(0.19	)
Weighted average number of units used in computing loss per unit - basic and diluted		11,141,915			24,519,601
See accompanying notes to condensed consolidated financial statements.

8

LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2007
(UNAUDITED)
									Total
	Number of		Limited			General			Unitholders'
	Limited Partner Units		Partner			Partner			Equity
Balance, December 31, 2006		18,395,233	$	138,653,452		$	135,767		$	138,789,219
Net proceeds from initial public
equity offering		6,900,000		121,554,464			-			121,554,464
Compensation expense on unit
options granted to employees		-		62,484			-			62,484
Compensation expense on restricted
unit awards issued to employees		-		85,164			-			85,164
Vesting of Restricted Units		17,538		-			-			-
Units issued to Greg McCabe
in exchange for oil and
natural gas properties		95,000		2,270,500			-			2,270,500
Distributions to unitholders, $0.41 per unit		-		(7,561,174	)		(7,569	)		(7,568,743	)
Net loss		-		(4,753,239	)		(3,426	)		(4,756,665	)
Balance, March 31, 2007		25,407,771	$	250,311,651		$	124,772		$	250,436,423
See accompanying notes to condensed consolidated financial statements.

9

LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Three Months Ended March 31,
	2006			2007
Cash flows from operating activities:
Net loss	$	(1,933,864	)	$	(4,756,665	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		2,387,866			5,295,056
Amortization of debt issuance costs		228,092			41,578
Impairment of long-lived assets		-			89,970
Loss on oil and natural gas swaps		3,896,182			7,222,669
Equity in loss of partnership		317,788			-
Amortization of unit-based compensation		14,080			147,648
Changes in assets and liabilities
(Increase) decrease in accounts receivable, oil and natural gas		(789,284	)		625,184
Increase in accounts receivable, joint interest owners		(135,790	)		(1,033,262	)
Increase in accounts receivable, other		(930,761	)		(33,040	)
Increase in other current assets		(474,720	)		(584,537	)
Decrease in accounts payable		(237,711	)		(2,452,021	)
Decrease in accrued oil and natural gas liabilities		(793,966	)		(1,468,524	)
Increase in due to affiliates		1,059,308			-
Increase (decrease) in other current liabilities		2,198,405			(773,576	)
Total adjustments		6,739,489			7,077,145
Net cash provided by operating activities		4,805,625			2,320,480
Cash flows from investing activities:
Investment in oil and natural gas properties		(9,491,019	)		(4,081,716	)
Increase in deposit on pending acquisition		-			(2,250,000	)
Investment in other equipment		(32,437	)		(11,670	)
Collection of notes receivable		924,441			-
Net cash settlements on oil and natural gas swaps		1,396,936			2,465,776
Net cash used in investing activities		(7,202,079	)		(3,877,610	)
Cash flows from financing activities:
Proceeds from long-term debt		65,800,000			6,000,000
Payments of long-term debt		(67,189,791	)		(117,800,000	)
Payments of debt issuance costs		(150,204	)		-
Proceeds from issuance of units, net		78,728,631			121,554,464
Redemption of Founding Investors' units		(69,938,000	)		-
Dividend - reimbursement of offering costs paid by MBN Management LLC		(1,200,229	)		-
Capital contributed by owner		19,356			-
Cash not acquired in Legacy formation transactions		(3,104,304	)		-
Distributions to unitholders		(2,296,914	)		(7,568,743	)
Net cash provided by financing activities		668,545			2,185,721
Net increase (decrease) in cash and cash equivalents		(1,727,909	)		628,591
Cash and cash equivalents, beginning of period		1,954,923			1,061,852
Cash and cash equivalents, end of period	$	227,014		$	1,690,443
See accompanying notes to condensed consolidated financial statements.

10

LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued
(UNAUDITED)
	Three Months Ended March 31,
	2006			2007
Non-Cash Investing and Financing Activities:
Asset retirement obligation costs and liabilities	$	1,467,241		$	-
Asset retirement obligations associated with property acquisitions	$	-		$	13,025
Non-controlling interests' share of net financing costs of MBN
Properties LP capitalized to oil and natural gas properties	$	164,202		$	-
Units issued to MBN Properties LP in exchange for the
non-controlling interests' share of oil and natural gas properties	$	31,743,934		$	-
Units issued to Brothers Group in exchange for:
Oil and natural gas properties	$	105,298,794		$	-
Other property and equipment	$	107,275		$	-
Units issued to H2K Holdings Ltd. in exchange for oil and
natural gas properties	$	1,419,483		$	-
Oil and natural gas hedge liabilities assumed from the
Brothers Group and H2K Holdings Ltd.	$	3,147,152		$	-
Units issued in exchange for oil and
natural gas properties	$	-		$	2,270,500
Deemed dividend to Moriah Group owners for accounts not acquired
in Legacy formation transaction:
Accounts receivable, oil and natural gas	$	4,248,157		$	-
Accounts receivable, joint interest owners	$	249,627		$	-
Accounts receivable, other	$	539,968		$	-
Other assets	$	891,300		$	-
Accounts payable	$	(213,941	)	$	-
Accrued oil and natural gas liabilities	$	(1,520,709	)	$	-
Due to affiliates	$	(1,254,215	)	$	-
Other liabilities	$	(2,166,276	)	$	-
See accompanying notes to condensed consolidated financial statements.

 

11

LEGACY RESERVES LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1)  Organization, Basis of Presentation and Description of Business

Legacy Reserves LP and its affiliated entities are referred to as Legacy or LRLP in these financial statements.

Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

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 less than a 0.1% general partner interest in LRLP.

On March 15, 2006, Legacy, 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 3) and (3) redeemed 4.4 million units for $69.9 million from the Brothers Group, H2K Holdings and MBN Properties, who, along with the Moriah Group, are its “Founding Investors”. The Moriah Group was 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 was reflected retroactively at carryover basis in these condensed consolidated financial statements. The accounts presented for periods prior to the Legacy Formation transaction are those of the Moriah Group.

