Legacy Reserves 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2014

or

£ 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 1800 Midland, Texas	79701
(Address of principal executive offices)	(Zip code)

(432) 689-5200

(Registrant’s telephone number, including area code)

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

x Yes  o  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes           £ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

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

57,564,767 units representing limited partner interests in the registrant were outstanding as of April 30, 2014.

TABLE OF CONTENTS

		Page
	Glossary of Terms	Page 3
	Part I - Financial Information
Item 1.	Financial Statements.
	Condensed Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013 (Unaudited).	Page 6
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013 (Unaudited).	Page 8
	Condensed Consolidated Statements of Unitholders' Equity for the three months ended March 31, 2014 (Unaudited).	Page 9
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013 (Unaudited).	Page 10
	Notes to Condensed Consolidated Financial Statements (Unaudited).	Page 11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	Page 27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	Page 39
Item 4.	Controls and Procedures.	Page 40
	Part II - Other Information
Item 1.	Legal Proceedings.	Page 41
Item 1A.	Risk Factors.	Page 41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	Page 42
Item 6.	Exhibits.	Page 43
	Signatures	Page 44

Page 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 project.  A drilling or other project which may target proven reserves, but which generally has a lower risk than that associated with exploration projects.

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.

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.

Hydrocarbons.  Oil, NGL and natural gas are all collectively considered hydrocarbons.

Liquids.  Oil and NGLs.

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.

MGal.  One thousand gallons of natural gas liquids or other liquid hydrocarbons.

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.

NGL 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.

Page 3

Oil.  Crude oil and condensate.

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 exceed 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 pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved developed non-producing reserves or PDNPs.  Proved oil and natural gas reserves that are developed behind pipe, shut-in or that 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 gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven 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 increased the cost of reserve purchases and reserves added through development projects. 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.

Page 4

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 the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price for each month) 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.

Page 5

Part I – FINANCIAL INFORMATION

Item 1.  Financial Statements.

LEGACY RESERVES LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

ASSETS
	March 31, 2014			December 31, 2013
	(In thousands)
Current assets:
Cash	$	2,972		$	2,584
Accounts receivable, net:
Oil and natural gas	59,614			47,429
Joint interest owners	15,957			16,532
Other	529			626
Fair value of derivatives (Notes 5 and 6)	2,266			3,801
Prepaid expenses and other current assets	4,100			3,727
Total current assets	85,438			74,699
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	2,287,952			2,265,788
Unproved properties	58,611			58,392
Accumulated depletion, depreciation, amortization and impairment	(821,762		)	(788,751		)
	1,524,801			1,535,429
Other property and equipment, net of accumulated depreciation and amortization of $6,368 and $6,053, respectively	3,604			3,688
Deposits on pending acquisitions	11,200			—
Operating rights, net of amortization of $4,145 and $4,024, respectively	2,871			2,992
Fair value of derivatives (Notes 5 and 6)	15,925			21,292
Other assets, net of amortization of $10,652 and $10,097, respectively	16,811			17,641
Investments in equity method investees	3,880			4,092
Total assets	$	1,664,530		$	1,659,833

See accompanying notes to condensed consolidated financial statements.

Page 6

LEGACY RESERVES LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

LIABILITIES AND UNITHOLDERS' EQUITY
	March 31, 2014		December 31, 2013
	(In thousands)
Current liabilities:
Accounts payable	$	8,147	$	6,016
Accrued oil and natural gas liabilities (Note 1)	73,872		63,161
Fair value of derivatives (Notes 5 and 6)	15,403		10,060
Asset retirement obligation (Note 7)	2,610		2,610
Other (Note 9)	19,010		12,043
Total current liabilities	119,042		93,890
Long-term debt (Note 2)	891,149		878,693
Asset retirement obligation (Note 7)	174,345		173,176
Fair value of derivatives (Notes 5 and 6)	1,438		2,119
Other long-term liabilities	1,528		1,559
Total liabilities	1,187,502		1,149,437
Commitments and contingencies (Note 4)
Unitholders' equity:
Limited partners' equity - 57,340,928 and 57,280,049 units issued and outstanding at March 31, 2014 and December 31, 2013, respectively	476,954		510,322
General partner's equity (approximately 0.03%)	74		74
Total unitholders' equity	477,028		510,396
Total liabilities and unitholders' equity	$	1,664,530	$	1,659,833

See accompanying notes to condensed consolidated financial statements.

Page 7

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended
	March 31,
	2014			2013
	(In thousands, except per unit data)
Revenues:
Oil sales	$	102,055		$	90,357
Natural gas liquids (NGL) sales	3,965			3,342
Natural gas sales	19,883			15,180
Total revenues	125,903			108,879
Expenses:
Oil and natural gas production	42,534			35,351
Production and other taxes	7,955			6,927
General and administrative	7,647			6,281
Depletion, depreciation, amortization and accretion	33,697			41,652
Impairment of long-lived assets	1,412			1,743
(Gain) loss on disposal of assets	2,301			(219		)
Total expenses	95,546			91,735
Operating income	30,357			17,144
Other income (expense):
Interest income	223			8
Interest expense (Notes 2, 5 and 6)	(13,939		)	(10,692		)
Equity in income (loss) of equity method investees	(8		)	44
Net losses on commodity derivatives (Notes 5 and 6)	(15,886		)	(13,005		)
Other	93			7
Income (loss) before income taxes	840			(6,494		)
Income tax expense	(314		)	(211		)
Net income (loss)	$	526		$	(6,705	)
Income (loss) per unit - basic and diluted (Note 8)	$	0.01		$	(0.12	)
Weighted average number of units used in computing net income (loss) per unit -
Basic	57,309			57,077
Diluted	57,367			57,077

See accompanying notes to condensed consolidated financial statements.

Page 8

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2014

(UNAUDITED)

	Number of Limited Partner Units	Limited Partner			General Partner		Total Unitholders' Equity
	(In thousands)
Balance, December 31, 2013	57,280	$	510,322		$	74	$	510,396
Unit-based compensation	—	462			—		462
Vesting of restricted and phantom units	61	—			—		—
Offering costs associated with the issuance of units	—	(105		)	—		(105		)
Distributions to unitholders, $0.59 per unit	—	(34,251		)	—		(34,251		)
Net income	—	526			—		526
Balance, March 31, 2014	57,341	$	476,954		$	74	$	477,028

See accompanying notes to condensed consolidated financial statements.

Page 9

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2014			2013
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	526		$	(6,705	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	33,697			41,652
Amortization of debt discount and issuance costs	1,012			766
Impairment of long-lived assets	1,412			1,743
Losses on derivatives	15,175			11,560
Equity in (income) loss of equity method investees	8			(44		)
Distribution from equity method investee	204			105
Unit-based compensation	1			127
(Gain) loss on disposal of assets	2,301			(219		)
Changes in assets and liabilities:
Increase in accounts receivable, oil and natural gas	(12,185		)	(10,064		)
(Increase) decrease in accounts receivable, joint interest owners	575			(4,346		)
Decrease in accounts receivable, other	97			140
(Increase) decrease in other assets	(41		)	136
Increase in accounts payable	2,131			8,624
Increase in accrued oil and natural gas liabilities	10,711			10,361
Increase in other liabilities	4,545			1,754
Total adjustments	59,643			62,295
Net cash provided by operating activities	60,169			55,590
Cash flows from investing activities:
Investment in oil and natural gas properties	(22,383		)	(28,663		)
Increase in deposits on pending acquisitions	(11,200		)	—
Proceeds from sale of assets	58			257
Investment in other equipment	(232		)	(287		)
Net cash settlements on commodity derivatives	(3,610		)	2,635
Net cash used in investing activities	(37,367		)	(26,058		)
Cash flows from financing activities:
Proceeds from long-term debt	126,000			86,000
Payments of long-term debt	(114,000		)	(84,000		)
Payments of debt issuance costs	(58		)	(44		)
Offering costs associated with the issuance of units	(105		)	—
Distributions to unitholders	(34,251		)	(32,645		)
Redemption of investment	—			(11		)
Net cash used in financing activities	(22,414		)	(30,700		)
Net increase (decrease) in cash and cash equivalents	388			(1,168		)
Cash and cash equivalents, beginning of period	2,584			3,509
Cash and cash equivalents, end of period	$	2,972		$	2,341
Non-cash investing and financing activities:
Asset retirement obligations associated with property acquisitions	—			$	523
Units issued in exchange for equity method investee	$	—		4,001
Note receivable received in exchange for the sale of oil and natural gas properties	$	—		$	11,857

See accompanying notes to condensed consolidated financial statements.

