LEGACY RESERVES LP (Form: 10-Q, Received: 10/31/2012 17:24:57)

Calendar Year

Volumes (Bbls)

October-December 2012

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 September 30, 2012

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-33249

Legacy Reserves LP

(Exact name of registrant as specified in its charter)



Delaware		16-1751069
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

303 W. Wall, Suite 1400 Midland, Texas		79701
(Address of principal executive offices)		(Zip code)

(432) 689-5200

(Registrant’s telephone number, including area code)

Indicate by 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

48,099,419 units representing limited partner interests in the registrant were outstanding as of October 30, 2012 .

TABLE OF CONTENTS



		Page
	Glossary of Terms	Page 3

	Part I - Financial Information
Item 1.	Financial Statements.
	Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011 (Unaudited).	Page 6
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011 (Unaudited).	Page 8
	Condensed Consolidated Statement of Unitholders' Equity for the nine months ended September 30, 2012 (Unaudited).	Page 9
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011 (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 26
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 42
Item 1A.	Risk Factors.	Page 42
Item 6.	Exhibits.	Page 42
	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 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 re-completion 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 re-completion. 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.

Re-completion. 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 un-weighted 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
	September 30, 2012			December 31, 2011
	(In thousands)
Current assets:
Cash and cash equivalents	$	4,366		$	3,151
Accounts receivable, net:
Oil and natural gas	35,161			35,489
Joint interest owners	13,322			10,299
Other	394			204
Fair value of derivatives (Notes 5 and 6)	9,633			7,117
Prepaid expenses and other current assets	4,144			3,525
Total current assets	67,020			59,785
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting	1,544,197			1,389,326
Unproved properties	28,746			20,063
Accumulated depletion, depreciation, amortization and impairment	(531,184		)	(450,060		)
	1,041,759			959,329
Other property and equipment, net of accumulated depreciation and amortization of $4,306 and $3,530, respectively	2,726			3,310
Deposits on pending acquisitions	930			—
Operating rights, net of amortization of $3,407 and $3,034, respectively	3,610			3,983
Fair value of derivatives (Notes 5 and 6)	19,950			10,188
Other assets, net of amortization of $7,480 and $6,337, respectively	5,930			6,611
Investment in equity method investee	369			282
Total assets	$	1,142,294		$	1,043,488

See accompanying notes to condensed consolidated financial statements.

Page 6

LEGACY RESERVES LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



LIABILITIES AND UNITHOLDERS' EQUITY
	September 30, 2012		December 31, 2011
	(In thousands)
Current liabilities:
Accounts payable	$	6,224	$	3,286
Accrued oil and natural gas liabilities (Note 1)	52,262		45,351
Fair value of derivatives (Notes 5 and 6)	9,024		18,905
Asset retirement obligation (Note 7)	22,158		20,262
Other (Note 9)	8,596		9,646
Total current liabilities	98,264		97,450
Long-term debt (Note 2)	452,000		337,000
Asset retirement obligation (Note 7)	105,490		100,012
Fair value of derivatives (Notes 5 and 6)	7,932		18,897
Other long-term liabilities	1,628		1,794
Total liabilities	665,314		555,153
Commitments and contingencies (Note 4)
Unitholders' equity:
Limited partners' equity - 47,868,942 and 47,801,682 units issued and outstanding at September 30, 2012 and December 31, 2011, respectively	476,883		488,264
General partner's equity (approximately 0.04%)	97		71
Total unitholders' equity	476,980		488,335
Total liabilities and unitholders' equity	$	1,142,294	$	1,043,488

See accompanying notes to condensed consolidated financial statements.

Page 7

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In thousands, except per unit data)
Revenues:
Oil sales	$	70,173		$	63,387		$	212,097		$	196,220
Natural gas liquids (NGL) sales	3,492			4,924			10,742			13,896
Natural gas sales	10,531			16,061			33,166			39,858
Total revenues	84,196			84,372			256,005			249,974

Expenses:
Oil and natural gas production	30,728			24,109			82,023			71,304
Production and other taxes	5,137			5,211			15,040			15,101
General and administrative	6,993			3,817			18,604			14,630
Depletion, depreciation, amortization and accretion	24,833			22,446			73,042			64,152
Impairment of long-lived assets	7,277			4,678			22,556			5,869
(Gain) loss on disposal of assets	260			(35		)	(3,064		)	(680		)
Total expenses	75,228			60,226			208,201			170,376

Operating income	8,968			24,146			47,804			79,598

Other income (expense):
Interest income	3			5			11			12
Interest expense (Notes 2, 5 and 6)	(5,285		)	(5,764		)	(14,256		)	(15,633		)
Equity in income of partnership	30			35			87			107
Realized and unrealized net gains (losses) on commodity derivatives (Notes 5 and 6)	(27,177		)	107,603			34,084			67,753
Other	(51		)	3			(87		)	(55		)
Income (loss) before income taxes	(23,512		)	126,028			67,643			131,782
Income tax expense	(54		)	(928		)	(878		)	(1,198		)
Net income (loss)	$	(23,566	)	$	125,100		$	66,765		$	130,584

Income (loss) per unit - basic and diluted (Note 8)	$	(0.49	)	$	2.87		$	1.40		$	3.00
Weighted average number of units used in computing net income (loss) per unit -
Basic	47,869			43,587			47,840			43,560
Diluted	47,869			43,607			47,840			43,572

See accompanying notes to condensed consolidated financial statements.

Page 8

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012

(UNAUDITED)



	Number of Limited Partner Units	Limited Partner			General Partner		Total Unitholders' Equity
	(In thousands)
Balance, December 31, 2011	47,802	$	488,264		$	71	$	488,335
Units issued to Legacy Board of Directors for services	17	497			—		497
Compensation expense on restricted unit awards issued to employees	—	1,229			—		1,229
Vesting of restricted units	50	—			—		—
Offering costs associated with the issuance of units	—	(2		)	—		(2		)
Distributions to unitholders, $1.665 per unit	—	(79,844		)	—		(79,844		)
Net income	—	66,739			26		66,765
Balance, September 30, 2012	47,869	$	476,883		$	97	$	476,980

See accompanying notes to condensed consolidated financial statements.

Page 9

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Cash flows from operating activities:
Net income	$	66,765		$	130,584
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	73,042			64,152
Amortization of debt issuance costs	1,143			1,160
Impairment of long-lived assets	22,556			5,869
Gains on derivatives	(35,141		)	(67,556		)
Equity in income of partnership	(87		)	(107		)
Unit-based compensation	333			(410		)
Gain on disposal of assets	(3,064		)	(680		)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	328			(6,647		)
Increase in accounts receivable, joint interest owners	(3,023		)	(7,320		)
Increase in accounts receivable, other	(190		)	(146		)
Increase in other assets	(619		)	(1,508		)
Increase in accounts payable	2,938			7,153
Increase in accrued oil and natural gas liabilities	6,911			21,140
Decrease in other liabilities	(2,453		)	(1,512		)
Total adjustments	62,674			13,588
Net cash provided by operating activities	129,439			144,172
Cash flows from investing activities:
Investment in oil and natural gas properties	(164,322		)	(147,528		)
Increase in deposits on pending acquisitions	(930		)	(2,638		)
Proceeds from sale of assets	9,102			—
Investment in other equipment	(1,014		)	(775		)
Goodwill	(7,770		)	—
Net cash settlements on commodity derivatives	2,018			(3,765		)
Net cash used in investing activities	(162,916		)	(154,706		)
Cash flows from financing activities:
Proceeds from long-term debt	335,000			267,000
Payments of long-term debt	(220,000		)	(186,000		)
Payments of debt issuance costs	(462		)	(5,034		)
Offering costs associated with the issuance of units	(2		)	2,283
Distributions to unitholders	(79,844		)	(69,588		)
Net cash provided by financing activities	34,692			8,661
Net increase (decrease) in cash and cash equivalents	1,215			(1,873		)
Cash and cash equivalents, beginning of period	3,151			3,478

Cash and cash equivalents, end of period	$	4,366		$	1,605

Non-cash investing and financing activities:

Asset retirement obligation costs and liabilities	$	—		$	(592	)
Asset retirement obligations associated with property acquisitions	$	6,036		$	4,688

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 and its affiliated entities are referred to as Legacy, LRLP or the Partnership 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 September 30, 2012 and for the three and nine months ended September 30, 2012 and 2011 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, 2011 .

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 0.04% 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 LRLP’s general partner and its affiliates, provided that a unit majority has elected a successor general partner.

• Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year.

In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRLP’s general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation.

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. Legacy has acquired oil and natural gas producing properties and undrilled leaseholds.


(b)	Accrued Oil and Natural Gas Liabilities

Below are the components of accrued oil and natural gas liabilities as of September 30, 2012 and December 31, 2011 .

Page 11



	September 30, 2012		December 31, 2011
	(In thousands)
Revenue payable to joint interest owners	$	19,086	$	19,972
Accrued lease operating expense	8,455		8,004
Accrued capital expenditures	8,488		6,920
Accrued ad valorem tax	12,136		5,171
Other	4,097		5,284
	$	52,262	$	45,351


(2)	Credit Facility

Previous Credit Agreement: On March 27, 2009, Legacy entered into a three-year secured revolving credit facility with BNP Paribas as administrative agent (the “Previous Credit Agreement”). Borrowings under the Previous Credit Agreement were set to mature on April 1, 2012. The Previous Credit Agreement permitted borrowings in the lesser amount of (i) the borrowing base, or (ii) $600 million . The borrowing base under the Previous Credit Agreement, initially set at $340 million , was increased to $410 million on March 31, 2010. Under the Previous Credit Agreement, interest on debt outstanding was charged based on Legacy’s selection of a LIBOR rate plus 2.25% to 3.0% , or the alternate base rate (“ABR”) which equaled the highest of the prime rate, the Federal funds effective rate plus 0.50% or LIBOR plus 1.50% , plus an applicable margin between 0.75% and 1.50% .

Current Credit Agreement: 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 (the "Current 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 Current Credit Agreement mature on March 10, 2016. The amount available for borrowing at any one time is limited to the borrowing base with a $2 million sub-limit for letters of credit. The borrowing base under the Current Credit Agreement was redetermined and increased to $595 million on September 28, 2012, and was further increased to $600 million on October 1, 2012 upon the closing of an individually immaterial acquisition of oil and natural gas properties. The borrowing base is subject to semi-annual re-determinations on or around April 1 and October 1 of each year. Additionally, either Legacy or the lenders may, once during each calendar year, elect to re-determine the borrowing base between scheduled re-determinations. Legacy also has the right, once during each calendar year, to request the re-determination 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. Under the Current Credit Agreement, interest on debt outstanding is charged based on Legacy's selection of a one-, two-, three- or six-month LIBOR rate plus 1.75% to 2.75% , or the ABR which equals the highest of the prime rate, the Federal funds effective rate plus 0.50% or one-month LIBOR plus 1.00% , plus an applicable margin from 0.75% to 1.75% per annum, determined by the percentage of the borrowing base then in effect that is drawn.