On January 18, 2007, Legacy closed its initial public offering (“IPO”) of 6,900,000 limited partnership units at an IPO price of $19.00 per unit. Net proceeds to the partnership after underwriting discounts and estimated offering expenses were approximately $122 million, which was used to repay all indebtedness outstanding under the partnership’s credit facility and for general partnership purposes.

Significant information regarding rights of the limited partners includes the following:

 • Right to receive, within 45 days after the end of each quarter, distributions of available cash, if distributions are declared.

 • 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 provided that a unit majority has elected a successor general partner.

 • 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.

12

All significant intercompany accounts and transactions have been eliminated. The Moriah Group consolidated MBN Properties LP as a variable interest entity under FASB Interpretation Number “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.

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 undrilled leasehold.

These condensed consolidated financial statements as of March 31, 2007 and for the three months ended March 31, 2007 and 2006 are unaudited.  In the opinion of management, such financial statements include the adjustments and accruals which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in these financial statements for and as of the three months ended March 31, 2007 and 2006.

(2)  Credit Facility

On July 29, 1999, the Moriah Group entered into a Credit Facility (the “Agreement”) that permitted borrowings up to the lesser of (i) the borrowing base, or (ii) $20 million. 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 New Facility. All amounts outstanding under the New Facility 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 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 MBN Facility. All amounts outstanding under the MBN Facility at March 15, 2006 were repaid in full on that date as part of the formation transactions.

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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. The terms of the Legacy Facility permits borrowings in the lesser amount of (i) the borrowing base, or (ii) $300 million. The borrowing base under the Legacy Facility, initially set at $130 million, is re-determined every six months and will be adjusted based upon changes in the fair market value of Legacy’s oil and natural gas assets. Interest on the Legacy Facility is payable monthly and is charged in accordance with Legacy’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 October 16, 2006, Legacy’s bank group reaffirmed its $130 million borrowing base. 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 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 March  31, 2007, Legacy had outstanding borrowings of $4.0 million at an interest rate of 8.25%, Legacy had approximately $125.7 million of availability remaining under the Legacy Facility as of March 31, 2007. For the three month period ended March 31, 2007, Legacy paid $773,306 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, 2006 and March 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 March 31, 2007:

	December 31,		March 31,
	2006		2007
Legacy Facility- due March 2010	$	115,800,000	$	4,000,000

(3)  Acquisitions

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 the quarter ended March 31, 2006.

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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
Other investors		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 8).

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:

15

	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 natural 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					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
MBN Properties LP purchase price to allocate
to oil and natural gas properties				$	32,688,375
Units related to purchase of non-controlling interest		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 $5.7 million. The conveyance of the leases was 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 have been included from their acquisition on June 29, 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

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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 are being 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 have been included from the acquisition on June 29, 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 have been included from their acquisition on July 31, 2006.

Pro Forma Operating Results

The following table reflects the unaudited pro forma results of operations as though the Formation Transactions and the Farmer Field, South Justis Unit and Kinder Morgan acquisitions had each occurred on January 1, 2006. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

 

	March 31,
	2006
Revenues, excluding hedging gains and losses	$	13,254,062
Revenues, net of hedging gains and losses	$	9,357,880
Net income	$	(973,952	)
Earnings per unit - basic and diluted:
Net income	$	(0.05	)
Units used in computing earnings per unit		18,386,482

(4)  Related Party Transactions

Cary Brown and Dale Brown, as owners of the Moriah Group, and the Brothers Group own a combined non-controlling 18% interest as limited partners in the partnership which owns the building that Legacy occupies. Monthly rent is $6,838, 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 $444,233 and $0 for the quarters ended March 31, 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 March 31, 2006, Brothers Production Company Inc. provided $47,236 of transition administrative services to Legacy.

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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 $16,173 and $32,945 for the quarters ended Match 31, 2006 and 2007, respectively.

Legacy has a receivable of $42,444 from one of its employees at March 31, 2007 related to federal income tax withholding on the vesting of a portion of his restricted units of Legacy Reserves LP. Any distributions on his unvested units are treated as compensation subject to withholding.

(5)  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.

(6)  Oil and Natural Gas Swaps

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 hedge 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 hedge 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 three months ended March 31, 2006 and 2007, Legacy included in revenue realized and unrealized losses related to its oil and natural gas derivatives. The impact on total revenue from hedging activities was as follows:

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	Three Months Ended
	March 31,
	2006			2007
Crude oil derivative contract settlements	$	(120,614	)	$	1,202,034
Natural gas derivative contract settlements		1,517,550			1,263,742
Unrealized change in fair value - oil contracts		(8,293,478	)		(5,087,147	)
Unrealized change in fair value - natural gas contracts		3,000,360			(4,601,298	)
	$	(3,896,182	)	$	(7,222,669	)

As of March 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:

	Annual		Average		Price
Calendar Year	Volumes (Bbls)		Price per Bbl		Range per Bbl
2007		572,232	$	67.32	$	64.15 - $75.70
2008		715,649	$	67.23	$	62.25 - $73.45
2009		660,613	$	64.96	$	61.05 - $71.40
2010		575,045	$	62.94	$	60.15 - $67.80
2011		44,640	$	67.33	$	67.33

As of March 31, 2007, Legacy had the following NYMEX Henry Hub and ANR-OK  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
2007		1,353,612	$	8.95	$	7.35 - $10.01
2008		1,675,374	$	8.46	$	7.59 - $10.58
2009		1,556,354	$	8.27	$	7.64 - $10.18
2010		1,353,899	$	7.94	$	7.36 - $9.73
2011		130,000	$	7.23	$	7.23

As of March 31, 2007, Legacy had the following gas basis swaps in which it receives 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 Legacy receives for its natural gas sales follow Waha more closely than NYMEX:

	Annual		Basis
Calendar Year	Volumes (Mcf)		Differential per Mcf
2007		1,170,000	$	(0.88)
2008		1,422,000	$	(0.84)
2009		1,320,000	$	(0.68)
2010		1,200,000	$	(0.57)

As of March 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		Price
Calendar Year	Volumes (Gal)		per Gal
2007		1,909,656	$	1.15
2008		2,509,248	$	1.15
2009		2,265,480	$	1.15

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 (7)  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 year ended December 31, 2006 and three months ended March 31, 2007.