Page 10

LEGACY RESERVES LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) Summary of Significant Accounting Policies

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

Legacy Reserves LP ("LRLP," "Legacy" or the "Partnership") and, unless the context indicates otherwise, its affiliated entities, are referred to as Legacy in these financial statements.

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, 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 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 Securities and Exchange Commission (“SEC”). These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013.

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 owns an approximate 0.03% general partner interest in LRLP.

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 LRLP’s 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 LRGPLLC 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 liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRGPLLC 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.

Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin (West Texas and Southeast New Mexico), Mid-Continent and Rocky Mountain regions of the United States.

(b) Accrued Oil and Natural Gas Liabilities

Below are the components of accrued oil and natural gas liabilities as of March 31, 2014 and December 31, 2013.

Page 11

	March 31, 2014		December 31, 2013
	(In thousands)
Revenue payable	$	31,585	$	21,686
Accrued lease operating expense	10,882		11,914
Accrued capital expenditures	13,722		10,409
Accrued ad valorem tax	6,794		9,459
Other	10,889		9,693
	$	73,872	$	63,161

(2) Long-Term Debt

Long-term debt consists of the following as of March 31, 2014 and December 31, 2013:

		March 31,			December 31,
		2014			2013
	��	(In thousands)
Credit Facility due 2016		$	360,000		$	348,000
8% Senior Notes due 2020		300,000			300,000
6.625% Senior Notes due 2021		250,000			250,000
		910,000			898,000
Unamortized discount on Senior Notes		(18,851		)	(19,307		)
Total Long-Term Debt		$	891,149		$	878,693

Credit Facility

On March 10, 2011, Legacy entered into an amended and restated five-year $1 billion secured revolving credit facility with BNP Paribas as administrative agent (as amended, the "Credit Agreement"). Effective April 20, 2012, Wells Fargo Bank, National Association ("Wells Fargo"), replaced BNP Paribas as administrative agent as a result of the sale of BNP Paribas' energy lending practice to Wells Fargo. Borrowings under the Credit Agreement mature on March 10, 2016. The amount available for borrowing at any one time is limited to the borrowing base currently set at $800 million. As discussed in Note 11 - Subsequent Events, the Credit Agreement was amended and restated on April 1, 2014.

As of March 31, 2014, Legacy had outstanding borrowings of $360 million at a weighted-average interest rate of 2.25% and approximately $439.9 million of availability remaining under the Credit Agreement. For the three-month period ended March 31, 2014, Legacy paid in cash $2.6 million of interest expense on the Credit Agreement.

At March 31, 2014, Legacy was in compliance with all covenants of the Credit Agreement.

8% Senior Notes Due 2020

On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 8% Senior Notes due 2020 (the "2020 Senior Notes"). The 2020 Senior Notes were issued at 97.848% of par. Legacy received approximately $286.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by Legacy. During the three months ended March 31, 2014, Legacy amortized $0.3 million of this discount.

Legacy will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below.

Page 12

Year	Percentage
2016	104.000	%
2017	102.000	%
2018 and thereafter	100.000	%

Prior to December 1, 2016, Legacy may redeem all or any part of the 2020 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to December 1, 2015, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes at the redemption price of 108% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy's and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its 100% owned subsidiaries Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other, debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to Note 11 - Subsidiary Guarantors for further details on Legacy's guarantors.

The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed the sum of available cash (as defined in the partnership agreement) at Legacy, net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. The indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the 2020 Senior Notes.

Interest is payable on June 1 and December 1 of each year.

6.625% Senior Notes Due 2021

On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of our 6.625% Senior Notes due 2021 (the "2021 Senior Notes"). The 2021 Senior Notes were issued at 98.405% of par. Legacy received approximately $240.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by Legacy. During the three months ended March 31, 2014, Legacy amortized $0.2 million of this discount.

The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below.

Page 13

Year	Percentage
2017	103.313	%
2018	101.656	%
2019 and thereafter	100.000	%

Prior to June 1, 2017, Legacy may redeem all or any part of the 2021 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to June 1, 2016, Legacy may at its option, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes at the redemption price of 106.625% with the net proceeds of a public or private equity offering. Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. The Partnership is in compliance with all financial and other covenants of the 2021 Senior Notes.

Interest is payable on June 1 and December 1 of each year.

(3) Related Party Transactions

Cary D. Brown, Chairman, President and Chief Executive Officer of LRGPLLC, Kyle A. McGraw, Director and Executive Vice President and Chief Development Officer of LRGPLLC and Dale Brown, Director of LRGPLLC, own interests in partnerships which, in turn, own a combined non-controlling 4.12% interest as limited partners in a partnership which owns the building that Legacy occupies. Monthly rent is $58,995, without respect to property taxes and insurance. The lease expires in September 2015.

During the year ended December 31, 2012, Legacy acquired a 5% working interest in prospective Cline Shale acreage from FireWheel Energy, LLC ("FireWheel"), the operator of the properties, for $7.2 million. During the year ended December 31, 2013, Legacy acquired a 5% working interest in additional acreage from Firewheel for $1.2 million. FireWheel is a private-equity funded oil and natural gas exploration company in which Alan Brown, son of Dale Brown, a director of Legacy, and brother of Cary D. Brown, is a principal. The interests acquired by Legacy were marketed to numerous industry participants and are governed by an industry standard Participation Agreement and Joint Operating Agreement.

(4) 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 could have a potential material adverse effect on its financial condition, results of operations or cash flows.

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, respectively.

(5) Fair Value Measurements

As defined in Financial Accounting Standards Board ("FASB") ASC 820-10, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820-10 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

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Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date.
Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as natural gas derivative swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG indices, enhanced swaps, commodity collars and Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014:

	Fair Value Measurements at March 31, 2014 Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs		Total Carrying Value as of
Description	(Level 1)		(Level 2)			(Level 3)		March 31, 2014
	(In thousands)
LTIP liability (a)	$	—	$	(1,756	)	$	—	$	(1,756	)
Oil and natural gas swaps	—		(9,155		)	2,255		(6,900		)
Oil and natural gas collars	—		—			12,297		12,297
Interest rate swaps	—		(4,047		)	—		(4,047		)
Total	$	—	$	(14,958	)	$	14,552	$	(406	)

(a) See Note 9 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method.

Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on

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published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	Significant Unobservable Inputs
	(Level 3)
	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Beginning balance	$	20,615		$	29,966
Total losses	(6,740		)	(7,221		)
Settlements, net	677			(3,931		)
Ending balance	$	14,552		$	18,814
Losses included in earnings relating to derivatives still held as of March 31, 2014 and 2013	$	(5,622	)	$	(11,171	)

During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or

illiquidity, it may be difficult to value certain of the Partnership's derivative instruments if trading becomes less frequent and/or

market data becomes less observable. There may be certain asset classes that were previously in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition

Fair Value on a Non-Recurring Basis

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of asset retirement obligations ("ARO") for which fair value is used. These ARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 7.

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Assets measured at fair value during the three-month period ended March 31, 2014 include:

	Fair Value Measurements at March 31, 2014 Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	(Level 1)		(Level 2)		(Level 3)
	(In thousands)
Assets:
Impairment (a)	$	—	$	—	$	2,019
Acquisitions (b)	$	—	$	—	$	588

(a) Legacy reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. During the three-month period ended March 31, 2014, Legacy incurred impairment charges of $1.4 million as oil and natural gas properties with a net cost basis of $3.4 million were written down to their fair value of $2.0 million. In order to determine fair value, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

(b) Assets and liabilities acquired in a business combination are recorded at fair value. During the three-month period ended March 31, 2014, Legacy acquired oil and natural gas properties, inclusive of unproved acreage acquisitions, with a fair value of $0.6 million in several individually immaterial transactions. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

The carrying amount of the revolving long-term debt of $360 million as of March 31, 2014 approximates fair value because Legacy's current borrowing rate does not materially differ from market rates for similar bank borrowings. Legacy has classified the revolving long-term debt as a Level 2 item within the fair value hierarchy. As of March 31, 2014, the fair values of the 2020 Senior Notes and the 2021 Senior Notes were $320.6 million and $250.2 million, respectively. As these valuations are based on unadjusted quoted prices in an active market, the fair values are classified as Level 1 items within the fair value hierarchy.

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(6) Derivative Financial Instruments

Commodity derivative transactions

Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) 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 prices 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. Each of these instruments was a costless contract with no upfront premium paid or payable to our counterparty.

All of these price risk management transactions are considered derivative instruments. These derivative instruments are intended to reduce Legacy’s price risk and may be considered hedges for economic purposes, but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings.

By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates credit risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties, who currently are all current or former members of Legacy's lending group.

The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the three months ended March 31, 2014 and 2013.