The borrowing base permits Legacy to issue up to $500 million in aggregate principal amount of senior notes or new debt issued to refinance 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 will be reduced by an amount equal to (i) in the case of senior notes, 25% of the stated principal amount of the senior notes and (ii) in the case of new debt, 25% of the portion of the new debt that exceeds the original principal amount of the senior notes.

As of September 30, 2012 , Legacy had outstanding borrowings of $452 million at a weighted-average interest rate of 2.73% and approximately $142.9 million of availability remaining under the Current Credit Agreement. For the nine -month period ended September 30, 2012 , Legacy paid in cash $9.1 million of interest expense on the Current Credit Agreement. Legacy’s Current Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:


•	total debt as of the last day of the most recent quarter to EBITDA (as defined in the Current Credit Agreement) in total over the last four quarters of not more than 4.0 to 1.0; and


•	consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0,

Page 12

excluding non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives.

At September 30, 2012 , Legacy was in compliance with all covenants of the Current Credit Agreement.


(3)	Related Party Transactions

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy's general partner, and Kyle A. McGraw, Director, Executive Vice President and Chief Development Officer of Legacy's general partner, own partnership interests in entities which, in turn, own a combined non-controlling 4.16% interest as limited partners in the partnership which owns the building that Legacy occupies. Monthly rent is $33,462 , without respect to property taxes, insurance and operating expenses. The lease expires in September 2015.

Legacy uses Lynch, Chappell and Alsup for some of its legal services. Alan Brown, son of Dale Brown, a director of Legacy, and brother of Cary D. Brown, was a less than ten percent shareholder in this firm until he resigned from his position on September 1, 2011. Legacy paid legal fees, during Alan Brown's tenure, to this firm of $109,881 for the nine months ended September 30, 2011 .

During the nine months ended September 30, 2012 , Legacy acquired a 5% working interest in approximately 129,428 acres of prospective Cline Shale acreage from FireWheel Energy, LLC ("FireWheel"), the operator of the properties, for $7.2 million . FireWheel is a private-equity funded oil and natural gas exploration company in which Alan 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, except as discussed below, 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.

On April 15, 2011, the Eleventh Court of Appeals (Case No. 11-09-00348-CV), in an appeal styled Raven Resources, LLC, Appellant v. Legacy Reserves Operating, LP, Appellee , on appeal from the 385th District Court, Midland County, Texas, reversed and rendered in part and reversed and remanded in part the trial court’s summary judgment, dated November 10, 2009 (Cause No. CV 46609) (the "Trial Court Summary Judgment"), in favor of Legacy Reserves Operating LP ("Legacy Operating"), a subsidiary of Legacy Reserves LP. As set forth below, on March 15, 2012, the Court of Appeals affirmed the Trial Court Summary Judgment in favor of Legacy Operating.

In its original petition to the trial court, filed August 15, 2008, Raven Resources, LLC ("Raven") had sought, among other things, a declaratory judgment that the purchase agreement dated July 11, 2007 (the "PSA") providing for the purchase by Legacy Operating of various non-operated oil and natural gas properties and interests primarily in the Permian Basin for $20.3 million , subject to adjustment, was void, as a matter of law, alleging an employee of Raven had forged the signature of David Stewart, Raven's managing member. Raven also asked the trial court to rescind the transaction, and to account for all proceeds received by Legacy Operating since the properties were originally conveyed. Further, Raven alleged that Legacy Operating had failed to pay the full purchase price for the properties as David Stewart had allegedly only been aware of a June 27, 2007 draft of a purchase agreement, which provided for a $26.6 million purchase price, whereas the PSA, following property due diligence and reducing the list of properties to be purchased, contained a reduced purchase price of $20.3 million . Raven alleged that David Stewart, despite having signed 35 assignments incorporating the PSA as well as a certificate acknowledging Mr. Stewart had executed the PSA, was not aware of the revised terms of the PSA, nor the amounts of payments made to Raven until August 27, 2007, when Mr. Stewart purportedly discovered the employee's fraud. With the proceeds received from Legacy at the closing of the transaction on August 3, 2007, Raven had paid its debts and its partners. In addition, Raven alleged that Legacy Operating benefitted from the fraud promulgated by Michael Lee, and asked the trial court for damages in excess of $6 million . Raven does not claim that Legacy knew about the forgery.

Legacy Operating filed a counterclaim for declaratory relief and for money damages based upon indemnity obligations and post-closing adjustments. The trial court granted a partial summary judgment in favor of Legacy Operating, denied a partial summary judgment sought by Raven, and entered a take-nothing judgment against Raven. The trial court severed the counterclaims brought by Legacy Operating.

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In its April 15, 2011 ruling (the "Original Opinion"), the Court of Appeals reversed the Trial Court Summary Judgment and rendered judgment that the PSA was void, as a matter of law, and that a void instrument is not subject to ratification. Further, while the Appeals Court held that the incorporation of the PSA into the assignments for the transfer of the properties will not void the assignments, the assignments were not complete in and of themselves in the absence of the terms of the PSA. The Court of Appeals further remanded to the trial court any issues regarding the repayment of the funds advanced by Legacy Operating, as well as any issues regarding any consideration received by Legacy Operating from or related to the properties.

Legacy Operating filed a motion for rehearing on May 11, 2011 (the "Legacy Motion for Rehearing"). On January 12, 2012, the Court of Appeals granted the Legacy Motion for Rehearing, withdrew its former opinion and judgment, and issued a new opinion and judgment which affirmed the judgment of the trial court granting a partial summary judgment in favor of Legacy Operating, denying a partial summary judgment sought by Raven, and entering a take-nothing judgment against Raven.

The Court of Appeals held that, as a matter of law, certain assignments which specifically incorporated the terms of the purchase agreement dated July 11, 2007 providing for the purchase by Legacy Operating from Raven of various non-operated oil and gas properties and interests in the Permian Basin for $20.3 million , constituted valid, enforceable agreements binding upon Raven and Legacy Operating.

Raven did not file a response to the Legacy Motion for Rehearing and the Court of Appeals did not request one. Subsequently, on January 24, 2012, Raven filed a motion for rehearing and on January 26, 2012, the Court of Appeals issued an order withdrawing its opinion and judgment dated January 12, 2012 in order to allow Raven to respond to the Legacy Motion for Rehearing on or before February 10, 2012. On February 10, 2012, Raven filed its response to the Legacy Motion for Rehearing.

On March 15, 2012, the Court of Appeals granted the Legacy Motion for Rehearing, withdrew the Original Opinion and affirmed the trial court's take nothing judgment against Raven. On April 27, 2012, Raven filed a petition for review with the Supreme Court of Texas, requesting that the Supreme Court reverse the Court of Appeals' judgment in every respect except its conclusion that forged documents are void and ineffective and render judgment that Raven was entitled to summary judgment, entitled to rescind the assignments and unwind the transaction. Alternatively, Raven requested that the Supreme Court reverse the Court of Appeals' judgment insofar as it grants Legacy's motion for partial summary judgment and remand the case to the trial court for further proceedings. The Texas Supreme Court has requested the parties to provide full briefing on the merits of the issue raised in Raven's petition for review.

At this time, Legacy cannot predict the Texas Supreme Court's action on Raven's petition for review, or the eventual outcome of this matter. Legacy currently believes that any outcome, which may include no payment, the unwinding of the transaction (which Legacy expects would have an effect of less than $6 million) or a payment of approximately $6 million to Raven, will not have a material impact on its financial condition or ability to make cash distributions at expected levels, though it could have a material adverse effect on its net income (loss).

Additionally, Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected.

Legacy has employment agreements with its officers that specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits, respectively.


(5)	Fair Value Measurements

As defined in Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("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, commodity collars and oil swaptions. 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 September 30, 2012 :



	Fair Value Measurements at September 30, 2012 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)			September 30, 2012
	(In thousands)
LTIP liability (a)	$	—	$	(4,076	)	$	—		$	(4,076	)
Oil and natural gas derivative swaps	—		(4,894		)	13,545			8,651
Oil and natural gas collars	—		—			15,607			15,607
Oil swaptions	—		—			(636		)	(636		)
Interest rate swaps	—		(10,995		)	—			(10,995		)
Total	$	—	$	(19,965	)	$	28,516		$	8,551


(a)	See Note 9 for further discussion on unit-based compensation expenses and the related 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 estimates the option value of the contract floors and ceilings and oil swaptions using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Significant changes in the quoted forward prices for commodities and changes in market volatility generally leads to corresponding changes in the fair value measurement of our oil and natural gas derivative contracts. In order to estimate the fair value of our

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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 majority of the Partnership’s counterparties is mitigated by the fact that such counterparties (or their affiliates) are also bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties including those who are no longer lenders under the revolving credit facility.

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						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In thousands)
Beginning balance	$	41,851		$	9,431		$	30,054		$	24,641
Total gains (losses)	(8,111		)	31,749			13,260			22,708
Settlements, net	(5,224		)	(3,162		)	(14,798		)	(9,331		)
Ending balance	$	28,516		$	38,018		$	28,516		$	38,018
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of September 30, 2012 and 2011	$	(13,335	)	$	28,587		$	(1,538	)	$	13,377

Fair Value on a Non-Recurring Basis

Legacy follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Legacy, ASC 820-10 applies to 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 for which fair value is used.

The asset retirement obligation 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.

Assets measured at fair value during the nine -month period ended September 30, 2012 include:



	Fair Value Measurements at September 30, 2012 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)	$	—	$	—	$	20,377
Acquisitions (b)	$	—	$	—	$	115,044
Total	$	—	$	—	$	135,421


(a)	Legacy utilizes ASC 360-10-35 to periodically review 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

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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 nine -month period ended September 30, 2012 , Legacy incurred impairment charges of $14.8 million as oil and natural gas properties with a net cost basis of $35.2 million were written down to their fair value of $20.4 million . Inclusive in this amount is $6.5 million of impairment on an available-for-sale property which Legacy has entered into an option agreement to sell all but a minority royalty interest in the property to a third party. The option can be exercised at any time prior to January 4, 2013. As such, Legacy has impaired the property to reduce its carrying value to its estimated fair value.

The remaining $7.8 million of impairment during the nine -month period ended September 30, 2012 was impairment of goodwill recognized on an acquisition of oil and natural gas properties. During the nine -month period ended September 30, 2012 , Legacy entered into a purchase and sale agreement with a third party to acquire certain oil and natural gas properties, the purchase price of which was negotiated as of the date of the agreement. During the period between the agreement date and the date of closing the acquisition, oil futures prices declined significantly, thereby reducing the fair value of the properties acquired at the date of close. As the purchase price exceeded the fair value of the properties acquired, goodwill amounting to $7.8 million was recognized and subsequently tested for impairment. As of September 30, 2012 , all of the goodwill associated with this acquisition has been impaired.

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)

Legacy utilizes ASC 805-10 to identify and record the fair value of assets and liabilities acquired in a business combination. During the nine -month period ended September 30, 2012 , Legacy acquired oil and natural gas properties, inclusive of unproved acreage acquisitions, with a fair value of $115.0 million in 15 individually immaterial transactions. 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 $452 million as of September 30, 2012 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.