	December 31,			March 31,
	2006			2007
Asset retirement obligation - beginning of period	$	2,302,147		$	6,492,780
Liabilities incurred in Legacy formation		1,467,241			-
Liabilities incurred with properties acquired		1,888,954			13,025
Liabilities incurred with properties drilled		22,882			-
Liabilities settled during the period		(213,343	)		(66,128	)
Current period accretion		242,432			94,492
Current period revisions to oil and natural gas properties		782,467			-
Asset retirement obligation - end of period	$	6,492,780		$	6,534,169

(8)  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 March  31, 2007 grants of awards covering 274,000 units have been made. The plan is administered by the compensation committee of the board of directors of Legacy’s general partner. SFAS No. 123(R) 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. Since Legacy had no restricted or unit option awards prior to March 15, 2006, there were no adoption or transition consequences as contemplated by SFAS No. 123(R). Pursuant to the provisions of SFAS 123(R), Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at March 31, 2007 does not include 47,578 units related to unvested restricted unit awards.

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 $14,080 and $85,164 for the three months ended March, 31, 2006 and 2007, respectively. As of March 31, 2007, there was a total of $751,768 of unrecognized compensation costs related to the non-vested portion of these restricted units. At March 31, 2007, this cost was expected to be recognized over a weighted-average period of 2.4 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 general partner’s board. The value of each unit was $17.00 at the time of grant.

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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. All options granted in 2006 expire five years from the grant date and are exercisable when they vest. During the three month period ended March 31, 2007, Legacy issued 14,000 unit option awards to officers and employees which vest ratably over a three-year period. All options granted in 2007 expire five years from the grant date and are exercisable when they vest.

For the three-month period ended March 31, 2007, Legacy recorded $62,484 of compensation expense based on its use of the Black-Scholes model to estimate the grant-date fair value of these unit option awards. As of March 31, 2007, there was a total of $522,711 of unrecognized compensation costs related to the non-vested portion of these unit option awards. At March 31, 2007, this cost was expected to be recognized over a weighted-average period of 2.08 years. Compensation expense is based upon straight line amortization of the grant-date fair value over the vesting period of the underlying unit option. Since Legacy is a newly public company and has minimal trading history, it has used an estimated volatility factor of approximately 37% based upon the historical trends of a representative group of publicly-traded companies in the energy industry and employed the fair value method to estimate the grant-date fair value to be amortized over the vesting periods of the unit options awarded. In the absence of historical data, Legacy has assumed an estimated forfeiture rate of 5%. As required by SFAS No. 123(R), the Company will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $1.64 per unit.

A summary of option activity for the three months ended March 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		14,000	$	20.97
Exercised		-		-
Forfeited		-		-
Outstanding at March 31, 2007		274,000	$	17.21	4.0 years
Options exercisable at March 31, 2007		62,667	$	17.00	-

The following table summarizes the status of the Legacy’s non-vested unit 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		14,000			4.26
Vested		(62,667	)		2.62
Forfeited		-			-
Non-vested at March 31, 2007		211,333		$	2.78

Legacy has used a weighted-average risk free interest rate of 4.9% in its Black-Scholes calculation of grant-date fair value, which approximates the U.S. Treasury interest rates at the time of the grant whose term is consistent with the expected life of the unit options. Expected life represents the period of time that options are expected to be outstanding and is based on Legacy’s best estimate. The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model.

21

	Three Months Ended
	March 31,
	2007
Expected life (years)		4
Annual interest rate		4.9	%
Annual distribution rate per unit	$	1.64
Volatility		37	%

 (9)  Subsequent Events

On March 20, 2007, Legacy entered into a definitive purchase agreement to acquire certain oil and natural gas producing properties from Nielson & Associates, Inc., for an aggregate purchase price of $45 million, subject to customary purchase price adjustments, in which we paid $30 million in cash with the remainder paid with the issuance of 611,247 units at closing. The properties are located in the East Binger (Marchand) Unit in Caddo County, Oklahoma. The acquisition closed on April 16, 2007. This acquisition will be accounted for as a purchase of oil and natural gas assets.

On March 29, 2007, Legacy entered into a definitive purchase agreement to acquire certain oil and natural gas producing properties from Ameristate Exploration, LLC, for an aggregate purchase price of $5.5 million, subject to customary purchase price adjustments, which was paid in cash at closing. The properties are located in Lea and Eddy counties of New Mexico. The acquisition closed on May 1, 2007. This acquisition will be accounted for as a purchase of oil and natural gas assets.

On April 10, 2007, Legacy entered into a definitive purchase agreement to acquire certain oil and natural gas producing properties from Terry S. Fields for an aggregate purchase price of $15.3 million, subject to customary purchase price adjustments, to be paid in cash at closing. The properties are located in Midland, Reagan and Upton counties in west Texas. The acquisition is subject to customary closing conditions and is expected to close in mid-May 2007. This acquisition will be accounted for as a purchase of oil and natural gas assets.

On April 17, 2007, the board of directors of Legacy’s general partner declared a $0.41 per unit cash distribution payable to all unitholders of record on April 30, 2007. This distribution will be paid on May 14, 2007.

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 May 7, 2007, Legacy entered into a definitive purchase agreement to acquire certain oil and natural gas producing properties from private parties for a purchase price of $12.9 million, subject to customary purchase price adjustments, to be paid at closing. The properties are located in the Slaughter and Rocker A fields in Cochran and Garza counties, respectively, in West Texas. The acquisition is subject to customary closing conditions and is expected to close during June. This acquisition will be accounted for as a purchase of oil and natural gas assets.

22

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Statement Regarding Forward Looking Information

 This document contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

      •           business strategy;

      •           financial strategy;

      •           drilling locations;

      •           oil and natural gas reserves;

      •           technology;

      •           realized oil and natural gas prices;

      •           production volumes;

      •           lease operating expenses, general and administrative costs and finding and development costs;

      •           future operating results; and

      •           plans, objectives, expectations and intentions.