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Beginning fair value of commodity derivatives	$	17,673		$	24,148
Total loss - oil derivatives	(12,260		)	(7,496		)
Total loss - natural gas derivatives	(3,626		)	(5,509		)
Crude oil derivative cash settlements paid (received)	2,556			(229		)
Natural gas derivative cash settlements paid (received)	1,054			(2,406		)
Ending fair value of commodity derivatives	$	5,397		$	8,508

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Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands):

	March 31, 2014
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets:				(In thousands)
Commodity derivatives	$	35,172		$	(16,981	)	$	18,191
Interest rate derivatives	—			—			—
Total derivative assets	$	35,172		$	(16,981	)	$	18,191
Offsetting Derivative Liabilities:
Commodity derivatives	$	(29,775	)	$	16,981		$	(12,794	)
Interest rate derivatives	(4,047		)	—			(4,047		)
Total derivative liabilities	$	(33,822	)	$	16,981		$	(16,841	)
	December 31, 2013
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets:				(In thousands)
Commodity derivatives	$	46,356		$	(21,263	)	$	25,093
Interest rate derivatives	—			—			—
Total derivative assets	$	46,356		$	(21,263	)	$	25,093
Offsetting Derivative Liabilities:
Commodity derivatives	$	(28,683	)	$	21,263		$	(7,420	)
Interest rate derivatives	(4,759		)	—			(4,759		)
Total derivative liabilities	$	(33,442	)	$	21,263		$	(12,179	)

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As of March 31, 2014, Legacy had the following NYMEX West Texas Intermediate ("WTI") crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:

		Average
Calendar Year	Volumes (Bbls)	Price per Bbl	Price Range per Bbl
April-December 2014	2,204,220	$93.19	$87.50	-	$101.50
2015	545,351	$91.98	$88.50	-	$100.20
2016	228,600	$87.94	$86.30	-	$99.85
2017	182,500	$84.75	$84.75

As of March 31, 2014, Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below:

		Average Short	Average Long	Average Short
Calendar Year	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Call Price per Bbl
April-December 2014	605,000	$71.59	$96.59	$110.56
2015	1,308,500	$64.67	$89.67	$112.21
2016	621,300	$63.37	$88.37	$106.40
2017	72,400	$60.00	$85.00	$104.20

As of March 31, 2014, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below:

		Average Long	Average Short	Average
Calendar Year	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Swap Price per Bbl
2015	365,000	$60.00	$80.00	$92.35
2016	183,000	$57.00	$82.00	$91.70
2017	182,500	$57.00	$82.00	$90.85
2018	127,750	$57.00	$82.00	$90.50

As of March 31, 2014, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and a fixed-price swap as indicated below:

		Average Short Put	Average Swap
Calendar Year	Volumes (Bbls)	Price per Bbl	Price per Bbl
2015	365,000	$70.00	$92.03

As of March 31, 2014, Legacy had the following NYMEX West Texas Waha, ANR-OK and CIG-Rockies natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:

		Average	Price
Calendar Year	Volumes (MMBtu)	Price per MMBtu	Range per MMBtu
April-December 2014	6,128,903	$4.31	$3.61	-	$6.47
2015	4,669,300	$4.58	$4.15	-	$5.82
2016	1,419,200	$4.30	$4.12	-	$5.30

As of March 31, 2014, Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below:

		Average Short Put	Average Long Put	Average Short Call
Calendar Year	Volumes (MMBtu)	Price per MMBtu	Price per MMBtu	Price per MMBtu
2015	1,440,000	$3.25	$4.05	$4.49

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Interest rate derivative transactions

Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged, which has, and could result in overhedged amounts.

Legacy accounts for these interest rate swaps at fair market value and included in the consolidated balance sheet as assets or liabilities.

Legacy does not designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows:

	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Beginning fair value of interest rate swaps	$	(4,759	)	$	(9,547	)
Total gain (loss) on interest rate swaps	(174		)	(336		)
Cash settlements paid	886			1,781
Ending fair value of interest rate swaps	$	(4,047	)	$	(8,102	)

The table below summarizes the interest rate swap position as of March 31, 2014:

						Estimated Fair Market Value at
Notional Amount		Fixed Rate		Effective Date	Maturity Date	March 31, 2014
(Dollars in thousands)
$	29,000	3.070	%	10/16/2007	10/16/2015	$	(1,173	)
$	13,000	3.112	%	11/16/2007	11/16/2015	(566		)
$	12,000	3.131	%	11/28/2007	11/28/2015	(525		)
$	50,000	0.710	%	8/10/2011	8/10/2014	(103		)
$	50,000	0.702	%	8/10/2011	8/10/2014	(101		)
$	50,000	2.500	%	10/10/2008	10/10/2015	(1,579		)
Total fair market value of interest rate derivatives						$	(4,047	)

(7) Asset Retirement Obligation

AROs associated with the retirement of a tangible long-lived asset are 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 three months ended March 31, 2014 and year ended December 31, 2013:

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	March 31, 2014			December 31, 2013
	(In thousands)
Asset retirement obligation - beginning of period	$	175,786		$	162,183
Liabilities incurred with properties acquired	—			10,969
Liabilities incurred with properties drilled	—			494
Liabilities settled during the period	(491		)	(2,441		)
Liabilities associated with properties sold	—			(1,606		)
Current period accretion	1,660			6,187
Asset retirement obligation - end of period	$	176,955		$	175,786

(8) Income (Loss) Per Unit

The following table sets forth the computation of basic and diluted income (loss) per unit:

	Three Months Ended
	March 31,
	2014		2013
	(In thousands)
Income (loss) available to unitholders	$	526	$	(6,705	)
Weighted average number of units outstanding	57,309		57,077
Effect of dilutive securities:
Restricted and phantom units	58		—
Weighted average units and potential units outstanding	57,367		57,077
Basic and diluted earnings (loss) per unit	$	0.01	$	(0.12	)

For the three months ended March 31, 2014, 201,643 and 289,977 restricted and phantom units, respectively, were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. For the three months ended March 31, 2013, 425,120 restricted units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.

(9) Unit-Based Compensation

Long-Term Incentive Plan

On March 15, 2006, the LTIP for Legacy was implemented for its employees, consultants and directors, its affiliates and its general partner. The awards under the LTIP may include unit grants, restricted units, phantom units, unit options and unit appreciation rights ("UARs"). The LTIP permits the grant of awards covering an aggregate of 2,000,000 units. As of March 31, 2014, grants of awards net of forfeitures and, in the case of UARs and phantom units, historical exercises covering 1,742,861 units had been made, comprised of 266,014 unit option awards, 609,208 UARs, 431,436 restricted unit awards, 323,965 phantom unit awards and 112,238 unit awards. The LTIP is administered by the compensation committee (the “Compensation Committee”) of the board of directors of LRGPLLC.

The cost of employee services in exchange for an award of equity instruments is measured 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. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Due to Legacy’s historical practice of settling options, UARs and certain phantom unit awards in cash, Legacy accounted for unit options, UARs and certain phantom unit awards by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost is recognized based on the change in the liability between periods. However, during 2013, the Compensation Committee revised the executive compensation policy and amended certain historical phantom unit award agreements to eliminate the Compensation Committee's option of settling phantom unit awards for executive officers in cash. Due to the elimination of the cash settlement

Page 22

option, Legacy now accounts for executive phantom unit awards under the equity method as described in ASC 718. Legacy treated the amendment as a cancellation of the historical awards and a grant of new awards in the period, though the award amounts and vesting terms remained unchanged.

Unit Appreciation Rights and Unit Options

A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy is accounting for the UARs by utilizing the liability method.

During the year ended December 31, 2013, Legacy issued 156,650 UARs to employees which vest ratably over a three-year period and 77,506 UARs to employees which vest at the end of a three-year period. During the three-month period ended March 31, 2014, Legacy issued 19,000 UARs to employees which vest ratably over a three-year period. All UARs granted in 2013 and 2014 expire seven years from the grant date and are exercisable when they vest.

For the three-month periods ended March 31, 2014 and 2013, Legacy recorded $(0.2) million and $0.4 million, respectively, of compensation expense (benefit) due to the change in liability from December 31, 2013 and 2012, respectively, based on its use of the Black-Scholes model to estimate the March 31, 2014 and 2013 fair value of these UARs and unit options (see Note 5). As of March 31, 2014, there was a total of approximately $0.8 million of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At March 31, 2014, this cost was expected to be recognized over a weighted-average period of approximately 2.13 years. Compensation expense is based upon the fair value as of March 31, 2014 and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 44% and employed the Black-Scholes model to estimate the March 31, 2014 fair value to be realized as compensation cost based on the percentage of service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 3.9%. Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $2.36 per unit.