(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, swaptions 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 to 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.

All of these price risk management transactions are considered derivative instruments and are accounted for in accordance with FASB Accounting Standards Codification 815, Disclosures About Derivative Instruments and Hedging Activities ("ASC 815") . 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 as of September 30, 2012 and December 31, 2011 with changes in fair value being recorded in earnings for the three and nine months ended September 30, 2012 and 2011 .

By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy is exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates repayment risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties that are parties to its Current Credit Agreement.

For the three and nine months ended September 30, 2012 and 2011 , Legacy recognized realized and unrealized gains and losses related to its oil and natural gas derivative transactions. The net gain (loss) from derivative activities was as follows:

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(In thousands)
Crude oil derivative contract settlements	$	2,108		$	(1,857	)	$	(10,949	)	$	(11,849	)
Natural gas derivative contract settlements	4,000			2,703			12,967			8,084
Total commodity derivative contract settlements	6,108			846			2,018			(3,765		)
Unrealized change in fair value - oil contracts	(26,196		)	104,026			43,911			71,663
Unrealized change in fair value - natural gas contracts	(7,089		)	2,731			(11,845		)	(145		)
Total unrealized change in fair value of commodity derivative contracts	(33,285		)	106,757			32,066			71,518
Total realized and unrealized gain (loss) on commodity derivative contracts	$	(27,177	)	$	107,603		$	34,084		$	67,753

As of September 30, 2012 , 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
October-December 2012(a)	583,570	$89.64	$67.72	-	$109.20
2013(a)	1,571,443	$90.34	$80.10	-	$108.65
2014	901,014	$92.89	$87.50	-	$103.75
2015	362,851	$93.73	$90.50	-	$100.20
2016	45,600	$94.53	$91.00	-	$99.85

(a)

On October 6, 2010, as part of an oil swap transaction entered into with a counterparty, Legacy sold two call options to the counterparty that allow the counterparty to extend a swap transaction covering calendar year 2011 to either 2012, 2013 or both calendar years. The counterparty exercised the option covering calendar year 2012 on December 30, 2011 and must exercise or decline the option covering calendar year 2013 on December 31, 2012. As the option was exercised for calendar year 2012, Legacy will pay the counterparty floating prices and receive a fixed price of $98.25 per Bbl on annual notional volumes of 183,000 Bbls ( 46,000 Bbls remaining as of September 30, 2012 ). For calendar year 2013, if exercised, Legacy would pay the counterparty floating prices and receive a fixed price of $98.25 per Bbl on annual notional volumes of 182,500 Bbls in 2013. The premium paid by the counterparty to Legacy for the two call options was in the form of an increase in the fixed price that we received pursuant to the 2011 swap of $98.25 per Bbl on 182,500 Bbls, or 500 Bbls per day, rather than the prevailing market price of approximately $87.00 per Bbl. These additional potential volumes related to the unexercised 2013 option are not reflected in the above table.

As of September 30, 2012 , Legacy had the following NYMEX WTI crude oil derivative collar contract that combines a long put option or “floor” with a short call option or “ceiling” as indicated below:

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As of September 30, 2012 , 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	Average	Average
Calendar Year	Volumes (Bbls)	Short Put Price	Long Put Price	Short Call Price
October-December 2012	110,400	$68.13	$95.00	$113.54
2013	795,670	$66.24	$91.92	$112.25
2014	1,226,130	$65.64	$90.86	$113.29
2015	1,126,000	$65.43	$90.43	$114.76
2016	438,300	$64.78	$89.78	$110.54
2017	72,400	$60.00	$85.00	$104.20

As of September 30, 2012 , 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
Calendar Year	Volumes (MMBtu)	Price per MMBtu	Price Range per MMBtu
October-December 2012	1,644,610	$5.11	$2.46	-	$8.70
2013	5,790,654	$4.76	$3.23	-	$6.89
2014	4,251,254	$4.65	$3.61	-	$6.47
2015	1,339,300	$5.65	$5.14	-	$5.82
2016	219,200	$5.30	$5.30

As of September 30, 2012 , Legacy had the following West Texas Waha natural gas derivative collar contract that combines a long put option or "floor" with a short call option or "ceiling" as indicated below:

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.

On August 29, 2007, Legacy entered into LIBOR interest rate swaps beginning in October 2007 and extending through November 2011. On January 29, 2009, Legacy revised and extended these LIBOR interest rate swaps. The revised swap transaction had Legacy paying its counterparty fixed rates ranging from 4.09% to 4.11% , per annum, and receiving floating rates on a total notional amount of $54 million . In August 2011, Legacy again revised and extended these LIBOR interest rate swaps. The current swap transaction has Legacy paying its counterparty fixed rates ranging from 3.07% to 3.13% , per annum, and receiving floating rates on the same total notional amount of $54 million . These swaps are settled on a monthly basis, beginning in August 2011 and ending in November 2015.

On March 14, 2008, Legacy entered into a LIBOR interest rate swap beginning in April 2008 and extending through April 2011. On January 28, 2009, Legacy revised this LIBOR interest rate swap extending the term through April 2013. The revised swap transaction has Legacy paying its counterparty a fixed rate of 2.65% per annum, and receiving floating rates on a notional amount of $60 million . This swap is settled on a monthly basis, beginning in April 2009 and ending in April 2013.

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On October 6, 2008, Legacy entered into two LIBOR interest rate swaps beginning in October 2008 and extending through October 2011. In January 2009, Legacy revised these LIBOR interest rate swaps extending the termination date through October 2013. The revised swap transactions have Legacy paying its counterparties fixed rates ranging from 3.09% to 3.10% , per annum, and receiving floating rates on a total notional amount of $100 million . In August 2011, Legacy further revised one of the aforementioned LIBOR interest rate swaps, extending the termination date through October 2015. The revised swap transaction has Legacy paying its counterparty a fixed rate of 2.50% , per annum, revised from the previous rate of 3.09% , per annum. The revised swaps are settled on a monthly basis, beginning in August 2011 and January 2009, respectively and ending in October 2015 and October 2013, respectively.

On December 16, 2008, Legacy entered into a LIBOR interest rate swap beginning in December 2008 and extending through December 2013. The swap transaction has Legacy paying its counterparty a fixed rate of 2.295% , per annum, and receiving floating rates on a total notional amount of $50 million . The swap is settled on a quarterly basis, beginning in March 2009 and ending in December 2013.

On August 8, 2011, Legacy entered into two LIBOR interest rate swaps, beginning in August 2011 and extending through August 2014. The swap transactions have Legacy paying its counterparties fixed rates ranging from 0.702% to 0.71% , per annum, and receiving floating rates on a total notional amount of $100 million . The swaps are settled on a monthly basis, beginning in August 2011 and ending in August 2014.

Legacy accounts for these interest rate swaps pursuant to ASC 815 which establishes accounting and reporting standards requiring that derivative instruments be recorded at fair market value and included in the balance sheet as assets or liabilities.

Legacy does not specifically designate these derivative transactions 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					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012			2011
	(In thousands)
Interest rate swap settlements	$	1,768		$	1,860	$	5,244		$	5,583
Unrealized change in fair value - interest rate swaps	(301		)	510		(1,057		)	197
Total increase to interest expense, net	$	1,467		$	2,370	$	4,187		$	5,780

The table below summarizes the interest rate swap position as of September 30, 2012 :



						Estimated Fair Market Value at
Notional Amount		Fixed Rate		Effective Date	Maturity Date	September 30, 2012
(Dollars in thousands)
$	29,000	3.070	%	10/16/2007	10/16/2015	$	(2,360	)
$	13,000	3.112	%	11/16/2007	11/16/2015	(1,089		)
$	12,000	3.131	%	11/28/2007	11/28/2015	(1,021		)
$	60,000	2.650	%	4/1/2008	4/1/2013	(726		)
$	50,000	3.100	%	10/10/2008	10/10/2013	(1,192		)
$	50,000	0.710	%	8/10/2011	8/10/2014	(252		)
$	50,000	2.295	%	12/18/2008	12/18/2013	(912		)
$	50,000	0.702	%	8/10/2011	8/10/2014	(244		)
$	50,000	2.500	%	10/10/2008	10/10/2015	(3,199		)
Total fair market value of interest rate derivatives						$	(10,995	)


(7)	Asset Retirement Obligation

ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of

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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 nine months ended September 30, 2012 and year ended December 31, 2011 :



	September 30, 2012			December 31, 2011
	(In thousands)
Asset retirement obligation - beginning of period	$	120,274		$	111,262

Liabilities incurred with properties acquired	6,036			8,300
Liabilities incurred with properties drilled	—			1,101
Liabilities settled during the period	(1,850		)	(3,775		)
Liabilities associated with properties sold	(207		)	—
Current period accretion	3,395			4,234
Current period revisions to previous estimates	—			(848		)
Asset retirement obligation - end of period	$	127,648		$	120,274


(8)	Earnings Per Unit

The following table sets forth the computation of basic and diluted net earnings per unit:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012		2011
	(In thousands)
Income (loss) available to unitholders	$	(23,566	)	$	125,100	$	66,765	$	130,584
Weighted average number of units outstanding	47,869			43,587		47,840		43,560
Effect of dilutive securities:
Restricted units	—			20		—		12
Weighted average units and potential units outstanding	47,869			43,607		47,840		43,572
Basic and diluted earnings (loss) per unit	$	(0.49	)	$	2.87	$	1.40	$	3.00

The unvested restricted units outstanding as of September 30, 2012 were anti-dilutive and therefore had no impact on diluted earnings per unit. For the three and nine months ended September 30, 2011 , 77,513 and 84,538 restricted units, respectively, 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, a Long-Term Incentive Plan (“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 September 30, 2012 , grants of awards net of forfeitures and, in the case of UARs and phantom units, historical exercises covering 1,310,938 units had been made, comprised of 266,014 unit option awards, 439,150 unit appreciation rights awards ("UARs"), 363,879 restricted unit awards, 148,232 phantom unit awards and 93,663 unit awards. The LTIP is administered by the compensation committee (the “Compensation Committee”) of the board of directors of Legacy’s general partner.

ASC 718 requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, ASC 718 stipulates that “if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if the entity usually settles in cash whenever an employee asks for cash

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settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument.” Due to Legacy's historical practice of settling unit options, UARs and phantom unit awards in cash, Legacy accounts for unit options, UARs, and phantom unit awards by utilizing the liability method as described in ASC 718. 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.

Unit Appreciation Rights and Unit Options

A unit appreciation right 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, 2011 , Legacy issued 68,000 UARs to employees which vest ratably over a three-year period and 50,034 UARs to employees which vest at the end of a three-year period. During the nine -month period ended September 30, 2012 , Legacy issued 50,500 UARs to employees which vest ratably over a three-year period. All UARs granted in 2011 and 2012 expire seven years from the grant date and are exercisable when they vest.