 All of these types of statements, other than statements of historical fact included in this document, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

 The forward-looking statements contained in this document are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this document are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in Legacy Reserves’ Annual Report on Form 10-K for the year ended December 31, 2006 in Item 1A. under “Risk Factors”. The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We were formed in October 2005. Upon completion of our private equity offering and as a result of the related formation transactions on March 15, 2006, we acquired oil and natural gas properties and business operations from our Founding Investors and three charitable foundations (“Legacy Formation”). Although we were the surviving entity for legal purposes, the formation transactions are treated as a purchase with Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being considered, on a combined basis, as the acquiring entity for accounting purposes. Therefore, the accounts reflected in our historical financial statements prior to March 15, 2006 are those of the Moriah Group.

On January 18, 2007, we closed our IPO of 6,900,000 units representing limited partner interests at an IPO 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 the $115.8 million of indebtedness outstanding under our credit facility and for general partnership purposes.

The Moriah Group owned and operated oil and natural gas producing properties located primarily in the Permian Basin of West Texas and southeast New Mexico. The Moriah Group included the accounts of Moriah Resources, Inc. as the general partner of Moriah Properties, Ltd., the oil and natural gas interests individually owned by Dale A. and Rita Brown until October 1, 2005 when those interests were transferred to DAB Resources, Ltd., DAB Resources, Ltd. and the accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP as a variable interest entity with the portion of net income (loss) applicable to the other owners’ equity interests eliminated through a non-controlling interest adjustment. Although MBN Management, LLC, the general partner of MBN Properties LP, is also a variable interest entity, it was accounted for by the Moriah Group using the equity method.

Because of our rapid growth through acquisitions and development of properties, historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

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The operating results of the properties acquired in the Formation Transaction are included in the results of operations from March 15, 2006, the operating results of the South Justis Unit properties and the Farmer Field properties acquired on June 29, 2006 have been included from July 1, 2006 and the operating results of the Kinder Morgan properties have been included from August 1, 2006.

Acquisitions have been financed with a combination of proceeds from bank borrowings and issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and exploiting the acquired properties and evaluating potential add-on acquisitions.

Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future.

Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs. Given the inherent volatility of oil and natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on sales price assumptions which historically have been lower than the average sales prices received. We focus our efforts on increasing oil and natural gas production and reserves while controlling costs at a level that is appropriate for long-term operations.

 We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary (CO 2) recovery methods to repressure the reservoir and recover additional oil, drilling to find additional reserves, restimulating existing wells and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through acquisitions and exploitation projects. Our ability to add reserves through acquisitions and exploitation projects is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and personnel.

Our revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. As set forth under “Cash Flow from Operations” below, we have hedged a significant portion of our expected production, which allows us to mitigate, but not eliminate, oil and natural gas price risk. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ability to execute our capital investment programs and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination to our borrowing base under our credit facility.

Legacy does not specifically designate derivative instruments as cash flow hedges; therefore, the mark-to-market adjustment reflecting the unrealized gain or loss associated with these instruments is recorded in current earnings.

Production and Operating Costs Reporting

We strive to increase our production levels to maximize our revenue and cash available for distribution. Additionally, we continuously monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we continuously monitor our production and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold.

Such costs include, but are not limited to, the cost of electricity to lift produced fluids, chemicals to treat wells, field personnel to monitor the wells, well repair expenses to restore production, well workover expenses intended to increase production and ad valorem taxes. We incur and separately report severance taxes paid to the states and counties in which our properties are located. These taxes are reported as production taxes and are a percentage of oil and natural gas revenue. Ad valorem taxes are a percentage of property valuation. Gathering and transportation costs are generally borne by the purchasers of our oil and natural gas as the price paid for our products reflects these costs.

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Operating Data

The following table sets forth selected financial and operating data of Legacy for the periods indicated.

	Three Months Ended March 31,
	2006 (a)			2007
Revenues:
Oil sales	$	7,439,840		$	12,405,812
Natural gas sales		2,995,417			3,525,874
Realized gain (loss) on oil swaps		(120,614	)		1,202,034
Realized gain on natural gas swaps		1,517,550			1,263,742
Unrealized loss on oil swaps		(8,293,478	)		(5,087,147	)
Unrealized gain (loss) on natural gas swaps		3,000,360			(4,601,298	)
Total revenue	$	6,539,075		$	8,709,017
Expenses:
Oil and natural gas production	$	2,676,767		$	4,739,552
Production and other taxes	$	738,157		$	993,573
General and administrative	$	955,856		$	1,827,136
Depletion, depreciation, amortization  and accretion	$	2,387,866		$	5,295,056
Production:
Oil - barrels		129,011			230,852
Natural gas - Mcf		433,960			588,346
Total (Boe)		201,338			328,910
Average daily production (Boe/d)		2,237			3,655
Average sales price per unit (including heges) (b):
Oil price per barrel	$	(7.55	)	$	36.91
Natural gas price per Mcf	$	17.31		$	0.32
Combined (per Boe)	$	32.48		$	26.48
Average sales price per unit (including realized hedge gains/losses) (c):
Oil price per barrel	$	56.73		$	58.95
Natural gas price per Mcf	$	10.40		$	8.14
Combined (per Boe)	$	58.77		$	55.93
Average sales price per unit (excluding hedges):
Oil price per barrel	$	57.67		$	53.74
Natural gas price per Mcf	$	6.90		$	5.99
Combined (per Boe)	$	51.83		$	48.44
NYMEX oil index prices per barrel:
Beginning of Quarter	$	61.04		$	61.05
End of Quarter	$	66.63		$	65.87
NYMEX gas index prices per Mcf:
Beginning of Quarter	$	11.18		$	6.30
End of Quarter	$	7.21		$	7.73
Average unit costs per Boe:
Production costs, excluding production and other taxes	$	13.29		$	14.41
Production and other taxes	$	3.67		$	3.02
General and administrative	$	4.75		$	5.56
Depletion, depreciation, amortization and accretion	$	11.86		$	16.10

(a)   Reflects the production and operating results of the oil and natural gas properties acquired in the March 15, 2006 formation transaction.