A summary of UAR and unit option activity for the three months ended March 31, 2014 is as follows:

	Units		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2014	627,043		$	25.99
Granted	19,000		26.77
Exercised	(17,500	)	23.01
Forfeited	(19,335	)	26.02
Outstanding at March 31, 2014	609,208		$	26.10	5.0	$	417,061
Options and UARs exercisable at March 31, 2014	244,373		$	24.37	3.7	$	412,295

The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2014: 

	Non-Vested UARs
	Number of Units		Weighted-Average Exercise Price
Non-vested at January 1, 2014	386,755		$	27.21
Granted	19,000		26.77
Vested	(22,585	)	26.39
Forfeited	(18,335	)	26.89
Non-vested at March 31, 2014	364,835		$	27.26

Legacy has used a weighted-average risk-free interest rate of 1.6% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at March 31, 2014 whose terms are consistent with the expected life of the

Page 23

UARs and unit options. Expected life represents the period of time that UARs and unit 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.

	Three Months Ended
	March 31, 2014
Expected life (years)	5.39
Risk free interest rate	1.6	%
Annual distribution rate per unit	$2.36
Volatility	44	%

Phantom Units

Legacy has also issued phantom units under the LTIP to both executive officers, as described below, and certain other employees. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive, in the case of non-executive employees, cash valued at the closing price of units on the vesting date, or, at the discretion of the Compensation Committee, the same number of Partnership units. Because Legacy’s current intent is to settle these non-executive phantom unit awards in cash, Legacy is accounting for these phantom units by utilizing the liability method. As mentioned above, in the case of executive employees, the Compensation Committee revised the historical grants for all executive phantom units to eliminate any election for cash payment. As these awards can now only be settled in Partnership units, Legacy is accounting for these phantom units by utilizing the equity method.

On September 21, 2009, the board of directors of LRGPLLC, upon the recommendation of the Compensation Committee, implemented an equity-based incentive compensation policy applicable to the executive officers of Legacy. In addition to cash bonus awards, under the compensation plan, the executives are eligible for both subjective and objective grants of phantom units. The subjective, or service-based, grants may be awarded up to a maximum percentage of annual salary as determined by the Compensation Committee. Once granted, these phantom units vest ratably over a three-year period. The objective, or performance-based, grants may be awarded up to a maximum percentage of annual salary as determined by the Compensation Committee. However, the amount to vest each year for the three-year vesting period will be determined on each vesting date based on a three-step process, with the first two steps each comprising 50% of the total vesting amount while the third step is the sum of the first two steps. The first step in the process will be a function of Total Unitholder Return (“TUR”) for the Partnership and the percentage rank of the Legacy TUR among a peer group of upstream master limited partnerships, as determined by the Compensation Committee at the beginning of each year. In the second step, the Legacy TUR will be compared to the TUR of a group of master limited partnerships included in the Alerian MLP Index. The third step is the addition of the above two steps to determine the total performance-based awards to vest. On March 7, 2013, the board of directors of LRGPLLC, upon the recommendation of the Compensation Committee, approved a revised compensation policy (the “Revised Policy.”) This Revised Policy applies to incentive awards granted after the fiscal year ended 2013. While the Revised Policy measures TUR against both the peer group and Alerian MLP Index, the measurement periods were increased to a three-year cumulative measurement period with a corresponding increase in vesting from a ratable three-year vesting to three-year cliff vesting. Performance based phantom units subject to vesting which do not vest in a given year will be forfeited. With respect to both the subjective and objective units awarded under both compensation policies, distribution equivalent rights ("DERs") will accumulate and accrue based on the total number of actual amounts vested and will be payable at the date of vesting. However, due to the aforementioned revision for executive employees, accrued DERs paid at the date of vesting will be treated as distributions in the period paid rather than being recognized as compensation expense over the life of the award.

On March 7, 2013, the Compensation Committee approved the award of 46,430 subjective, or service-based, phantom units and 76,723 objective, or performance based, phantom units to Legacy’s executive officers. On March 4, 2014, the Compensation Committee approved the award of 117,197 subjective, or service-based, phantom units and 102,572 objective, or performance based, phantom units to Legacy’s executive officers.

Compensation expense (benefit) related to the phantom units and associated DERs was $0.3 million and $(0.8) million for the three months ended March 31, 2014 and 2013, respectively.

Restricted Units

During the year ended December 31, 2013, Legacy issued an aggregate of 85,728 restricted units to non-executive employees. These restricted units awarded mostly vest ratably over a three-year period all beginning on or around the date of

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grant. During the three-month period ended March 31, 2014, Legacy issued an aggregate of 2,475 restricted units to non-executive employees. These restricted units awarded vest ratably over a three-year period. Compensation expense related to restricted units was $0.5 million and $0.6 million for the three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014, there was a total of $4.1 million of unrecognized compensation expense related to the unvested portion of these restricted units. At March 31, 2014, this cost was expected to be recognized over a weighted-average period of 2.5 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at March 31, 2014, do not include 225,278 units related to unvested restricted unit awards.

Board and Additional Executive Units

On May 14, 2013, Legacy granted and issued 3,715 units to each of its five non-employee directors. The value of each unit was $27.39 at the time of issuance.

(10) Subsidiary Guarantors

On September 6, 2011, we filed a post-effective amendment to a registration statement on Form S-3 with the Securities and Exchange Commission ("SEC") to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by Legacy Reserves Finance Corporation. The registration statement also registered guarantees of debt securities by Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in a private offering on May 28, 2013 and were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by our 100% owned subsidiaries Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., which constitute all of our wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in Note 2 - Long-Term Debt. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors.

(11) Subsequent Events

On April 22, 2014, Legacy’s board of directors approved a distribution of $0.595 per unit payable on May 14, 2014 to unitholders of record on May 1, 2014, representing an increase of $0.005 per unit over the last quarterly distribution.

On April 1, 2014, Legacy entered into an amended and restated five-year $1.5 billion secured revolving credit facility that matures on April 1, 2019, with the borrowing base remaining unchanged at $800 million.

On April 17, 2014, Legacy, with Stifel Nicolaus & Company, Incorporated, Barclays Capital Inc. and MLV & Co. LLC acting as joint book-running managers, issued a public offering of 2 million 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units ("Series A Preferred Units") at a price of $25.00 per unit. The underwriters have been granted a 30-day option to purchase up to an additional 300,000 Series A Preferred Units from Legacy at the public offering price less the underwriting discount. Legacy received net proceeds of approximately $48.1 million, after deducting underwriting discounts and estimated offering expenses, from the offering.

Distributions on the Series A Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of LRGPLLC. Distributions on the Series A Preferred Units will be payable out of amounts legally available therefor from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24%, based on the $25.00 liquidation preference per Series A Preferred Unit.

At any time on or after April 15, 2019, Legacy may redeem the Series A Preferred Units, in whole or in part, out of amounts legally available therefor, at a redemption price of $25.00 per Series A Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon through and including the date of redemption, whether or not declared. Legacy may also redeem the Series A Preferred Units in the event of a Change of Control.

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The Series A Preferred Units were admitted for trading on NASDAQ under the symbol "LGCYP" and commenced trading on NASDAQ on May 5, 2014.

On May 2, 2014, Legacy entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) by and between Legacy and certain of its subsidiaries and WPX Energy Rocky Mountain, LLC , a subsidiary of WPX Energy, Inc., for the purchase of a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County Colorado.  Upon the closing of the transactions contemplated by the Purchase and Sale Agreement, Legacy will pay consideration consisting of (i) $355 million in cash, subject to certain adjustments at closing, and (ii) 300,000 incentive distribution units representing a new class of limited partner interests in the Partnership (the "Incentive Distribution Units"), 100,000 of which vest immediately and the remainder of which vest pursuant to the terms of a related Incentive Distribution Unitholder Agreement. The Incentive Distribution Units will represent limited partner interests in the Partnership which will be designated and authorized in an amendment to Legacy’s partnership agreement. This acquisition will be accounted for as a business combination. Legacy will determine the fair value of assets acquired and liabilities assumed on the date of close.

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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;

•the amount of oil and natural gas we produce;

•the price at which we are able to sell our oil and natural gas production;

•our ability to acquire additional oil and natural gas properties at economically attractive prices;

•our drilling locations and our ability to continue our development activities at economically attractive costs;

• the level of our lease operating expenses, general and administrative costs and finding and development costs, including payments to our general partner;

•the level of capital expenditures;

•the level of cash distributions to our unitholders;

•our future operating results; and

•our 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 our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in Legacy’s Annual Report on Form 10-K for the year ended December 31, 2013 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.

Overview

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.