For the nine -month periods ended September 30, 2012 and 2011 , Legacy recorded $0.5 million and $0.02 million , respectively, of compensation expense due to the change in liability from December 31, 2011 and 2010 , respectively, based on its use of the Black-Scholes model to estimate the September 30, 2012 and 2011 fair value of these UARs and unit options (see Note 5). As of September 30, 2012 , there was a total of approximately $1.0 million of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At September 30, 2012 , this cost was expected to be recognized over a weighted-average period of approximately 1.6 years. Compensation expense is based upon the fair value as of September 30, 2012 and is recognized as a percentage of the service period satisfied. Since Legacy's trading history does not yet match the term of the outstanding UAR and unit option awards, it has used an estimated volatility factor of approximately 50% based upon the historical trends of a representative group of publicly-traded companies in the energy industry and employed the Black-Scholes model to estimate the September 30, 2012 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 3.8% . As required by ASC 718, Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $2.24 per unit.

A summary of UAR and unit option activity for the nine months ended September 30, 2012 is as follows:



	Units		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2012	620,031		$	22.36
Granted	50,500		27.99
Exercised	(173,315	)	19.84
Forfeited	(58,066	)	24.68
Outstanding at September 30, 2012	439,150		$	23.77	4.6	$	2,291,151

UARs and unit options exercisable at September 30, 2012	172,736		$	20.33	3.1	$	1,487,654

The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2012:

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	Non-Vested UARs
	Number of Units		Weighted-Average Exercise Price
Non-vested at January 1, 2012	387,766		$	22.80
Granted	50,500		27.99
Vested - Unexercised	(91,319	)	19.81
Vested - Exercised	(49,467	)	16.43
Forfeited	(31,066	)	22.69
Non-vested at September 30, 2012	266,414		$	25.99

Legacy has used a weighted-average risk-free interest rate of 0.9% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at September 30, 2012 whose terms are consistent with the expected life of the 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.



	Nine Months Ended
	September 30, 2012
Expected life (years)	4.60
Risk free interest rate	0.9	%
Annual distribution rate per unit	$2.24
Volatility	50	%

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 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 awards in cash, Legacy is accounting for the phantom units by utilizing the liability method.

On September 21, 2009, the board of directors of Legacy’s general partner, upon the recommendation of the Compensation Committee, implemented the current 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 ranging from 30% to 110% 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 ranging from 45% to 165% , 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. The percentage of the 50% performance-based award to vest under this step is determined within a matrix which ranges from 0% to 100% and will increase from 0% to 100% as each of the Legacy TUR and the percentage rank of the Legacy TUR among the peer group increase. The applicable Legacy TUR range is from less than 8% (where 0% to 25% of the amount will vest, depending upon the Legacy TUR ranking among its peer group) to more than 20% (where 50% to 100% of the amount will vest, depending upon the Legacy TUR ranking among its peer group). 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 percentage of the 50% of the performance-based award to vest under this step is determined within a matrix which ranges from 0% to 100% and will increase from 0% to 100% as the Legacy TUR and the percentile rank of the Legacy TUR among the Adjusted Alerian MLP Index increases. The applicable Legacy TUR range is from less than 8% (where 0% to 30% of the amount will vest, depending upon the Legacy TUR percentile ranking among the Adjusted Alerian MLP Index) to more than 20% (where 50% to 100% of the amount will vest, depending upon the Legacy TUR percentile ranking among the

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Adjusted Alerian MLP Index). The third step is the addition of the above two steps to determine the total performance-based awards to vest. 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 this compensation policy, 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.

On February 18, 2011 , the Compensation Committee approved the award of 32,806 subjective, or service-based, phantom units and 53,487 objective, or performance based, phantom units to Legacy’s executive officers. On February 1, 2012 and February 2, 2012 , the Compensation Committee approved the award of 30,828 subjective, or service-based, phantom units and 57,189 objective, or performance based, phantom units to Legacy’s executive officers. Upon his resignation effective March 16, 2012, Legacy's former President and Chief Financial Officer forfeited all of his unvested phantom unit awards.

Compensation expense related to the phantom units and associated DERs was $1.5 million and $1.3 million for the nine months ended September 30, 2012 and 2011 , respectively.

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Restricted Units

During the year ended December 31, 2011 , Legacy issued an aggregate of 51,365 restricted units to non-executive employees. The restricted units awarded vest ratably over a three-year period, beginning on the date of grant. During the nine -month period ended September 30, 2012 , Legacy issued an aggregate of 170,645 restricted units to both non-executive employees and certain executive employees not previously covered under the aforementioned executive compensation plan. The restricted units awarded vest either ratably over a three-year period, ratably over a two-year period or cliff vest at the end of a five year period, all beginning on the date of grant. Compensation expense related to restricted units was $1.2 million and $0.6 million for the nine months ended September 30, 2012 and 2011 , respectively. As of September 30, 2012 , there was a total of $5.5 million of unrecognized compensation expense related to the unvested portion of these restricted units. At September 30, 2012 , this cost was expected to be recognized over a weighted-average period of 3.3 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at September 30, 2012 , do not include 227,477 units related to unvested restricted unit awards.

Board and Additional Executive Units

On May 11, 2011, Legacy granted and issued 1,630 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy's general partner. The value of each unit was $30.24 at the time of issuance. On August 26, 2011, Legacy granted and issued 1,885 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy's general partner. The value of each unit was $26.94 at the time of issuance. On May 9, 2012, Legacy granted and issued 3,509 units to each of its five non-employee directors and 2,500 units to an executive employee. The value of each unit was $28.34 at the time of issuance.

(10) Subsidiary Guarantors

Legacy and Legacy Reserves Finance Corporation, a wholly owned finance subsidiary, filed an automatic registration statement on Form S-3 on May 23, 2011. Securities that may be offered and sold include debt securities which may be guaranteed by Legacy's subsidiaries and are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. Legacy, as the parent company, has no independent assets or operations. Legacy contemplates that if it offers guaranteed debt securities pursuant to the registration statement, all guarantees will be full and unconditional and joint and several, and any subsidiaries of Legacy other than the subsidiary guarantors will be minor. In addition, there are no restrictions on the ability of Legacy to obtain funds from its subsidiaries by dividend or loan.

(11) Equity Distribution Agreement

Legacy currently has an Equity Distribution Agreement with Knight Capital Americas, L.P. ("KCA") under which Legacy may offer and sell units from time to time through KCA, as Legacy's sales agent. During the year ended December 31, 2011 , Legacy received proceeds from 87,364 units issued pursuant to this agreement of approximately $2.4 million gross and $2.3 million net of commissions, which proceeds were used for general partnership purposes. No sales were made during the nine months ended September 30, 2012 .

(12) Subsequent Events

On October 22, 2012, Legacy’s board of directors approved a distribution of $0.565 per unit payable on November 14, 2012 to unitholders of record on November 1, 2012, representing an increase of $0.005 per unit over the last quarterly distribution.

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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, 2011 in Item 1A under “Risk Factors” and Legacy's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 in Part II, 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, 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, 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, re-completing 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 exploitation 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, if any, on any redetermination of 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 unrealized gain or loss associated with these instruments is recorded in current earnings.

Production and Operating Costs Reporting

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

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 and are reported with production costs. 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					Nine Months Ended
	September 30,					September 30,
	2012		2011			2012			2011
	(In thousands, except per unit data)
Revenues:
Oil sales	$	70,173	$	63,387		$	212,097		$	196,220
Natural gas liquid sales	3,492		4,924			10,742			13,896
Natural gas sales	10,531		16,061			33,166			39,858
Total revenue	$	84,196	$	84,372		$	256,005		$	249,974

Expenses:
Oil and natural gas production	$	28,207	$	22,093		$	75,067		$	64,572
Ad valorem taxes	2,521		2,016			$	6,956		$	6,732
Total oil and natural gas production	$	30,728	$	24,109		$	82,023		$	71,304
Production and other taxes	$	5,137	$	5,211		$	15,040		$	15,101
General and administrative	$	6,993	$	3,817		$	18,604		$	14,630
Depletion, depreciation, amortization and accretion	$	24,833	$	22,446		$	73,042		$	64,152

Realized commodity derivative settlements:
Realized gains (losses) on oil derivatives	$	2,108	$	(1,857	)	$	(10,949	)	$	(11,849	)
Realized gains on natural gas derivatives	$	4,000	$	2,703		$	12,967		$	8,084

Production:
Oil (MBbls)	840		755			2,418			2,190
Natural gas liquids (MGal)	3,821		3,735			10,938			10,509
Natural gas (MMcf)	2,571		2,548			7,774			6,397
Total (MBoe)	1,359		1,269			3,974			3,506
Average daily production (Boe/d)	14,772		13,793			14,504			12,842

Average sales price per unit (excluding derivatives):
Oil price (per Bbl)	$	83.54	$	83.96		$	87.72		$	89.60
Natural gas liquid price (per Gal)	$	0.91	$	1.32		$	0.98		$	1.32
Natural gas price (per Mcf)	$	4.10	$	6.30		$	4.27		$	6.23
Combined (per Boe)	$	61.95	$	66.49		$	64.42		$	71.30

Average sales price per unit (including realized derivative gains/losses):
Oil price (per Bbl)	$	86.05	$	81.50		$	83.19		$	84.19
Natural gas liquid price (per Gal)	$	0.91	$	1.32		$	0.98		$	1.32
Natural gas price (per Mcf)	$	5.65	$	7.36		$	5.93		$	7.49
Combined (per Boe)	$	66.45	$	67.15		$	64.93		$	70.23

NYMEX oil index prices per Bbl:
Beginning of period	$	84.96	$	95.42		$	98.83		$	91.38
End of period	$	92.19	$	79.20		$	92.19		$	79.20

NYMEX gas index prices per Mcf:
Beginning of period	$	2.82	$	4.37		$	2.99		$	4.41
End of period	$	3.32	$	3.67		$	3.32		$	3.67

Average unit costs per Boe:
Oil and natural gas production	$	20.76	$	17.41		$	18.89		$	18.42
Ad valorem taxes	$	1.86	$	1.59		$	1.75		$	1.92
Production and other taxes	$	3.78	$	4.11		$	3.78		$	4.31
General and administrative	$	5.15	$	3.01		$	4.68		$	4.17
Depletion, depreciation, amortization and accretion	$	18.27	$	17.69		$	18.38		$	18.30

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Results of Operations

Three-Month Period Ended September 30, 2012 Compared to Three-Month Period Ended September 30, 2011

Legacy’s revenues from the sale of oil were $70.2 million and $63.4 million for the three-month periods ended September 30, 2012 and 2011 , respectively. Legacy’s revenues from the sale of NGLs were $3.5 million and $4.9 million for the three-month periods ended September 30, 2012 and 2011 , respectively. Legacy’s revenues from the sale of natural gas were $10.5 million and $16.1 million for the three-month periods ended September 30, 2012 and 2011 , respectively. The $6.8 million increase in oil revenues reflects the increase in oil production of 85 MBbls ( 11% ) partially offset by a slight decrease in average realized price of $0.42 per Bbl ( 1% ). This increase in production is due to Legacy’s purchase of additional oil and natural gas properties during 2012. The $1.4 million decrease in NGL sales reflects a decrease in the average realized price of $0.41 per gallon ( 31% ) partially offset by an increase in NGL production of approximately 86 MGals ( 2% ). The $5.5 million decrease in natural gas revenues largely reflects a decrease in average realized natural gas prices, as Legacy's average realized natural gas price decreased by $2.20 per Mcf ( 35% ), which reflects declining NYMEX natural gas prices and declining NGL prices. Our natural gas production increased approximately 23 MMcf ( 1% ) due to Legacy’s purchase of additional oil and natural gas properties which was largely offset by high pressure in natural gas gathering lines that inhibited our natural gas production in the Permian Basin during the three months ended September 30, 2012 . 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 substantially higher than NYMEX Henry Hub natural gas prices due to this NGL content.