(b)   Includes both the realized and unrealized hedge gains and losses from Legacy’s oil and natural gas swaps. Since Legacy does not specifically designate its commodity derivative instruments as cash flow hedges, current earnings reflect a mark-to-market adjustment for commodity derivatives which will be settled in future periods.

(c)   Includes only the realized hedge gains (losses) from Legacy’s oil and natural gas swaps.

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Results of Operations

Three-Month Period Ended March  31, 2007 Compared to Three-Month Period Ended March 31, 2006

Legacy’s revenues from the sale of oil were $12.4 million and $7.4 million for the three month periods ended March 31, 2007 and 2006, respectively. Legacy’s revenues from the sale of natural gas were $3.5 million and $3.0 million for the three month periods ended March 31, 2007 and 2006, respectively. The $5.0 million increase in oil revenues reflects an increase in oil production of 102 MBbls (79%) due primarily to Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 Legacy Formation transactions, and the South Justis, Farmer Field and Kinder Morgan acquisitions while the realized price excluding the effects of hedging decreased $3.93 per Bbl. The $0.5 million increase in natural gas revenues reflects an increase in natural gas production of approximately 154 MMcf (36%) due primarily to the Legacy Formation, while the realized price per Mcf excluding the effects of hedging decreased $0.91 per Mcf. Since the Legacy Formation occurred on March 15, 2006, Legacy’s revenues and related volumes for the three month period ended March 31, 2006 do not reflect the 50 MBbls and 119 MMcf produced by the oil and natural gas properties acquired in that transaction from January 1, 2006 to March 15, 2006.

For the three-month period ended March 31, 2007, Legacy recorded $7.2 million of net losses on oil and natural gas swaps comprised of realized gains of $2.5 million from net cash settlements of oil and natural gas swap contracts and net unrealized losses of $9.7 million. Legacy had unrealized net losses from its oil swaps because the fixed prices of its oil swap contracts were below the NYMEX index prices at March 31, 2007. As a point of reference, the NYMEX price for light sweet crude oil for the near-month close at March 31, 2007 was $65.87 per Bbl, a price which is greater than the average contract prices of Legacy’s outstanding oil swap contracts. Due to the increase in oil prices during the quarter, the differential between Legacy’s fixed price oil swaps and NYMEX increased, resulting in losses for the quarter. Legacy had unrealized net losses from its natural gas swaps because the fixed prices of its natural gas swap contracts were below the NYMEX index prices at March 31, 2007. In addition, the NYMEX price for natural gas for the near-month close at March 31, 2007 was $7.73 per MMbtu, a price which is greater than the average contract prices of Legacy’s outstanding natural gas swap contracts. Due to the increase in natural gas prices during the quarter, the differential between Legacy’s fixed price natural gas swaps and NYMEX increased, resulting in losses for the quarter. For the three month period ended March 31, 2006, Legacy recorded $3.9 million of net losses on oil and natural gas swaps comprised of a realized loss of $121,000 from net cash settlements of oil swap contracts, a realized gain of $1.5 million from net cash settlements of natural gas swap contracts, a net unrealized loss of $8.3 million on oil swap contracts, due to the increase in oil prices during the quarter which increased the differential between the NYMEX oil index price and our fixed price oil swaps, and a net unrealized gain of $3.0 million on natural gas swap contracts, due to the decrease in natural gas prices which increased the differential between the NYMEX natural gas index price and our fixed price natural gas swaps. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods.

Legacy’s oil and natural gas production expenses, excluding production and other taxes, increased to $4.7 million ($14.41 per Boe) for the three month period ended March 31, 2007, from $2.7 ($13.29 per Boe) million for the three month period ended March 31, 2006. Production expenses increased primarily because of (i) $1.3 million related to the Legacy Formation and, (ii) $0.8 million related to the South Justis, Farmer Field and Kinder Morgan acquisitions. In addition, the increase in production costs per Boe is consistent with industry-wide costs increases, particularly those related to oil operations that require lifting produced oil and water or involve enhanced recovery projects.

Legacy’s production and other taxes were $1.0 million and $0.7 million for the three month periods ended March 31, 2007 and 2006, respectively. Production and other taxes increased primarily because of approximately $0.3 million of taxes related to the Legacy Formation. The decrease in production and other taxes per Boe is primarily due to the decrease in realized prices excluding hedges. As production and other taxes are a function of price and volume, the decrease in unit cost is consistent with the decrease in realized prices.

Legacy’s general and administrative expenses were $1.8 million and $1.0 million for the three month periods ended March 31, 2007 and 2006, respectively. General and administrative expenses increased approximately $0.8 million between periods primarily due to increased employee costs related to business expansion and approximately $423,000 of costs incurred in connection with the preparation of the 2006 federal income tax return and related Form K-1’s.

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Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $5.3 million and $2.4 million for the three month periods ended March 31, 2007 and 2006, respectively, reflecting primarily $1.1 million of DD&A related to the Legacy Formation and $0.6 million to recent acquisitions. In addition, the increase in DD&A expense per Boe reflects the higher cost basis of the producing oil and natural gas properties acquired in the Formation Transaction and in the three acquisitions of oil and natural gas properties in the second and third quarters of 2006.

Impairment expense was $89,970 for the three month period ended March 31, 2007 involving five separate producing fields. The impairment is primarily due to additional costs incurred during the quarter ended March 31, 2007 on fields from which the future estimated production revenues did not exceed these costs.

Legacy recorded interest income of $104,308 for the three-month period ended March 31, 2007 and $33,347 for the three-month periods ended March 31, 2006. The increase of $70,961 is a result of higher average cash balances for the current period.

Interest expense was $0.6 million and $1.4 million for the three-month periods ended March 31, 2007 and 2006, respectively, reflecting lower average borrowings and higher average interest rates in the current period. Legacy repaid the entire $115.8 million outstanding under its revolving credit facility at the close of its initial public offering on January 18, 2007.