Acquisitions have been financed with a combination of proceeds from bank borrowings, issuance of notes, issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and developing 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.

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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 and the amount of our cash distributions.

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 acquiring more reserves than we produce, drilling to find additional reserves, utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary (CO2 and nitrogen) recovery methods to re-pressure the reservoir and recover additional oil, recompleting or adding pay in existing wellbores and improving artificial lift. 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 development projects is dependent upon many factors including our ability to raise capital, competitively bid on acquisitions, 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 “Investing Activities” below, we have entered into oil and natural gas derivatives designed to mitigate the effects of price fluctuations covering 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 on any redetermination to our borrowing base under our revolving credit facility.

Legacy does not specifically designate derivative instruments as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in fair value 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 or recompleted.

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 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. We do not consider royalties paid to mineral owners an expense as we deduct hydrocarbon volumes owned by mineral owners from the reported hydrocarbon sales volumes.

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Operating Data

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

	Three Months Ended
	March 31,
	2014			2013
	(In thousands, except per unit data)
Revenues:
Oil sales	$	102,055		$	90,357
Natural gas liquids sales	3,965			3,342
Natural gas sales	19,883			15,180
Total revenue	$	125,903		$	108,879
Expenses:
Oil and natural gas production, excluding ad valorem taxes	$	39,638		$	32,385
Ad valorem taxes	$	2,896		$	2,966
Total oil and natural gas production	$	42,534		$	35,351
Production and other taxes	$	7,955		$	6,927
General and administrative, excluding LTIP	$	6,957		$	5,295
LTIP expense	$	690		$	986
Total general and administrative	$	7,647		$	6,281
Depletion, depreciation, amortization and accretion	$	33,697		$	41,652
Commodity derivative cash settlements:
Oil derivative cash settlements received (paid)	$	(2,556	)	$	229
Natural gas derivative cash settlements received (paid)	$	(1,054	)	$	2,406
Production:
Oil (MBbls)	1,135			1,114
Natural gas liquids (MGal)	3,362			2,893
Natural gas (MMcf)	3,226			3,546
Total (MBoe)	1,753			1,774
Average daily production (Boe/d)	19,478			19,711
Average sales price per unit (excluding derivative cash settlements):
Oil price (per Bbl)	$	89.92		$	81.11
Natural gas liquids price (per Gal)	$	1.18		$	1.16
Natural gas price (per Mcf) (a)	$	6.16		$	4.28
Combined (per Boe)	$	71.82		$	61.37
Average sales price per unit (including derivative cash settlements):
Oil price (per Bbl)	$	87.66		$	81.32
Natural gas liquids price (per Gal)	$	1.18		$	1.16
Natural gas price (per Mcf) (a)	$	5.84		$	4.96
Combined (per Boe)	$	69.76		$	62.86
Average WTI oil spot price (per Bbl)	$	98.68		$	94.33
Average Henry Hub natural gas index price (per Mcf)	$	4.93		$	3.34
Average unit costs per Boe:
Oil and natural gas production	$	22.61		$	18.26
Ad valorem taxes	$	1.65		$	1.67
Production and other taxes	$	4.54		$	3.90
General and administrative excluding LTIP	$	3.97		$	2.98
Total general and administrative	$	4.36		$	3.54
Depletion, depreciation, amortization and accretion	$	19.22		$	23.48

____________________

(a) We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin and for Legacy as a whole are higher than Henry Hub natural gas index prices due to this NGL content.

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Results of Operations

Three-Month Period Ended March 31, 2014 Compared to Three-Month Period Ended March 31, 2013

Our revenues from the sale of oil were $102.1 million and $90.4 million for the three-month periods ended March 31, 2014 and 2013, respectively. Our revenues from the sale of NGLs were $4.0 million and $3.3 million for the three-month periods ended March 31, 2014 and 2013, respectively. We had revenues from the sale of natural gas of $19.9 million and $15.2 million for the three-month periods ended March 31, 2014 and 2013, respectively. The $11.7 million increase in oil revenues reflects the increase in oil production of 21 MBbls (2%) as well as an increase in average realized price of $8.81 per Bbl (11%). This increase in production is related to our purchase of additional oil and natural gas properties during 2013, as well as our ongoing development activities partially offset by a decline in the Lower Abo oil production and downtime related to inclement weather. The improvement in realized oil prices of $8.81 per Bbl during the three months ended March 31, 2014 compared to the same period in 2013 was due to an improvement in West Texas Intermediate (“WTI”) crude oil prices of $4.35 per Bbl as well as improved crude oil differentials in the Permian Basin and Rocky Mountain regions. The $0.6 million increase in NGL sales reflects an increase in realized NGL price of approximately $0.02 (2%) as well as an increase in NGL production of 469 MGals (16%). The $4.7 million increase in natural gas revenues reflects an increase in our realized natural gas prices partially offset by a decrease in our production volumes. Our natural gas production decreased by approximately 320 MMcf (9%) primarily due to a decline in the Lower Abo natural gas production and downtime related to inclement weather that impacted our natural gas production in the Permian Basin and the Rockies. Average realized natural gas prices increased by $1.88 per Mcf (44%) during the three months ended March 31, 2014 compared to the same period in 2013, due to the increase in index prices. We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin and for Legacy as a whole are higher than NYMEX Henry Hub natural gas prices due to this NGL content.

For the three-month period ended March 31, 2014, we recorded $15.9 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the three-month period ended March 31, 2014 are primarily due to the increase in oil prices during the period. For the three-month period ended March 31, 2013, we recorded $13.0 million of net losses on oil and natural gas derivatives. Settlements of such contracts resulted in cash payments of $3.6 million and cash receipts of $2.6 million during the three months ended March 31, 2014 and 2013, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, increased to $39.6 million ($22.61 per Boe) for the three-month period ended March 31, 2014 from $32.4 million ($18.26 per Boe) for the three-month period ended March 31, 2013. Production expenses increased primarily due to expenses associated with our acquisitions and development activities, a $2.1 million increase in one-time well workover expenses and industry-wide cost increases. Our ad valorem tax expense decreased marginally to $2.9 million ($1.65 per Boe) for the three-month period ended March 31, 2014 compared to $3.0 million ($1.67 per Boe) for the three-month period ended March 31, 2013.

Our production and other taxes were $8.0 million and $6.9 million for the three-month periods ended March 31, 2014 and 2013, respectively. Production and other taxes increased because of increased production volumes related to 2013 acquisitions and increased product prices, as production and other taxes as a percentage of revenue remained relatively unchanged during the three-month period ended March 31, 2014 compared to the same period in 2013.

Our general and administrative expenses were $7.6 million and $6.3 million for the three-month periods ended March 31, 2014 and 2013, respectively. General and administrative expenses increased $1.4 million primarily due to an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base.

We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $33.7 million and $41.7 million for the three-month periods ended March 31, 2014 and 2013, respectively. DD&A decreased due to a decrease in both the depletion rate and depletable base. As the depletion rate is a function of production and reserves, the increase in our reserves balance, combined with a decrease in production, resulted in a lower depletion rate. Additionally, the depletion recognized in 2013 combined with impairment charges realized in 2013 more than offset the increase in the depletable base from our acquisition and development activities, which resulted in a lower depletable base during 2014 compared to the same time period of 2013.

Impairment expense was $1.4 million and $1.7 million for the three-month periods ended March 31, 2014 and 2013, respectively. In the three-month period ended March 31, 2014, we recognized $1.4 million of impairment expense on two

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separate producing fields primarily related to a reduction in the future expected cash flows from two unproved properties. We consider expected cash flows from both proved and unproved properties in a given field when reviewing for impairment. In the case of these two fields, impairment was indicated in previous periods, but the additional cash flow from identified unproved projects mitigated the indicated impairment. During the three months ended March 31, 2014, we revised certain reserve estimates associated with these unproved properties due to other operators' recent drilling results on adjacent properties and thus recognized impairment on the reduced expected cash flows. Impairment expense for the period ended March 31, 2013 was primarily related to higher realized oil and natural gas differentials, which reduced the future expected cash flows.

We recorded interest expense of $13.9 million and $10.7 million for the three-month periods ended March 31, 2014 and 2013, respectively. Interest expense increased approximately $3.2 million primarily due to $4.3 million of interest expense related to the senior notes issued in May 2013, which was partially offset by lower average debt outstanding under our revolving credit agreement.

Non-GAAP Financial Measure

Our management uses Adjusted EBITDA as a tool to provide additional information and metrics relative to the performance of our business. Our management believes that Adjusted EBITDA is useful to investors because this measure is used by many companies in the industry as a measure of operating and financial performance and is commonly employed by financial analysts and others to evaluate the operating and financial performance of the Partnership from period to period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.