For the three-month period ended September 30, 2012 , Legacy recorded $27.2 million of net losses on oil and natural gas derivatives comprised of realized gains of $6.1 million from net cash settlements of oil and natural gas derivative contracts and net unrealized losses of $33.3 million . Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives that will be settled in future periods. Legacy had unrealized net losses of $26.2 million from oil derivatives primarily because oil futures prices increased during the three-month period ended September 30, 2012 . Due to the rise in oil futures prices, the associated net asset related to our oil derivatives at September 30, 2012 decreased relative to the net asset balance as of June 30, 2012, resulting in the recording of the corresponding unrealized loss. Legacy had unrealized net losses from natural gas derivatives of $7.1 million because the NYMEX natural gas futures prices increased during the three-month period ended September 30, 2012 . Due to this increase in natural gas prices during the quarter, the positive difference between the average contract prices of Legacy’s natural gas derivatives and NYMEX prices decreased. Accordingly, the net asset attributable to Legacy’s outstanding natural gas derivatives decreased, resulting in the recording of the corresponding unrealized loss. For the three-month period ended September 30, 2011 , Legacy recorded $107.6 million of net gains on oil and natural gas derivatives, comprised of realized gains of $0.8 million from net cash settlements of oil and natural gas derivative contracts and net unrealized gains of $106.8 million .

Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, increased to $28.2 million ( $20.76 per Boe) for the three-month period ended September 30, 2012 from $22.1 million ( $17.41 per Boe) for the three-month period ended September 30, 2011 . Production expenses increased primarily due to $2.1 million of increased non-recurring workover expenses, unusually high maintenance costs, the acquisition of oil and natural gas properties and, to a lesser extent, expenses associated with Legacy's development activities. Legacy’s ad valorem tax expense increased to $2.5 million ( $1.86 per Boe) for the three-month period ended September 30, 2012 compared to $2.0 million ( $1.59 per Boe) for the three-month period ended September 30, 2011 , due to increased well counts from recent acquisitions.

Legacy’s production and other taxes were $5.1 million and $5.2 million for the three-month periods ended September 30, 2012 and 2011 , respectively. Production and other taxes remained relatively flat, as production and other taxes as a percentage of revenue remained largely unchanged.

Legacy’s general and administrative expenses were $7.0 million and $3.8 million for the three-month periods ended September 30, 2012 and 2011 , respectively. General and administrative expenses increased $3.2 million primarily due to a $2.1 million increase in unit-based compensation due to increased unit prices as well as increases in salaries and benefit costs related to the hiring of additional personnel.

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $24.8 million and $22.4 million for the three-month periods ended September 30, 2012 and 2011 , respectively. DD&A increased primarily due to increased production from our development activities and recent acquisitions, as well as proportionate increases in cost basis. These increases were partially offset by increased reserve volumes related to our acquisitions and development activities.

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Impairment expense was $7.3 million and $4.7 million for the three-month periods ended September 30, 2012 and 2011 , respectively. In the three-month period ended September 30, 2012 , Legacy recognized $0.8 million of impairment expense on two separate producing fields primarily related to lower annual average oil prices at September 30, 2012 compared to June 30, 2012 , which reduced the future expected cash flows. The remaining $6.5 million represents the impairment on a single field in which Legacy has entered into an option agreement with a third party that grants the third party the option to purchase the oil and natural gas properties Legacy owns in this field. The option can be exercised at any time prior to January 4, 2013. Due to its status as an "available-for-sale" property, Legacy has impaired the property to reduce its carrying value to its estimated fair value. Impairment expense for the period ended September 30, 2011 , was related to declining oil prices during the period compounded by increased operating expenses in select fields.

Legacy recorded interest expense of $5.3 million and $5.8 million for the three-month periods ended September 30, 2012 and 2011 , respectively. Interest expense decreased approximately $0.5 million primarily due to a reduction in the mark-to-market adjustment of our interest rate swap derivatives consisting of a $0.3 million reduction in interest expense for the three-month period ended September 30, 2012 , compared to a $0.5 million increase in interest expense for the three-month period ended September 30, 2011 . This reduction was partially offset by increased cash interest expense due to higher average outstanding debt balance during the three-month period ended September 30, 2012 .

Nine -Month Period Ended September 30, 2012 Compared to Nine -Month Period Ended September 30, 2011

Legacy’s revenues from the sale of oil were $212.1 million and $196.2 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. Legacy’s revenues from the sale of NGLs were $10.7 million and $13.9 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. Legacy’s revenues from the sale of natural gas were $33.2 million and $39.9 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. The $15.9 million increase in oil revenues reflects the increase in oil production of 228 MBbls ( 10% ) which was partially offset by a decrease in average realized price of $1.88 per Bbl ( 2% ) that is largely attributable to increased oil differentials during the nine -month period ended September 30, 2012 . This increase in production is due primarily to Legacy’s purchase of additional oil and natural gas properties. The $3.2 million decrease in NGL sales reflects a decrease in the average realized price of $0.34 per gallon ( 26% ) partially offset by an increase in NGL production of approximately 429 MGals ( 4% ) due primarily to non-operated development activity in the Permian Basin and Texas Panhandle. The $6.7 million decrease in natural gas revenues reflects a decrease in average realized prices partially offset by an increase in natural gas production. Our natural gas production increased approximately 1,377 MMcf ( 22% ) due to a full nine-month impact of acquisitions of properties with natural gas-weighted production during 2011 as well as Legacy's ongoing development activities that are primarily focused in the Permian Basin, specifically the Wolfberry play, in which we produce primarily oil but also a significant amount of NGL-rich, casinghead natural gas. Legacy's average realized natural gas price decreased by $1.96 per Mcf ( 31% ), which reflects declining NYMEX natural gas prices and declining NGL prices. We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained with 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 substantially higher than NYMEX Henry Hub natural gas prices due to this NGL content.

For the nine -month period ended September 30, 2012 , Legacy recorded $34.1 million of net gains on oil and natural gas derivatives comprised of realized gains of $2.0 million from net cash settlements of oil and natural gas derivative contracts and net unrealized gains of $32.1 million . Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives that will be settled in future periods. Legacy had unrealized net gains of $43.9 million from oil derivatives because oil futures prices decreased during the nine -month period ended September 30, 2012 . Unlike at December 31, 2011 , the average contract prices of Legacy's outstanding oil derivatives exceeded oil futures prices at September 30, 2012 , which changed the associated net liability at December 31, 2011 to a net asset at September 30, 2012 , resulting in the recording of the corresponding unrealized gain. Legacy had unrealized net losses from natural gas derivatives of $11.8 million due to the increase in NYMEX natural gas futures prices during the nine -month period ended September 30, 2012 as well as the addition of natural gas derivatives contracts at lower prices, which reduced Legacy's average derivative contract prices. The combination of higher natural gas prices and lower priced derivatives reduced the positive difference between Legacy’s natural gas derivatives and NYMEX futures prices, which reduced the net asset attributable to unrealized net gains from Legacy’s outstanding natural gas derivatives and resulted in the recording of the corresponding unrealized loss. For the nine -month period ended September 30, 2011 , Legacy recorded $67.8 million of net gains on oil and natural gas derivatives, comprised of realized losses of $3.8 million from net cash settlements of oil and natural gas derivative contracts and net unrealized gains of $71.5 million .

Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, increased to $75.1 million ( $18.89 per Boe) for the nine -month period ended September 30, 2012 from $64.6 million ( $18.42 per Boe) for the nine -month period ended September 30, 2011 . Production expenses increased primarily due $2.3 million of increased non-recurring workover

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activity as well as the purchases of oil and natural gas properties and, to a lesser extent, expenses associated with Legacy's development activity. Legacy’s ad valorem tax expense increased to $7.0 million ( $1.75 per Boe) for the nine -month period ended September 30, 2012 , from $6.7 million ( $1.92 per Boe) for the nine -month period ended September 30, 2011 .

Legacy’s production and other taxes were $15.0 million and $15.1 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. Production and other taxes remained substantially unchanged as production and other taxes as a percentage of revenue remained largely unchanged.

Legacy’s general and administrative expenses were $18.6 million and $14.6 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. General and administrative expenses increased $4.0 million due to a $1.2 million increase in unit based compensation expenses due to increased unit prices as well as increases in salaries and benefit costs related to the hiring of additional personnel.

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $73.0 million and $64.2 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. DD&A increased primarily because of increased production from our development activities and recent acquisitions, as well as proportionate increases in cost basis. These increases were partially offset by increased reserve volumes related to our acquisitions and development activities.

Impairment expense was $22.6 million and $5.9 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. In the nine -month period ended September 30, 2012 , Legacy recognized $14.8 million of impairment expense on 26 separate producing fields primarily related to lower oil and natural gas prices at during 2012, which reduced the future expected cash flows. In addition, Legacy recognized $6.5 million of impairment related to the reduction in the carrying value of the property which Legacy has entered into an option agreement to sell as previously discussed. The remaining $7.8 million impairment of goodwill was recognized on an acquisition of oil and natural gas properties during the nine -month period ended September 30, 2012 as a result of a purchase and sale agreement Legacy entered into with a third party to acquire certain oil and natural gas properties, the purchase price of which was negotiated as of the date of the agreement. During the period between the agreement date and the date of closing the acquisition, oil futures prices declined significantly, thereby reducing the fair value of the properties acquired at the date of close. Since the oil derivatives we entered into on the agreement date related to expected production from these properties constitute separate transactions, our derivatives do not affect the associated fair value of the oil and natural gas properties acquired. Because the purchase price exceeded the fair value of the properties acquired, goodwill was recognized and subsequently tested for impairment. As of September 30, 2012 , all of the goodwill associated with this acquisition had been impaired. Impairment expense for the period ended September 30, 2011 , was primarily related to lower oil prices during the period and higher operating costs.

Legacy recorded interest expense of $14.3 million and $15.6 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. Interest expense decreased approximately $1.4 million due primarily to a reduction in the mark-to-market adjustments of our interest rate swap derivatives consisting of a $1.1 million reduction in interest expense for the nine -month period ended September 30, 2012 , compared to a $0.2 million increase in interest expense for the nine -month period ended September 30, 2011 .

