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.

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		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.

 

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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 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.