The following presents a reconciliation of “Adjusted EBITDA,” which is a non-GAAP measure, to its nearest comparable GAAP measure. Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.

Adjusted EBITDA is defined as net income (loss) plus:

• Interest expense;

• Income taxes;

• Depletion, depreciation, amortization and accretion;

• Impairment of long-lived assets;

• (Gain) loss on sale of partnership investment;

• (Gain) loss on disposal of assets;

• Equity in (income) loss of equity method investees;

• Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;

• Minimum payments earned in excess of overriding royalty interest earned;

• Equity in EBITDA of equity method investee;

• Net (gains) losses on commodity derivatives;

• Net cash settlements received (paid) on commodity derivatives; and

• Transaction expenses related to acquisitions.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA for the three months ended March 31, 2014 and 2013, respectively.

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	Three Months Ended
	March 31,
	2014			2013
	(In thousands)
Net income (loss)	$	526		$	(6,705	)
Plus:
Interest expense	13,939			10,692
Income tax expense	314			211
Depletion, depreciation, amortization and accretion	33,697			41,652
Impairment of long-lived assets	1,412			1,743
(Gain) loss on disposal of assets	2,301			(219		)
Equity in income of equity method investees	8			(44		)
Unit-based compensation expense	690			986
Minimum payments earned in excess of overriding royalty interest(a)	333			400
Equity in EBITDA of equity method investee(b)	258			—
Net losses on commodity derivatives	15,886			13,005
Net cash settlements received (paid) on commodity derivatives	(3,610		)	2,635
Transaction expenses related to acquisitions	55			—
Adjusted EBITDA	$	65,809		$	64,356

____________________

(a) A portion of minimum payments earned in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments are recognized in net income.

(b) EBITDA applicable to equity method investee is defined as the equity method investee's net income plus interest expense and depreciation.

For the three months ended March 31, 2014 and 2013, respectively, Adjusted EBITDA (as defined below) increased 2% to $65.8 million from $64.4 million primarily due to higher realized commodity prices. These factors were partially offset by higher commodity derivative settlement payments of approximately $6.2 million as well as higher expenses and taxes.

Capital Resources and Liquidity

Our primary sources of capital and liquidity have been cash flow from operations, the issuance of additional common and preferred units, the issuance of notes, proceeds from bank borrowings or a combination thereof. To date, our primary use of capital has been for acquisition and development of oil and natural gas properties and the repayment of bank borrowings.

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 developing additional hydrocarbon 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 revolving credit facility, if available, or obtain additional debt or equity financing. Our revolving credit facility and our senior notes issued in December 2012 and May 2013, respectively, limit our ability to issue additional debt, but permit us to issue limited amounts of unsecured senior or senior subordinated notes. Further, our existing revolving credit facility matures on April 1, 2019.

The amounts available for borrowing under our credit facility are subject to a borrowing base which is currently set at $800.0 million. As of April 30, 2014, we had $501.9 million available for borrowing under our revolving credit facility. Based on their commodity price expectations, our lenders redetermine the borrowing base semi-annually, with the next redetermination scheduled on or around October 2014. Please see “— Financing Activities — Our Revolving Credit Facility.”

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Cash Flow from Operations

Our net cash provided by operating activities was $60.2 million and $55.6 million for the three-month periods ended March 31, 2014 and 2013, respectively. The 2014 period was favorably impacted by higher realized commodity prices, partially offset by higher operating expenses.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, NGL and natural gas prices. Oil, NGL 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 development projects, as well as the prices of oil, NGL and natural gas.

Investing Activities

We invested cash capital of $22.4 million for the three-month period ended March 31, 2014. The total includes $0.6 million for the acquisition of oil and natural gas properties in several individually immaterial acquisitions and $21.8 million for development projects. Our cash capital expenditures were $28.7 million for the three-month period ended March 31, 2013. The total includes $8.6 million for the acquisition of oil and natural gas properties in 5 individually immaterial acquisitions, $19.7 million for development projects and $0.3 million of exploratory capital expenditures.

Our capital expenditure budget, which predominantly consists of drilling, recompletion and well stimulation projects, is currently $100.0 million for the year ending December 31, 2014, of which $21.8 million has been expended during the three-months ended March 31, 2014. Our remaining borrowing capacity under our revolving credit facility is $501.9 million as of April 30, 2014. 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. 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, non-operated capital requirements 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. Based upon current oil and natural gas price expectations for the year ending December 31, 2014, 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 remaining planned capital expenditures of $78.2 million. Future cash distributions will be at levels to be determined based on cash available for distribution, any remaining borrowing capacity for cash distributions under our credit facility, requirements to repay debt and any other factors the board of directors of our general partner may consider. 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.

We enter into oil and natural gas derivative transactions to reduce the impact of oil and natural gas price volatility on our operations. Currently, we use derivatives to offset price volatility on NYMEX oil and natural gas prices, which do not include the additional net discount to NYMEX WTI that we typically experience in the Permian Basin. For the three-month periods ended March 31, 2014 and 2013, we had favorable (unfavorable) cash settlements of $(3.6) million and $2.6 million, respectively, related to our commodity derivatives. At March 31, 2014, we had in place oil and natural gas derivatives covering significant portions of our estimated 2014 through 2018 oil and natural gas production.

By reducing the cash flow effects of 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 institutions deemed by management as competent and competitive market makers. In addition, all of our current counterparties are current or former lenders under our revolving credit facility, which allows us to avoid margin calls. However, we cannot be assured that all of our counterparties will meet their obligations under our derivative contracts. Due to this uncertainty, we routinely monitor the creditworthiness of our counterparties.

The following tables summarize, for the periods indicated, our oil and natural gas derivatives currently in place as of April 30, 2014, covering the period from April 1, 2014 through December 31, 2018. We use derivatives, including swaps, enhanced swaps and three-way collars, as our mechanism for offsetting the cash flow effects of changes in commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to reduce the effects on cash flow of the floating prices we are paid by purchasers of our oil and natural gas. These transactions are mostly settled based upon the monthly average closing price of the front-month NYMEX WTI oil, the price on the last trading day of

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front-month NYMEX Henry Hub natural gas and published West Texas Waha, ANR-Oklahoma and Rocky Mountain CIG prices of natural gas.

Oil Swaps:

Calendar Year	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
April-December 2014	2,400,220	$93.66	$87.50	-	$101.50
2015	680,351	$92.48	$88.50	-	$100.20
2016	228,600	$87.94	$86.30	-	$99.85
2017	182,500	$84.75	$84.75

Natural Gas Swaps:

Calendar Year	Volumes (MMBtu)	Average Price per MMBtu	Price Range per MMBtu
April-December 2014	7,178,903	$4.39	$3.61	-	$6.47
2015	7,819,300	$4.51	$4.15	-	$5.82
2016	1,419,200	$4.30	$4.12	-	$5.30

We have also entered into multiple NYMEX WTI crude oil derivative three-way collar contracts. Each contract combines a long put, a short put and a short call. The use of the short put allows us to buy a put and sell a call at higher prices, thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk. If the market price is below the long put fixed price but above the short put fixed price, a three-way collar allows us to settle for the long put fixed price. A three-way collar also allows us to settle for WTI market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. The following table summarizes the three-way oil collar contracts currently in place as of April 30, 2014, covering the period from April 1, 2014 through June 30, 2017:

		Average Short	Average Long	Average Short
Calendar Year	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Call Price per Bbl
April-December 2014	605,000	$71.59	$96.59	$110.56
2015	1,308,500	$64.67	$89.67	$112.21
2016	621,300	$63.37	$88.37	$106.40
2017	72,400	$60.00	$85.00	$104.20

We have also entered into multiple NYMEX WTI crude oil derivative enhanced swap contracts. The first type of enhanced swap contract combines buying a lower-priced put, selling a higher-priced put, and using the net proceeds from these positions to simultaneously obtain a swap at above market prices (“enhanced swap price”). If the market price is at or above the higher-priced short put, this contract allows us to settle at the enhanced swap price. If the market price is below the higher-priced short put but above the lower-priced long put, this contract allows us to settle for the market price plus the spread between the enhanced swap price and the higher-priced short put. If the market price is at or below the lower-priced long put, this contract allows us to settle for the lower-priced long put plus the spread between the enhanced swap price and the higher-priced short put. The following table summarizes these type of enhanced swap contracts currently in place as of April 30, 2014, covering the period from January 1, 2015 to December 31, 2018:

		Average Long	Average Short	Average
Calendar Year	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Swap Price per Bbl
2015	365,000	$60.00	$80.00	$92.35
2016	183,000	$57.00	$82.00	$91.70
2017	182,500	$57.00	$82.00	$90.85
2018	127,750	$57.00	$82.00	$90.50