Non-GAAP Financial Measures

For the three months ended September 30, 2012 and 2011 , respectively, Adjusted EBITDA (as defined below) decreased 5% to $49.3 million from $52.1 million primarily due to lower commodity prices as well as higher total production and general and administrative expenses. These factors were partially offset by higher production as well as increased realized commodity derivative settlement receipts of approximately $5.3 million . For the three months ended September 30, 2012 and 2011 , respectively, Distributable Cash Flow decreased 3% to $23.4 million from $24.1 million , as lower Adjusted EBITDA and higher cash settlements on LTIP unit awards were partially offset by lower development capital expenditures.

For the nine months ended September 30, 2012 and 2011 , respectively, Adjusted EBITDA decreased 2% to $145.2 million from $148.3 million due to lower commodity prices as well as higher total production and general and administrative expenses. These factors were partially offset by higher production as well as increased realized commodity derivative settlements of approximately $5.8 million . Distributable Cash Flow remained substantially unchanged at $78.9 million from $79.1 million , as lower Adjusted EBITDA, slightly higher cash interest expense and cash settlements on LTIP unit awards were almost completely offset by lower development capital expenditures.

Legacy's management uses Adjusted EBITDA and Distributable Cash Flow as tools to provide additional information and metrics relative to the performance of Legacy’s business, such as the cash distributions Legacy expects to pay to its

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unitholders. Legacy’s management believes that both Adjusted EBITDA and Distributable Cash Flow are useful to investors because these measures are used by many companies in the industry as measures of operating and financial performance and are 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 and Distributable Cash Flow 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” and “Distributable Cash Flow,” both of which are non-GAAP measures, to their nearest comparable GAAP measure. “Adjusted EBITDA” and “Distributable Cash Flow” should not be considered as alternatives 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 in Legacy’s revolving credit facility 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 (excluding settlements of asset retirement obligations);


•	Equity in (income) loss of partnership;


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


•	Unrealized (gain) loss on oil and natural gas derivatives.

Distributable Cash Flow is defined as Adjusted EBITDA less:


•	Cash interest expense;


•	Cash income taxes;


•	Cash settlements of LTIP unit awards; and


•	Development capital expenditures.

The following table presents a reconciliation of Legacy’s consolidated net income to Adjusted EBITDA and Distributable Cash Flow for the three and nine months ended September 30, 2012 and 2011 , respectively.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(Dollars in thousands)
Net income (loss)	$	(23,566	)	$	125,100		$	66,765		$	130,584
Plus:
Interest expense	5,285			5,764			14,256			15,633
Income tax expense	54			928			878			1,198
Depletion, depreciation, amortization and accretion	24,833			22,446			73,042			64,152
Impairment of long-lived assets	7,277			4,678			22,556			5,869
Gain on disposal of assets	(9		)	—			(3,846		)	—
Equity in income of partnership	(30		)	(35		)	(87		)	(107		)
Unit-based compensation expense	2,138			6			3,670			2,446
Unrealized (gains) losses on oil and natural gas derivatives	33,285			(106,757		)	(32,066		)	(71,518		)
Adjusted EBITDA	$	49,267		$	52,130		$	145,168		$	148,257

Less:
Cash interest expense	5,283			4,989			14,396			14,182
Cash settlements of LTIP unit awards	990			185			3,371			2,855
Development capital expenditures	19,565			22,832			48,457			52,127
Distributable Cash Flow	$	23,429		$	24,124		$	78,944		$	79,093

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Capital Resources and Liquidity

Legacy’s primary sources of capital and liquidity have been bank borrowings, cash flow from operations, the issuance of additional units or a combination thereof. To date, Legacy’s primary uses of capital have been for acquisitions, repayment of bank borrowings and development of oil and natural gas properties.

We continually monitor the capital resources available to us to meet our future financial obligations and planned capital expenditures. Our future success in maintaining and growing reserves and production will be highly dependent on capital resources available to us and our success in acquiring and developing additional reserves. If we were to make significant additional acquisitions for cash, we would need to borrow additional amounts under our credit facility, if available, or obtain additional debt or equity financing. Further, our revolving credit facility imposes specific restrictions on our ability to obtain additional debt financing. Please see “ – Financing Activities – Our Revolving Credit Facility.” Based upon current oil and natural gas price expectations and our extensive commodity derivatives positions for the year ending December 31, 2012 , we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our credit facility will provide us sufficient working capital to meet our currently planned capital expenditures and future cash distributions 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.

The amounts available for borrowing under our credit facility are subject to a borrowing base, which is currently set at $600 million . As of October 30, 2012 , we had $137.9 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 April 2013. Please see “— Financing Activities — Our Revolving Credit Facility.”

Cash Flow from Operations

Legacy’s net cash provided by operating activities was $129.4 million and $144.2 million for the nine -month periods ended September 30, 2012 and 2011 , respectively. The 2012 period was unfavorably impacted by lower realized commodity prices and higher expenses, partially offset by higher production volumes. In addition, the net cash amounts for 2012 and 2011 do not include cash settlements received/(paid) of $2.0 million and $(3.8) million , respectively, from our commodity derivative transactions.

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

Investing Activities

Legacy’s cash capital expenditures were $164.3 million for the nine -month period ended September 30, 2012 . The total includes $115.0 million for the acquisition of oil and natural gas properties in 15 individually immaterial acquisitions, $48.5 million for development projects and $0.8 million of exploratory capital expenditures. Legacy’s cash capital expenditures were $147.5 million for the nine -month period ended September 30, 2011 . The total includes $95.4 million for the acquisition of oil and natural gas properties in 23 individually immaterial acquisitions and $52.1 million for development projects.

Our capital expenditure budget, which predominantly consists of drilling, re-completion and capital workover projects, is currently $66.0 million for the year ending December 31, 2012 , of which $48.5 million has been expended during the nine -months ended September 30, 2012 . Our remaining borrowing capacity under our revolving credit facility is $137.9 million as of October 30, 2012 . 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 or accelerate projects planned for future periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner. Based upon current oil and natural gas price expectations for the year ending December 31, 2012 , 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 $17.5 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

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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 that we typically experience in the Permian Basin. For the nine -month periods ended September 30, 2012 and 2011 we had favorable cash settlements of $2.0 million and unfavorable cash settlements of $3.8 million , respectively, related to our commodity derivatives. At September 30, 2012 , we had in place oil and natural gas derivatives covering significant portions of our estimated 2012 through 2017 oil, NGL and natural gas production. As of October 30, 2012 , we have derivative contracts covering approximately 73% of our remaining expected oil, NGL and natural gas production for 2012 , 62% for 2013 and 26% of our currently expected oil and natural gas production for 2014 through December 2017.

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 financial institutions deemed by management as competent and competitive market makers. In addition, these 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 October 30, 2012 , covering the period from October 1, 2012 through June 30, 2017. We use derivatives, including swaps, collars and 3-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 settled based upon the monthly average closing price of the front-month NYMEX West Texas Intermediate ("WTI") oil contract price at Cushing, Oklahoma, and West Texas Waha, Rocky Mountain CIG and ANR-Oklahoma prices of natural gas on the average of the three final trading days of the month and settlement occurs on the fifth day of the production month.



Calendar Year	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
October-December 2012(a)	583,570	$89.64	$67.72	-	$109.20
2013(a)	1,571,443	$90.34	$80.10	-	$108.65
2014	901,014	$92.89	$87.50	-	$103.75
2015	362,851	$93.73	$90.50	-	$100.20
2016	45,600	$94.53	$91.00	-	$99.85

(a)

On October 6, 2010, as part of an oil swap transaction entered into with a counterparty, we sold two call options to the counterparty that allow the counterparty to extend a swap transaction covering calendar year 2011 to either 2012, 2013 or both calendar years. The counterparty exercised the option covering calendar year 2012 on December 30, 2011 and must exercise or decline the option covering calendar year 2013 on December 31, 2012. As the option was exercised for calendar year 2012, we will pay the counterparty floating prices and receive a fixed price of $98.25 per Bbl on annual notional volumes of 183,000 Bbls (46,000 Bbls remaining as of October 1, 2012 ). For calendar year 2013, if exercised, we would pay the counterparty floating prices and receive a fixed price of $98.25 per Bbl on annual notional volumes of 182,500 Bbls in 2013. The premium paid by the counterparty to us for the two call options was in the form of an increase in the fixed price that we received pursuant to the 2011 swap of $98.25 per Bbl on 182,500 Bbls, or 500 Bbls per day, rather than the prevailing market price of approximately $87.00 per Bbl. These additional potential volumes related to the unexercised 2013 option are not reflected in the above table.

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Calendar Year	Volumes (MMBtu)	Average Price per MMBtu	Price Range per MMBtu
October-December 2012	1,644,610	$5.11	$2.46	-	$8.70
2013	5,790,654	$4.76	$3.23	-	$6.89
2014	4,251,254	$4.65	$3.61	-	$6.47
2015	1,339,300	$5.65	$5.14	-	$5.82
2016	219,200	$5.30	$5.30

On June 24, 2008, we entered into a NYMEX WTI crude oil derivative collar contract that combines a long put option or “floor” with a short call option or “ceiling.” The following table summarizes the oil collar contract currently in place as of October 30, 2012 , covering the period from October 1, 2012 through December 31, 2012:

On January 12, 2011, we entered into a West Texas Waha natural gas derivative collar contract that combines a long put option or "floor" with a short call option or "ceiling." The following table summarizes the natural gas collar contract currently in place as of October 30, 2012 , covering the period from October 1, 2012 through December 31, 2012:

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. In regards to our three-way collar contracts, if the market price has fallen below the short put fixed price, we would receive the market price plus $25 or $30 per barrel, depending on the contract. The following table summarizes the three-way oil collar contracts currently in place as of October 30, 2012 , covering the period from October 1, 2012 through June 30, 2017:



		Average	Average	Average
Calendar Year	Volumes (Bbls)	Short Put Price	Long Put Price	Short Call Price
October-December 2012	110,400	$68.13	$95.00	$113.54
2013	795,670	$66.24	$91.92	$112.25
2014	1,226,130	$65.64	$90.86	$113.29
2015	1,126,000	$65.43	$90.43	$114.76
2016	438,300	$64.78	$89.78	$110.54
2017	72,400	$60.00	$85.00	$104.20

Financing Activities

Legacy’s net cash provided by financing activities was $34.7 million for the nine months ended September 30, 2012 , compared to net cash provided of $8.7 million for the nine months ended September 30, 2011 . During the nine months ended September 30, 2012 , total net borrowings under our revolving credit facility were $115.0 million , comprised of borrowings of $335.0 million and repayments of $220.0 million . The borrowings under the credit facility were used to finance our acquisition and development activities. Additionally, Legacy had cash outflow during the nine months ended September 30, 2012 in the amount of $79.8 million for distributions to unitholders which was funded from cash flow from operations. Cash provided by financing activities during the nine months ended September 30, 2011 , included $81.0 million in net borrowings under our revolving credit facility and $69.6 million for distributions to unitholders.