Legacy recorded equity in loss of partnership of $317,788 for the three-month period ended March 31, 2006. The recorded equity in loss of partnership was related to Legacy’s investment in MBN Management, LLC, which was formed in July 2005. Legacy did not acquire any interest in MBN Management, LLC as part of the Legacy Formation. Accordingly, no such loss was incurred in the current period.

Capital Resources and Liquidity

Legacy’s primary sources of capital and liquidity have been bank borrowings, cash flow from operations, its private offering in March 2006 and its initial public offering in January 2007. To date, Legacy’s primary use of capital has been for acquisitions, repayment of bank borrowings and exploitation of oil and natural gas properties.

As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and planned capital expenditures. Our future success in growing reserves and production will be highly dependent on capital resources available to us and our success in acquiring and exploiting additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we would need to borrow additional amounts under our credit facility, if available, or obtain additional debt or equity financing. Our credit facility imposes certain restrictions on our ability to obtain additional debt financing. Based upon current oil and natural gas price expectations for the year ending December 31, 2007, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our credit facility will provide us sufficient working capital to meet our planned capital expenditures of $10.3 million and planned cash distributions of $38.9 million, which reflects the $7.6 million of distributions paid in the first quarter of 2007 and $10.4 million of planned distributions during each of the second, third and fourth quarters of 2007. Please read “— Financing Activities — Our Revolving Credit Facility.”

On May 3, 2007, Legacy’s bank group increased Legacy’s borrowing base to $150 million as part of the semi-annual re-determination.

Cash Flow from Operations

Legacy’s net cash provided by operating activities was $2.3 million and $4.8 million for the three month periods ended March 31, 2007 and 2006, respectively, with the 2007 period being favorably impacted by higher sales volumes, offset by the higher working capital needs of our growing business.

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Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on our ability to maintain and increase production through acquisitions and exploitation projects, as well as the prices of oil and natural gas.

We enter into hedging arrangements to reduce the impact of oil and natural gas price volatility on our operations. Currently, we use swaps to hedge NYMEX oil and natural gas prices, which do not include the additional net discount that we typically realize in the Permian Basin. At March 31, 2007, we had in place oil and natural gas swaps covering significant portions of our estimated 2007 through 2011 oil and natural gas production. We have hedged approximately 70% of our remaining expected oil and natural gas production for 2007. We have also hedged approximately 63% of our currently expected oil and natural gas production for 2008 through 2010 from existing total proved reserves.

By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.

The following tables summarize, for the periods indicated, our oil and natural gas swaps currently in place through December 31, 2011. We use swaps as our mechanism for hedging commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to hedge the floating prices we are paid by purchasers of our oil and natural gas. These transactions are settled based upon the NYMEX price of oil at Cushing, Oklahoma, and NYMEX price of natural gas at Henry Hub  and ANR-OK on the average of the three final trading days of the month and settlement occurs on the fifth day of the production month.

	Annual		Average		Price
Calendar Year	Volumes (Bbls)		Price per Bbl		Range per Bbl
2007		572,232	$	67.32	$	64.15 - $75.70
2008		715,649	$	67.23	$	62.25 - $73.45
2009		660,613	$	64.96	$	61.05 - $71.40
2010		575,045	$	62.94	$	60.15 - $67.80
2011		44,640	$	67.33	$	67.33

	Annual		Average		Price
Calendar Year	Volumes (MMBtu)		Price per MMBtu		Range per MMBtu
2007		1,353,612	$	8.95	$	7.35 - $10.01
2008		1,675,374	$	8.46	$	7.59 - $10.58
2009		1,556,354	$	8.27	$	7.64 - $10.18
2010		1,353,899	$	7.94	$	7.36 - $9.73
2011		130,000	$	7.23	$	7.23

In July 2006, we entered into basis swaps to receive floating NYMEX prices less a fixed basis differential and pay prices based 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. The basis swaps thereby provide a better match between our natural gas sales and the settlement payments on our natural gas swaps. The following table summarizes, for the periods indicated, our NYMEX basis swaps currently in place through December 31, 2010.

	Annual		Basis
Calendar Year	Volumes (Mcf)		Differential per Mcf
2007		1,170,000	$	(0.88)
2008		1,422,000	$	(0.84)
2009		1,320,000	$	(0.68)
2010		1,200,000	$	(0.57)

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 On March 30, 2007, we entered into natural gas liquids swaps to hedge the impact of volatility in the spot prices of natural gas liquids.  These swaps hedge the spot prices for ethane, propane, iso-butane, normal butane and natural gasoline tracked on the Mont Belvieu, Non-Tet OPIS exchange. We entered into these swaps as aniticipatory asset hedges related to our acquisition of the East Binger (Marchand) Unit in Caddo County, Oklahoma.  The following table summarizes, for the periods indicated, our Mont Belvieu, Non-Tet Opis natural gas liquids swaps currently in place through December 31, 2009.

	Annual		Price
Calendar Year	Volumes (Gal)		per Gal
2007		1,909,656	$	1.15
2008		2,509,248	$	1.15
2009		2,265,480	$	1.15

Investing Activities — Acquisitions and Capital Expenditures

Legacy’s cash capital expenditures were $4.1 million for the three month period ended March 31, 2007. The total includes $.4 million for acquisition of oil and natural gas properties in small acquisitions and $3.7 million of exploitation projects.

Legacy’s cash capital expenditures were $9.5 million for the three month period ended March 31, 2006. The total for the three month period ended March 31, 2006 includes $7.7 million paid to three charitable foundations in the Legacy Formation for oil and natural gas properties.

We currently anticipate that our drilling budget, which predominantly consists of drilling, recompletion and refracture stimulation projects and one tertiary (CO2) recovery project will be $10.3 million for the year ending December 31, 2007. Our borrowing capacity under our revolving credit facility is $103.7 million as of May 14, 2007. The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based upon current oil and natural gas price expectations for the year ending December 31, 2007, we anticipate that we will have sufficient sources of working capital, including our cash flow from operations and available borrowing capacity under our credit facility, to meet our cash obligations including our planned capital expenditures of $10.3 million and planned cash distributions of $38.9 million for the year ending December 31, 2007. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Initial Public Offering

On January 18, 2007, Legacy completed its IPO of 6,900,000 units representing limited partner interests at an IPO price of $19.00 per unit. Net proceeds to Legacy after underwriting discounts and estimated offering expenses were approximately $122 million, all of which were used to repay in full the indebtedness outstanding under Legacy’s credit facility and for general partnership purposes.