We have also entered into other multiple NYMEX WTI crude oil derivative enhanced swap contracts. This second type of enhanced swap contract combines selling a put and using the net proceeds to simultaneously obtain a swap at above market

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prices, i.e. the enhanced swap price. If the market price is at or above the put, this contract allows us to settle at the enhanced swap price. If the market price is below the put, this contract allows us to settle for the market price plus the spread between the enhanced swap price and the put price. The following table summarizes these type of enhanced swap contracts currently in place as of April 30, 2014, covering the period from January 1, 2015 to December 31, 2015:

		Average Short	Average
Calendar Year	Volumes (Bbls)	Put Price per Bbl	Swap Price per Bbl
2015	365,000	$70.00	$92.03

We have also entered into multiple NYMEX Henry Hub natural gas derivative three-way collar contracts. Each contract combines a long put, a short put and a short call. The use of the short put allows us to buy a put and sell a call at higher prices, thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk. If the market price is below the long put fixed price but above the short put fixed price, a three-way collar allows us to settle for the long put fixed price. A three-way collar also allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. The following table summarizes the three-way natural gas collar contracts currently in place as of April 30, 2014:

		Average Short Put	Average Long Put	Average Short Call
Calendar Year	Volumes (MMBtu)	Price per MMBtu	Price per MMBtu	Price per MMBtu
April-December 2014	320,000	$4.00	$4.65	$5.03
2015	1,440,000	$3.25	$4.05	$4.49

Financing Activities

Our net cash used in financing activities was $22.4 million for the three months ended March 31, 2014, compared to net cash used of $30.7 million for the three months ended March 31, 2013. During the three months ended March 31, 2014, total net repayments under our revolving credit facility were $12.0 million. The borrowings under the credit facility were used to finance our acquisition and development activities. Additionally, we had cash outflow during the three months ended March 31, 2014 in the amount of $34.3 million for distributions to unitholders which was funded from cash flow from operations. Cash provided by financing activities during the three months ended March 31, 2013 included $2.0 million in net borrowings under our revolving credit facility and $32.6 million for distributions to unitholders.

8% Senior Notes Due 2020

On December 4, 2012, we, together with our 100% owned subsidiary Legacy Reserves Finance Corporation, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 8% Senior Notes due 2020 (the "2020 Senior Notes"). The 2020 Senior Notes were issued at 97.848% of par. We received approximately $286.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by us. We used the net proceeds from this offering to fund a portion of the consideration paid for the acquisition of certain oil and natural gas properties located primarily in the Permian Basin from wholly-owned subsidiaries of Concho Resources, Inc., for a net cash purchase price of approximately $502.6 million.

We will have the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption, if redeemed during the twelve-month period beginning on December 1 of the years indicated below.

Year	Percentage
2016	104.000	%
2017	102.000	%
2018 and thereafter	100.000	%

Prior to December 1, 2016, we may redeem all or any part of the 2020 Senior Notes at the “make-whole” redemption price. In addition, prior to December 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes at the redemption price of 108% with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and

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unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by our 100% owned subsidiaries Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor's, other debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 10 - Subsidiary Guarantors in the Notes to the Condensed Consolidated Financial Statements for further details on our guarantors.

The indenture governing the 2020 Senior Notes limits our ability and the ability of certain of our subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem our subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including us) and we may pay distributions to the holders of our equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed our sum of available cash (as defined in our partnership agreement), net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of our subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and us and our subsidiaries will cease to be subject to such covenants. The indenture also includes customary events of default. We are in compliance with all financial and other covenants of the 2020 Senior Notes.

6.625% Senior Notes Due 2021

On May 28, 2013, we, together with our 100% owned subsidiary Legacy Reserves Finance Corporation, completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of our 6.625% Senior Notes due 2021 (the "2021 Senior Notes"). The 2021 Senior Notes were issued at 98.405% of par. We received approximately $240.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by us.

The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the interest rate and redemption provisions noted below. We will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest to the date of redemption, if any, if redeemed during the twelve-month period beginning on June 1 of the years indicated below.

Year	Percentage
2017	103.313	%
2018	101.656	%
2019 or thereafter	100.000	%

Prior to June 1, 2017, we may redeem all or any part of the 2021 Senior Notes at the “make-whole” redemption price as defined in the indenture. In addition, prior to June 1, 2016, we may at our option, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes at the redemption price of 106.625% with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. We are in compliance with all financial and other covenants of the 2021 Senior Notes.

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Our Revolving Credit Facility

Credit Facility

Previous Credit Agreement: On March 10, 2011, we entered into an amended and restated five-year, $1 billion secured revolving credit facility with BNP Paribas as administrative agent (as amended, the "Previous Credit Agreement"). Effective April 20, 2012, Wells Fargo Bank, National Association ("Wells Fargo"), replaced BNP Paribas as administrative agent as a result of the sale of BNP Paribas' energy lending practice to Wells Fargo. Borrowings under the Previous Credit Agreement were set to mature on March 10, 2016. The amount available for borrowing under the Previous Credit Agreement at any one time was limited to the borrowing base, which was set at $800.0 million as of March 31, 2014.

As of March 31, 2014, we were in compliance with all covenants of the Previous Credit Agreement.

Current Credit Agreement: On April 1, 2014, we entered into an amended and restated five-year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, Compass Bank, as syndication agent, UBS Securities LLC and U.S. Bank National Association, as co-documentation agents and the lenders party thereto (the “Current Credit Agreement”). Borrowings under the Current Credit Agreement mature on April 1, 2019. Our obligations under the Current Credit Agreement are secured by mortgages on over 80% of the total value our oil and natural 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 and contains a $2 million sub-limit for letters of credit. The borrowing base is currently set at $800.0 million. As of April 30, 2014, we have approximately $298.0 million drawn under the Current Credit Agreement, leaving approximately $501.9 million of current availability. The borrowing base is subject to semi-annual redeterminations on April 1 and October 1 of each year, commencing October 1, 2014. Additionally, either we 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 request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement so long as it does not increase the borrowing base then in effect.

We may at any time issue additional senior notes or new debt whose proceeds are used to refinance such senior notes, subject to specified conditions in the Current Credit Agreement, which include that upon the issuance of such senior notes or new debt, the borrowing base shall be reduced by an amount equal to (i) (A) in the case of the senior notes, 25% of the stated principal amount of the senior notes and (B) in the case of the new debt, 25% of the portion of the new debt that exceeds the original principal amount of the senior notes or (ii) in the sole discretion of the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement prior to the issuance of the senior notes or new debt, a lesser amount. In addition, after giving pro forma effect to the issuance of any additional senior notes, we must continue to have a ratio of total debt to EBITDA of not more than 4.0 to 1.0 for four fiscal quarters preceding the issuance of the senior notes. 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 natural 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 ABR loans or Eurodollar loans. Interest on the loans is determined as follows:

• with respect to ABR loans, the alternate base rate equals the highest of (i) the prime rate, (ii) the Federal funds effective rate plus 0.50% and (iii) the one-month London interbank rate (LIBOR) plus 1.00%, in each case plus an applicable margin ranging from and including 0.50% and 1.50% per annum, determined by the percentage of the borrowing base then in effect that is drawn, or

• with respect to any Eurodollar loans, one-, two-, three- or six-month LIBOR, or, upon the consent of all of the lenders, twelve month LIBOR, in each case plus an applicable margin ranging from and including 1.50% and 2.50% per annum, determined by the percentage of the borrowing base then in effect that is drawn.

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We pay a commitment fee ranging from and including 0.375% and 0.500% on the average daily amount of the unused amount of the commitments under the Current Credit Agreement.

The Current Credit Agreement 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 our business; or

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

The Current Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

• total debt to EBITDA of not more than 4.0 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 FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives.

EBITDA is defined as net income (loss) plus (i) interest expense, (ii) expense for income and income based taxes paid or accrued, (iii) depreciation, depletion, amortization, accretion and impairment, including without limitation, impairment of goodwill, and (iv) any non-cash items associated with (a) mark to market accounting related to derivatives or investments, (b) equity compensation and/or (c) any gains or losses attributable to writeups or writedowns of assets, including ceiling test writedowns; less, all non-cash items increasing net income, all on a consolidated basis.

If an event of default exists under the Current Credit Agreement, 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 $2.0 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

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generally defined to mean members of our board of directors as of April 1, 2014 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’s ceasing to be our sole general partner;

• the entry of, and failure to pay, one or more adverse judgments in excess of $2.0 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 $2.0 million in any year.