Our Revolving Credit Facility

Previous Credit Agreement

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On March 27, 2009, we entered into a three-year, $600 million secured revolving credit facility (the “Previous Credit Agreement”) and retained BNP Paribas as administrative agent to replace our initial four-year, $300 million revolving credit facility with BNP Paribas as administrative agent. All borrowings outstanding under the Previous Credit Agreement were paid in full on March 10, 2011 with borrowings under the Current Credit Agreement.

Current 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 (the "Current Credit Agreement"). In conjunction with BNP Paribas' sale of its energy lending practice to Wells Fargo Bank National Association ("Wells Fargo"), Wells Fargo is now the administrative agent under the Current Credit Agreement effective April 20, 2012. Our obligations under the Current Credit Agreement are secured by mortgages on 80% of our oil and natural gas properties as well as a pledge of all of our ownership interests in our operating subsidiaries. Borrowings under the Current Credit Agreement mature on March 10, 2016. The amount available for borrowing at any one time is limited to the borrowing base, which is currently set at $600 million with a $2 million sub-limit for letters of credit. The borrowing base is subject to semi-annual redeterminations on or about April 1 and October 1 of each year. On October 1, 2012, the borrowing base was increased to $600 million from $565 million. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. We also have the right, once during each calendar year, to 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. 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 66.67% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility. If the required lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66.67% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility, so long as it does not increase the borrowing base then in effect. Outstanding borrowings in excess of the borrowing base must be prepaid, and, if mortgaged properties represent less than 80% of total value of oil and gas properties evaluated in the most recent reserve report, we must pledge other oil and natural gas properties as additional collateral. Legacy may at any time issue up to $500 million in aggregate principal amount of 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) in the case of senior notes, 25% of the stated principal amount of the senior notes and (ii) in the case of new debt, 25% of the portion of the new debt that exceeds the principal amount of the senior notes. Also, notwithstanding that a lender (or its affiliate) is no longer a party to the Current Credit Agreement, any lender (or its affiliate) which has entered into any hedging arrangement with us while a party to the Current Credit Agreement will continue to have our obligations under such hedging arrangement secured on a ratable and pari passu basis by the collateral securing our obligations under the Current Credit Agreement, the related loan documents and our hedging arrangements.

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


•	with respect to ABR loans, the alternate base rate equals the highest of the prime rate, the Federal funds effective rate plus 0.50%, or the one-month London interbank rate (“LIBOR”) plus 1.00%, plus an applicable margin ranging from and including 0.75% and 1.75% 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 plus an applicable margin ranging from and including 1.75% and 2.75% per annum, determined by the percentage of the borrowing base then in effect that is drawn.

We pay a commitment fee equal to 0.50% per annum on the average daily amount of the unused amount of the commitments under the Current Credit Agreement, payable quarterly.

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

Our Current Credit Agreement also contains various covenants that limit our ability to:


•	incur indebtedness;

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•	enter into certain leases;


•	grant certain liens;


•	enter into certain derivatives;


•	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.

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


•	total debt as of the last day of the most recent quarter to EBITDA (as defined in the Current Credit Agreement) in total over the last four quarters of not more than 4.0 to 1.0; and


•	consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas derivatives and interest rate swaps.

If an event of default exists under our Current Credit Agreement, the lenders will be able to accelerate the maturity of the Current 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 Current 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 generally defined to mean members of our board of directors as of March 10, 2011 and persons who are nominated for election or elected to our general partner’s board of directors with the approval of a majority of the continuing directors who were members of such board of directors at the time of such nomination or election), (iii) the direct or indirect sale, transfer or other disposition in one or a series of related transactions of all or substantially all of the properties or assets (including equity interests of subsidiaries) of us and our subsidiaries to any person, (iv) the adoption of a plan related to our liquidation or dissolution or (v) Legacy Reserves GP, LLC ceasing to be our sole general partner;


•	the entry of, and failure to pay, one or more adverse judgments in excess of $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

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•	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.

As of September 30, 2012 , Legacy was in compliance with all covenants of the revolving credit facility.

Legacy periodically enters into interest rate swap transactions to mitigate the volatility of interest rates. As of September 30, 2012 , Legacy had interest rate swaps on notional amounts of $364 million with a weighted-average fixed rate of 2.17% . These swaps mature between April 2013 and November 2015.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon the condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. Legacy based its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:


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


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

Please read Note 1 of the Notes to the Condensed Consolidated Financial Statements here and in our Annual Report on Form 10-K for the period ended December 31, 2011 for a detailed discussion of all significant accounting policies that we employ and related estimates made by management.

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

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

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Effect if Different Assumptions Used: Units-of-production method to deplete our oil and natural gas properties — A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the three-month period ended September 30, 2012 by approximately 10%.

Nature of Critical Estimate Item: Asset Retirement Obligations — We have certain obligations to remove tangible equipment and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. US GAAP requires us to estimate asset retirement costs for all of our assets, adjust those costs for inflation to the forecasted abandonment date, discount that amount using a credit-adjusted risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an asset retirement obligation ("ARO") liability in that amount with a corresponding addition to our asset value. When new obligations are incurred, i.e. a new well is drilled or acquired, we add a layer to the ARO liability. We then accrete the liability layers quarterly using the applicable period-end effective credit-adjusted risk-free rates for each layer. Should either the estimated life or the estimated abandonment costs of a property change materially upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. Thus, abandonment costs will almost always approximate the estimate. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from our balance sheet.

Assumptions/Approach Used: Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

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

Nature of Critical Estimate Item: Derivative Instruments and Hedging Activities — We periodically use derivative financial instruments to achieve a more predictable cash flow from our oil, NGL and natural gas production and interest expense by reducing our exposure to price fluctuations and interest rate changes. Currently, these transactions are swaps, swaptions and collars whereby we exchange our floating price for our oil and natural gas for a fixed price and floating interest rates for a fixed rate with qualified and creditworthy counterparties (currently BNP Paribas, Bank of America Merrill Lynch, KeyBank, Wells Fargo, BBVA Compass Bank, Royal Bank of Canada, The Bank of Nova Scotia and Credit Agricole). Our existing oil and natural gas derivatives and interest rate swaps are with current or former members of our lending group which enables us to avoid margin calls for out-of-the-money mark-to-market positions.

We do not specifically designate derivative instruments as cash flow hedges, even though they reduce our exposure to changes in oil, NGL and natural gas prices and interest rate changes. Therefore, the mark-to-market of these instruments is recorded in current earnings. We use market value estimates prepared by a third party firm, which specializes in valuing derivatives, and validate these estimates by comparison to counterparty estimates as the basis for these end-of-period mark-to-market adjustments. When we record a mark-to-market adjustment resulting in a loss in a current period, these unrealized losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. As shown in tables on prior pages, we have hedged a significant portion of our future production through 2017. As oil and natural gas prices rise and fall, our future cash obligations related to these derivative transactions will rise and fall.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse

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

We periodically enter into, and anticipate entering into, derivative transactions in the future with respect to a portion of our projected oil, NGL and natural gas production through various transactions that mitigate the risk of the future prices received. These transactions may include price swaps, collars, three-way collars and swaptions. These derivative transactions are intended to support oil, NGL and natural gas prices at targeted levels and to manage our exposure to oil, NGL and natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

As of September 30, 2012 , the fair market value of Legacy’s commodity derivative positions was a net asset of $23.6 million based on NYMEX futures prices from October 2012 to June 2017 for both oil and natural gas. As of December 31, 2011 , the fair market value of Legacy’s commodity derivative positions was a net liability of $8.4 million based on NYMEX futures prices from January 2012 to December 2016 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 October 2012 through June 2017, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Investing Activities.”

Interest Rate Risks

At September 30, 2012 , Legacy had debt outstanding of $452 million , which incurred interest at floating rates in accordance with its revolving credit facility. The average annual interest rate incurred by Legacy for the nine -month period ended September 30, 2012 was 3.0% . A 1% increase in LIBOR on Legacy outstanding debt as of September 30, 2012 would result in an estimated $0.88 million increase in annual interest expense as Legacy has entered into interest rate swaps with a weighted-average fixed rate of 2.17% to mitigate the volatility of interest rates on notional amounts of $364 million of floating rate debt.

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 September 30, 2012 . 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.

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There have been no changes in our internal control over financial reporting that occurred during our fiscal quarter ended September 30, 2012 , 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, except as discussed in Note 4 in the Notes to the Condensed Consolidated Financial Statements, 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 risk factor set forth below and the other 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, 2011 and in our Quarterly Report on Form 10-Q for the period ended June 30, 2012, which could materially affect our business, financial condition or future results. 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.

An increase in the differential between the West Texas Intermediate (“WTI”) or other benchmark prices of oil and the wellhead price we receive for our production could adversely affect our financial condition.

The prices that we receive for our oil production sometimes reflect a discount to the relevant benchmark prices, such as WTI, that are used for calculating derivative positions. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark prices for oil and the wellhead price we receive could adversely affect our financial condition. For example, our oil revenues for the three-month period ended June 30, 2012 decreased $7.8 million compared to the three-month period ended June 30, 2011. This decrease was caused not only by a decrease in the average WTI crude oil price, but also by a significant increase in the Midland-to-WTI crude oil differential for the three-month period ended June 30, 2012. Significant price discounts or differentials between the benchmark prices, such as WTI and in the Rockies, and the prices we actually receive at the wellhead, could adversely affect our financial condition.

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Item 6. Exhibits.

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



Exhibit Number	Description
3.1	Certificate of Limited Partnership of Legacy Reserves LP (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.1)
3.2	Amended and Restated Limited Partnership Agreement of Legacy Reserves LP (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, included as Appendix A to the Prospectus and including specimen unit certificate for the units)
3.3	Amendment No.1, dated December 27, 2007, to the 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 January 2, 2008, 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	Amendment No. 1 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	Amendment No. 2 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)
10.1*	Employment Agreement effective September 24, 2012 between James Daniel Westcott and Legacy Reserves Services, Inc.
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.

Pursuant to Rule 406T of Regulation S-T, the interactive data files ("XBRL") on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL-related documents is "unaudited" or "unreviewed".

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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

October 31, 2012	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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Exhibit 10.1

EMPLOYMENT AGREEMENT

The parties to this Employment Agreement (this “ Agreement ”) are Legacy Reserves Services, Inc., a Texas corporation (the “ Employer ”), James Daniel Westcott (the “ Employee ”). The parties desire to provide for the employment of the Employee as Executive Vice President and Chief Financial Officer of Legacy Reserves GP, LLC, a Delaware limited liability company (the “ Company ”) on the terms set forth herein effective as of September 24, 2012 (the “ Effective Date ”). Legacy Reserves LP (“ Legacy ”), a Delaware limited partnership, is joining in this Agreement for the limited purposes of reflecting its agreement to the matters set forth herein as to it, but such joinder is not intended to make Legacy the employer of the Employee for any purpose.