Our Revolving Credit Facility

At the closing of our private equity offering on March 15, 2006, we entered into a new, four-year, $300 million revolving credit facility with BNP Paribas as administrative agent. Our obligations under the credit facility are secured by mortgages on more than 80% of our oil and gas properties as well as a pledge of all of our ownership interests in our operating subsidiaries. The amount available for borrowing at any one time is limited to the borrowing base, which was initially set at $130 million and increased on May 3, 2007 to $150 million. The borrowing base is subject to semi-annual

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re-determinations on April 1 and October 1 of each year. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. We also have the right, once during each calendar year, to redetermine the borrowing base upon the proposed acquisition of certain oil and gas properties where the purchase price is greater than 10% of the borrowing base. Any increase in the borrowing base requires the consent of all the lenders and any decrease in the borrowing base must be approved by the lenders holding 662/3 % of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility. If the required lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 662/3 % of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility so long as it does not increase the borrowing base then in effect. Outstanding borrowings in excess of the borrowing base must be prepaid, and, if mortgaged properties represent less than 80% of total value of oil and gas properties evaluated in the most recent reserve report, we must pledge other oil and natural gas properties as additional collateral.

We may elect that borrowings be comprised entirely of alternate base rate (ABR) loans or Eurodollar loans. Interest on the loans is determined as follows:

•  with respect to ABR loans, the alternate base rate equals the higher of the prime rate or the Federal funds effective rate plus 0.50%, plus an applicable margin between 0% and 0.375%, or

•  with respect to any Eurodollar loans for any interest period, the London interbank rate, or LIBOR plus an applicable margin between 1.25% and 1.875% per annum.

Interest is generally payable quarterly for ABR loans and on the last day of the applicable interest period for any Eurodollar loans.

Our revolving credit facility also contains various covenants that limit our ability to:

•  incur indebtedness;

•  enter into certain leases;

•  grant certain liens;

•  enter into certain swaps;

•  make certain loans, acquisitions, capital expenditures and investments;

•  make distributions other than from available cash;

•  merge, consolidate or allow any material change in the character of its business; or

•  engage in certain asset dispositions, including a sale of all or substantially all of our assets.

Our credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

•  consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization and other similar charges excluding unrealized gains and losses under SFAS No. 133, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0; and

•  consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of oil, natural gas and interest rate swaps.

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If an event of default exists under our revolving credit facility, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following would be an event of default:

•  failure to pay any principal when due or any reimbursement amount, interest, fees or other amount within certain grace periods;

•  a representation or warranty is proven to be incorrect when made;

•  failure to perform or otherwise comply with the covenants or conditions contained in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

•  default by us on the payment of any other indebtedness in excess of $1.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

•  bankruptcy or insolvency events involving us or any of our subsidiaries;

•  the loan documents cease to be in full force and effect our failing to create a valid lien, except in limited circumstances;

•  a change of control, which will occur upon (i) the acquisition by any person or group of persons of beneficial ownership of more than 35% of the aggregate ordinary voting power of our equity securities, (ii) the first day on which a majority of the members of the board of directors of our general partner are not continuing directors (which is generally defined to mean members of our board of directors as of March 15, 2006 and persons who are nominated for election or elected to our general partner’s board of directors with the approval of a majority of the continuing directors who were members of such board of directors at the time of such nomination or election), (iii) the direct or indirect sale, transfer or other disposition in one or a series of related transactions of all or substantially all of the properties or assets (including equity interests of subsidiaries) of us and our subsidiaries to any person, (iv) the adoption of a plan related to our liquidation or dissolution or (v) Legacy Reserves GP, LLC ceasing to be our sole general partner.

•  the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and

•  specified ERISA events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1,000,000 in any year.

At March 31, 2007, Legacy was in compliance with all financial and other covenants of the Legacy Facility.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. Legacy based its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making

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judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

•  it requires assumptions to be made that were uncertain at the time the estimate was made, and

•  changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

Please read Note 1 of the Notes to the Consolidated Financial Statements for a detailed discussion of all significant accounting policies that we employ and related estimates made by management.

Nature of Critical Estimate Item:  Oil and Natural Gas Reserves — Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. LaRoche Petroleum Consultants, Ltd., annually prepares a reserve and economic evaluation of all our properties in accordance with SEC guidelines on a lease, unit or well-by-well basis, depending on the availability of well-level production data. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion rates are made concurrently with changes to reserve estimates.

Assumptions/Approach Used:  Units-of-production method to deplete our oil and natural gas properties — The quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate.

Effect if Different Assumptions Used:  Units-of-production method to deplete our oil and natural gas properties — A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the three month period ended March 31, 2007 by approximately 10%.

Nature of Critical Estimate Item:  Asset Retirement Obligations — We have certain obligations to remove tangible equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. We adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations effective January 1, 2003. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, SFAS No. 143 requires us to estimate asset retirement costs for all of our assets, adjust those costs for inflation to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an ARO liability in that amount with a corresponding addition to our asset value. When new obligations are incurred, i.e. a new well is drilled or acquired, we add a layer to the ARO liability. We then accrete the liability layers quarterly using the applicable period-end effective credit-adjusted-risk-free rates for each layer. Should either the estimated life or the estimated abandonment costs of a property change materially upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. Thus, abandonment costs will almost always approximate the estimate. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from our balance sheet.

Assumptions/Approach Used:  Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations

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often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Effect if Different Assumptions Used:  Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite our efforts to make an accurate estimate. We engage independent engineering firms to evaluate our properties annually. We use the remaining estimated useful life from the year-end reserve report by our independent reserve engineers in estimating when abandonment could be expected for each property. We expect to see our calculations impacted significantly if interest rates continue to rise, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis.