We periodically enter into interest rate swap transactions to mitigate the volatility of interest rates. As of March 31, 2014, we had interest rate swaps on notional amounts of $204 million with a weighted average fixed rate of 1.78%. These swaps mature between August 2014 and November 2015.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of March 31, 2014, our critical accounting policies were consistent with those discussed in our Annual Report on Form 10-K for the period ended December 31, 2013.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves, the fair value of assets and liabilities acquired in business combinations, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. Actual results could differ from these estimates.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The 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. These derivative instruments are discussed in Item 1. Financial Statements – Notes to Consolidated Financial Statements – Note 6 Derivative Financial Instruments.

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 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.

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The prices we receive for production depend on many factors outside of our control, such as the strength of the global economy and the supply of oil and natural gas outside of the United States.

We periodically enter into and anticipate entering into derivative transactions with respect to a portion of our projected oil and natural gas production through various transactions that offset changes in the future prices received. These transactions may include swaps, enhanced swaps and three-way collars. These derivative transactions 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.

As of March 31, 2014, the fair market value of our commodity derivative positions was a net asset of $5.4 million based on NYMEX futures prices from April 2014 to December 2018 for both oil and natural gas. As of December 31, 2013, the fair market value of our commodity derivative positions was a net asset of $17.7 million based on NYMEX futures prices from January 2014 to December 2017 for both oil and natural gas. For more discussion about our derivative transactions and to see a table listing the oil and natural gas derivatives from April 2014 through December 2018, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Investing Activities.”

Interest Rate Risks

At March 31, 2014, we had debt outstanding under its revolving credit facility of $360 million, which incurred interest at floating rates in accordance with its revolving credit facility. The average annual interest rate incurred by us under our revolving credit facility for the three-month period ended March 31, 2014 was 3.0%. A 1% increase in LIBOR on our outstanding debt under our revolving credit facility as of March 31, 2014 would result in an estimated $1.56 million increase in annual interest expense assuming our current interest rate hedges remain in place and do not expire. We have entered into interest rate swaps with a weighted-average fixed rate of 1.78% to mitigate the volatility of interest rates on notional amounts of $204 million of floating rate debt, which will expire during 2014 and 2015.

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, 2014. 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, 2014, 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 1.  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 information set forth in this report, you should carefully consider the factors discussed under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013, which could materially affect our business, financial condition or future results. In addition, many of the risks identified in our Annual Report on Form 10-K as applying to our units, including without limitation those regarding the issuance of additional partnership interests and the ability to pay distributions, also apply to our Series A Preferred Units (as defined below). The risks described in these reports 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.

Risks Related to the Series A Preferred Units

Our Series A Preferred Units rank senior in right of payment to our units, and we are unable to make any distribution to our unitholders unless full cumulative distributions are made on our Series A Preferred Units.

On April 17, 2014, we issued 2,000,000 of our 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) with a liquidation preference of $25.00 per unit. The Series A Preferred Units represent perpetual equity interests in us and rank senior in right of payment to our units. Distributions on the Series A Preferred Units are cumulative from the date of original issue and are payable monthly on the 15th day of each month. No distribution may be declared or paid or set apart for payment on the units, or any other junior securities, unless full cumulative distributions have been or contemporaneously are being paid or provided for on all outstanding Series A Preferred Units and any parity securities through the most recent respective distribution payment dates.

The Series A Preferred Units are subordinated to our existing and future debt obligations, and your interests could be diluted by the issuance of additional partnership securities, including additional Series A Preferred Units, and by other transactions.

The Series A Preferred Units are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under our Current Credit Agreement, our 8% Senior Notes due 2020 and our 6.625% Senior Notes due 2021). We may incur additional debt under our Current Credit Agreement or future credit facilities or by issuing additional senior or subordinated debt securities. The payment of principal and interest on our debt reduces cash available for distribution to unitholders, including the holders of Series A Preferred Units.

The issuance of additional partnership securities pari passu with or senior to the Series A Preferred Units would dilute the interests of the holders of the Series A Preferred Units, and any issuance of Senior Securities or Parity Securities or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Units. Only the Change of Control provision relating to the Series A Preferred Units protects the holders of the Series A Preferred Units in the event of a highly leveraged or other transaction, including a merger or the sale, lease or conveyance of all or substantially all our assets or business, which might adversely affect the holders of the Series A Preferred Units.

Treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our Series A Preferred Units than the holders of our units.

The tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series A Preferred Units as ordinary income. Although a holder of Series A Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions monthly. Otherwise, the holders of Series A Preferred Units are generally not anticipated to share in our items of income, gain, loss or

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deduction. Nor will we allocate any share of our nonrecourse liabilities to the holders of Series A Preferred Units. If the Series A Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Series A Preferred Units.

A holder of Series A Preferred Units will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Series A Preferred Units. Subject, in certain circumstances, to rules requiring a blended basis among multiple partnership interests, the tax basis of a Series A Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the unitholder to acquire such Series A Preferred Unit. Gain or loss recognized by a unitholder on the sale or exchange of a Series A Preferred Unit held for more than one year generally will be taxable as long‑term capital gain or loss. Because holders of Series A Preferred Units will not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the Series A Preferred Units by tax‑exempt investors, such as employee benefit plans and individual retirement accounts, and non‑U.S. persons raises issues unique to them. Distributions to non‑U.S. holders of the Series A Preferred Units will be treated as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) and will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non‑U.S. holders. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non‑U.S. holders may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax exempt investors is not certain. If you are a tax‑exempt entity or a non‑U.S. person, you should consult your tax advisor with respect to the consequences of owning our Series A Preferred Units.

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

Purchases of Equity Securities

	(a)	(b)	(c)	(d)
Period	Total number of units purchased	Price paid per unit	Total number of units purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value of units) that may yet be purchased under the plans or programs
February 18, 2014	20,631(1)	$27.24	—	—
March 19, 2014	109(2)	$25.47	—	—

(1) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $27.24 per unit, the closing price of Legacy's units on the NASDAQ Global Market on such date.

(2) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $25.47 per unit, the closing price of Legacy's units on the NASDAQ Global Market on such date.

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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	Second Amended and Restated Agreement of Limited Partnership of Legacy Reserves LP (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K (File No. 001-33249) filed April 17, 2014, Exhibit 3.1)
3.4	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)
3.5	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)
3.6	First Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP's Quarterly Report on Form 10-Q (File No. 001-33249) filed May 4, 2012, Exhibit 3.6)
3.7	Second Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP's Quarterly Report on Form 10-Q (File No. 001-33249) filed May 4, 2012, Exhibit 3.7)
4.1	Indenture, dated as of May 28, 2013, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (including form of the 6.625% Senior Notes due 2021) (Incorporated by reference to Legacy's Current Report on Form 8-K (File No. 001-33249) filed May 31, 2013, Exhibit 4.1)
4.2	Registration Rights Agreement, dated as of May 28, 2013, by and among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, UBS Securities LLC, Barclays Capital Inc., Citigroup Global Markets Inc. and J.P. Morgan Securities LLC as representatives of the Initial Purchasers named therein. (Incorporated by reference to Legacy's Current Report on Form 8-K (File No. 001-33249) filed May 31, 2013, Exhibit 4.2)
10.1	Fifth Amendment to Second Amended and Restated Credit Agreement, dated March 10, 2011, by and between Legacy Reserves LP, Wells Fargo Bank, National Association, as administrative agent, and certain other financial institutions parties thereto as Lenders (Incorporated by reference to Legacy's Quarterly Report on Form 10-Q (File No. 001-33249) filed August 7, 2013, Exhibit 10.1).
10.2	Third Amended and Restated Credit Agreement, dated as of April 1, 2014, among Legacy Reserves LP, Wells Fargo Bank, National Association, as administrative agent, Compass Bank, as syndication agent, UBS Securities LLC and U.S. Bank National Association, as co-documentation agents, and certain other financial institutions party thereto as Lenders (Incorporated by reference to Legacy's Current Report on Form 8-K (File No. 001-33249) filed April 2, 2014, Exhibit 10.1).
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)
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.DEF**	XBRL Taxonomy Extenstion Definition Linkbase Document
101.PRE**	XBRL Taxonomy Extenstion Presentation Linkbase Document
101.CAL**	XBRL Taxonomy Extenstion Calculation Linkbase Document
101.LAB**	XBRL Taxonomy Extenstion Label Linkbase Document

* Filed herewith

** Filed electronically herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	LEGACY RESERVES LP By:  Legacy Reserves GP, LLC, its General Partner
May 6, 2014	By:	/s/ James Daniel Westcott
		James Daniel Westcott
		Executive Vice President and Chief Financial Officer
		(On behalf of the Registrant and as Principal Financial Officer)

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