Nature of Critical Estimate Item:  Derivative Instruments and Hedging Activities — We periodically use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Currently, these transactions are swaps whereby we exchange our floating price for our oil and natural gas for a fixed price with qualified and creditworthy counterparties (currently BNP Paribas and Bank of America). Our existing oil and natural gas swaps are with members of our lending group which enables us to avoid margin calls for out-of-the money mark-to-market positions.

We do not specifically designate derivative instruments as cash flow hedges, even though they reduce our exposure to changes in oil and natural gas prices. Therefore, the mark-to-market of these instruments is recorded in current earnings. While we are not internally preparing an estimate of the current market value of these derivative instruments, we use market value statements from each of our counterparties as the basis for these end-of-period mark-to-market adjustments. When we record a mark-to-market adjustment resulting in a loss in a current period, these unrealized losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. As shown in the tables above, we have hedged a significant portion of our future production through 2011. As oil and gas prices rise and fall, our future cash obligations related to these derivatives will rise and fall.

Item 3.  Quantitative and Qualitative Disclosure About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to our natural gas production and the prevailing price for crude oil. Pricing for oil and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, such as the strength of the global economy.

We periodically enter into, and anticipate entering into hedging arrangements in the future with respect to a portion of our projected oil and natural gas production through various transactions that hedge the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into put options, whereby we pay a premium in exchange for the right to receive a fixed price at a future date. At the settlement date we receive the excess, if any, of the fixed floor over the floating rate. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

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As of March 31, 2007, the fair market value of Legacy’s derivative positions was a net liability of $6.6 million. As of December 31, 2006, the fair market value of Legacy’s derivative positions was an asset of $3.1 million. The oil and natural gas swaps for 2007 through December 31, 2011 are tabulated in the tables presented above under “— Cash Flow from Operations.”

Interest Rate Risks

At March 31, 2007, Legacy had debt outstanding of $4.0 million, which incurred interest at floating rates in accordance with its revolving credit facility and the subordinated notes payable. The average annual interest rate incurred by Legacy for the three month period ended March 31, 2007 was 8.01%. A 1% increase in LIBOR on Legacy’s outstanding debt as of March 31, 2007 would result in an estimated $40,000 increase in annual interest expense. Historically, Legacy has not entered into interest rate derivative transactions to mitigate its interest rate risk.

Item 4.  Controls and Procedures.

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, or the “Exchange Act”) that are designed to ensure that information required to be disclosed in Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our General Partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

Our management, with the participation of our General Partner’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2007. Based upon that evaluation and subject to the foregoing, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

Our General Partner’s Chief Executive Officer and Chief Financial Officer do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. The design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be considered relative to their cost. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that we have detected all of our control issues and all instances of fraud, if any. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving our stated goals under all potential future conditions.

There have been no changes in our internal control over financial reporting that occurred during our fiscal quarter ended March 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1A.  LEGAL PROCEEDINGS

 Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 1A.  RISK FACTORS

 In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2006 Annual Report, which could materially affect our business, financial condition or future results.  The risks described in our 2006 Annual Report are not the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

On January 11, 2007 we issued options to purchase 9,000 units to employees pursuant to the Legacy Reserves LP Long-Term Incentive Plan. These options vest ratably over a three-year period, expire five years from the grant date and are exercisable when they vest. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

On January 30, 2007, we issued 95,000 units in consideration for our acquisition of producing oil and natural gas properties in West Texas. The issuance of these units was exempt from registration under Section 4(2) of the Securities Act.

On February 26, 2007 we issued options to purchase 2,000 units to an employee pursuant to the Legacy Reserves LP Long-Term Incentive Plan. These options vest ratably over a three-year period, expire five years from the grant date and are exercisable when they vest. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

On March 15, 2007 we issued options to purchase 3,000 units to an employee pursuant to the Legacy Reserves LP Long-Term Incentive Plan. These options vest ratably over a three-year period, expire five years from the grant date and are exercisable when they vest. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

On April 16, 2007, we issued 611,247 units in consideration for our acquisition of producing oil and natural gas properties in the East Binger (Marchand) Unit in Caddo County, Oklahoma. The issuance of these units was exempt from registration under Section 4(2) of the Securities Act.

Item 3.  Defaults Upon Senior Securities.

 None.

Item 4.  Submission of Matters to a Vote of Security Holders.

 None.

Item 5.  Other Information.

 None.

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Item 6.  Exhibits.

The following documents are filed as a part of this quarterly report on Form 10-Q or incorporated by reference:

 

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Legacy Reserves LP (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.1)
3.2	Amended and Restated Limited Partnership Agreement of Legacy Reserves LP (Incorporated by reference to Legacy Reserve LP’s Registration Statement on Form S-1 (File No. 33-134056) filed May 12, 2006, included as Appendix A to the Prospectus and including specimen unit certificate for the units)
3.3	Certificate of Formation of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.3)
3.4	Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.4)
4.1	Registration Rights Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and Friedman, Billings, Ramsey & Co. (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 4.1)
4.2	Registration Rights Agreement dated June 29, 2006 between Henry Holding LP and Legacy Reserves LP and Legacy Reserves GP, LLC (the “Henry Registration Rights Agreement”) (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006 Exhibit 4.2)
4.3	Registration Rights Agreement dated March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto (the “Founders Registration Rights Agreement”) (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006 Exhibit 4.3)
4.4*	Registration Rights Agreement dated April 16, 2007 by and among Nielson & Associates, Inc., Legacy Reserves GP, LLC and Legacy Reserves LP
10.1*	Purchase, Sale and Contribution Agreement dated March 20, 2007, by and among Nielson & Associates, Inc. and Legacy Reserves Operating LP
31.1*	Rule 13a-14(a) Certifications (under Section 302 of the Sarbanes-Oxley Act of 2002)
31.2*	Rule 13a-14(a) Certifications (under Section 302 of the Sarbanes-Oxley Act of 2002)
32.1*	Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002)

 * Filed herewith

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