1.	POSITION AND DUTIES .

1.1. Employment; Titles; Reporting . On the Effective Date, the Employer agrees to employ the Employee and the Employee agrees to enter employment with the Employer, upon the terms and subject to the conditions provided under this Agreement. During the Employment Term (as defined in Section 2 ), the Employee will serve as Executive Vice President and Chief Financial Officer of the Company. In such capacity, the Employee will report to and otherwise will be subject to the direction and control of the Board of Directors of the Company (including any committee thereof, the “ Board ”) and will have such duties, responsibilities and authorities as may be assigned to the Employee by the Board from time to time and otherwise consistent with such position in a public company, comparable in size to Legacy, which is engaged in natural gas and oil acquisition, development and production (including, but not limited to, maintaining, to the extent applicable, compliance with the Sarbanes-Oxley Act of 2002 and related regulations and all other federal, state and local laws and regulations, as well as all regulations and rules of any exchange or electronic trading system on which Legacy's securities may be traded).

1.2. Duties . During the Employment Term, the Employee will devote substantially all of his full working time to the business and affairs of the Employer, the Company and Legacy, will use his best efforts to promote the Employer's, the Company's, and Legacy's interests and will perform his duties and responsibilities faithfully, diligently and to the best of his ability, consistent with sound business practices. The Employee may be required by the Board to provide services to, or otherwise serve as an officer or director of, any direct or indirect subsidiary of the Employer, the Company or Legacy (the Employer, the Company, Legacy and all such direct and indirect subsidiaries of the Employer, the Company or Legacy being referred to herein as the “ Related Parties ”), as applicable. The Employee will comply with the Employer's, the Company's and Legacy's policies, codes and procedures, as they may be in effect from time to time, applicable to executive officers of the Company and Legacy. Nevertheless, the Employee may, with prior approval of the Board in each instance, engage in such other business and charitable activities that do not violate Section 7 , create a conflict of interest with the Employer, the Company or Legacy or materially interfere with the performance of the Employee's obligations to the Employer, the Company or Legacy under this Agreement. The activities in which the Employee is engaged as of the Effective Date, all of which have been approved by the Board, are listed on Exhibit A hereto. The activities listed on Exhibit A hereto as described by Employee to the Board on or before the Effective Date of this Agreement are not

a violation of any provision of this Agreement.

1.3. Place of Employment . The Employee will perform the Employee's duties under this Agreement at the Company's offices in Midland, Texas, with the likelihood of substantial business travel.


2.	TERM OF EMPLOYMENT .

The term of the Employee's employment by the Employer under this Agreement (the “ Employment Term ”) will commence on the Effective Date and will continue until employment is terminated by either party under Section 5 . The date on which the Employee's employment ends due to a “separation from service,” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “ Code ”), and Final Treasury Regulation Section 1.409A-1(h) and the default presumptions thereof, is referred to in this Agreement as the “ Termination Date .”


3.	COMPENSATION .

3.1. Base Salary . During the Employment Term, the Employee will be entitled to receive a base salary (“ Base Salary ”) at an annual rate of not less than $275,000 for services rendered to the Employer, the Company, Legacy, and any of their affiliates and their direct or indirect subsidiaries, payable in accordance with the Employer's regular payroll practices. The Employee's Base Salary will be reviewed annually by the Board and may be adjusted upward in the Board's sole discretion.

3.2. Annual Bonus Compensation . During the Employment Term, the Employee will be eligible to receive incentive compensation in such amounts and at such times as the Board may determine in its sole discretion to award to him under any incentive compensation or other bonus plan or arrangement as may be established by the Board from time to time (collectively “ Employee Bonus Plan ”), subject to and payable in accordance with the terms and conditions of any such Employee Bonus Plan. Any additional incentive compensation payable under any Employee Bonus Plan will be referred to in the aggregate in this Agreement as the Employee's “ Bonus .”

3.3. Long-Term Incentive Compensation . Awards of equity interests of Legacy (“ Units ”) and/or other forms of equity-based compensation to the Employee on or after the Effective Date may be made from time to time during the Employment Term by the Board in its sole discretion, whose decision will be based upon performance and award guidelines for executive officers of the Company and Legacy established periodically by the Board in its sole discretion.


4.	EXPENSES AND OTHER BENEFITS .

4.1. Reimbursement of Expenses . The Employee will be entitled to receive prompt reimbursement for all reasonable expenses, including professional fees, incurred by the Employee during the Employment Term (in accordance with the policies and practices presently followed by the Company or as may be established by the Board from time to time for the Company's senior executive officers) in performing services under this Agreement, provided that

the Employee properly accounts for such expenses in accordance with the Company's and Legacy's policies as in effect from time to time.

4.2. Vacation . The Employee will be entitled to paid vacation time each year during the Employment Term that will accrue in accordance with the Company's policies and procedures now in force or as such policies and procedures may be modified with respect to all senior executive officers of the Company.

4.3. Other Employee Benefits . In addition to the foregoing, during the Employment Term, the Employee will be entitled to participate in and to receive benefits as a senior executive under all of the Related Parties' employee benefit plans, programs and arrangements available to senior executives, subject to the eligibility criteria and other terms and conditions thereof, as such plans, programs and arrangements may be duly amended, terminated, approved or adopted by the Board from time to time.


5.	TERMINATION OF EMPLOYMENT .

5.1. Death . The Employee's employment under this Agreement will terminate upon his death.

5.2. Termination by the Employer .

(a) Terminable at Will . The Employer may terminate the Employee's employment under this Agreement at any time with or without Cause (as defined below).

(b) Definition of Cause . For purposes of this Agreement, the Employer will have “ Cause ” to terminate the Employee's employment under this Agreement by reason of any of the following: (i) the Employee's conviction of, or plea of nolo contendere to, any felony or to any crime or offense causing substantial harm to Legacy or its direct or indirect subsidiaries (whether or not for personal gain) or involving acts of theft, fraud, embezzlement, or moral turpitude or similar conduct; (ii) the Employee's being charged with any felony or crime, which charge or publicity arising from or related thereto has caused harm or, in the good faith judgment of the Board, may cause substantial harm to Legacy or its direct or indirect subsidiaries; (iii) the Employee's repeated intoxication by alcohol or drugs during the performance of the Employee's duties; (iv) malfeasance in the conduct of the Employee's duties, including, but not limited to, (A) willful and intentional misuse or diversion of any of the Related Parties' funds, (B) embezzlement or (C) fraudulent or willful and material misrepresentations or concealments on any written reports submitted to any of the Related Parties; (v) the Employee's material failure to perform the duties of the Employee's employment consistent with the Employee's position, expressly including the provisions of this Agreement, or material failure to follow or comply with the reasonable and lawful written directives of the Board; (vi) a material breach of this Agreement; or (vii) a material breach by the Employee of written policies of the Related Parties concerning employee discrimination or harassment.

(c) Notice and Cure Opportunity in Certain Circumstances . The Employee may be afforded a reasonable opportunity to cure any act or omission that

would otherwise constitute “Cause” hereunder according to the following terms: The Board will cause the Employer to give the Employee written notice stating with reasonable specificity the nature of the circumstances determined by the Board in good faith to constitute “Cause.” If, in the good faith judgment of the Board, the alleged breach is reasonably susceptible to cure, the Employee will have fifteen (15) days from his receipt of such notice to effect the cure of such circumstances or such breach to the good faith satisfaction of the Board. The Board will state whether the Employee will have such an opportunity to cure in the initial notice of “Cause” referred to above. If, in the good faith judgment of the Board the alleged breach is not reasonably susceptible to cure, or such circumstances or breach have not been satisfactorily cured within such fifteen (15) day cure period, such breach will thereupon constitute “Cause” hereunder.

5.3. Termination by the Employee .

(a) Terminable at Will . The Employee may terminate his employment under this Agreement at any time with or without Good Reason (as defined below).

(b) Notice and Cure Opportunity . If such termination is with Good Reason, the Employee will give the Employer written notice within thirty (30) days of the date the circumstance giving rise to the Good Reason first existed, which will identify with reasonable specificity the grounds for the Employee's resignation and provide the Employer with thirty (30) days from the day such notice is given to cure the alleged grounds for resignation contained in the notice. A termination will not be for Good Reason if such notice is given by the Employee to the Employer more than thirty (30) days after the occurrence of the event that the Employee alleges is Good Reason for the Employee's termination hereunder.

(c) Definition of Good Reason . For purposes of this Agreement, “ Good Reason ” will mean any of the following to which the Employee has not consented in writing: (a) a reduction in the Employee's Base Salary; (b) a relocation of the Employee's primary place of employment to a location more than 20 miles from Midland, Texas; or (c) any material reduction in the Employee's title, authority or responsibilities as Chief Accounting Officer and Controller of the Company.

5.4. Notice of Termination . Any termination of the Employee's employment by the Employer or by the Employee during the Employment Term (other than termination pursuant to Section 5.1 ) will be communicated by written Notice of Termination to the other party hereto in accordance with Section 9.8 . For purposes of this Agreement, a “ Notice of Termination ” means a written notice that (a) indicates the specific termination provision in this Agreement relied upon, (b) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Employee's employment under the provision so indicated, and (c) if the Termination Date is other than the date of receipt of such notice, specifies the Termination Date (which Termination Date will be not more than thirty (30) days after the giving of such notice). However, if the Employee submits a Notice of Termination specifying a Termination Date other than the date of Employer's receipt of such notice, the Employer may, at its sole discretion, change the Termination Date to any date on or after the date of Employer's receipt of such Notice of Termination and before the Termination Date specified

by the Employee in the Notice of Termination. If the Employer changes the Termination Date from the Termination Date the Employee specified in the Notice of Termination, the Employment Term shall be from the Effective Date until the Termination Date selected by the Employer.

5.5. Disability . If the Employer determines in good faith that the Disability (as defined herein) of the Employee has occurred during the Employment Term, it may, without breaching this Agreement, give to the Employee written notice in accordance with Section 5.4 of its intention to terminate the Employee's employment. In such event, the Employee's employment with the Employer will terminate effective on the fifteenth (15th) day after receipt of such notice by the Employee (the “ Disability Effective Date ”), provided that, within the fifteen (15) days after such receipt, the Employee will not have returned to full-time performance of the Employee's duties. “ Disability ” means the determination by a physician selected by the Employer that the Employee has been unable to perform the Employee's usual and customary duties under this Agreement for a period of at least one hundred twenty (120) consecutive days or a non-consecutive period of one hundred eighty (180) days during any twelve-month period as a result of incapacity due to mental or physical illness or disease. At any time and from time to time, upon reasonable request by the Employer, the Employee will submit to reasonable medical examination for the purpose of determining the Employee's ability to perform the essential functions of the job position, with or without any reasonable accommodation.


6.	COMPENSATION OF THE EMPLOYEE UPON TERMINATION .

6.1. Death . If the Employee's employment under this Agreement is terminated by reason of the Employee's death, the Employer will pay to the person or persons designated by the Employee for that purpose in a notice filed with the Employer, or, if no such person will have been so designated, to the Employee's estate the amount of (a) the Employee's accrued but unpaid Base Salary through the Termination Date paid in a lump sum within thirty (30) days following the Termination Date (or, if earlier, as required by applicable law), (b) any accrued but unpaid Bonus paid in a lump sum, which Bonus will be payable at such time as the bonuses of other executive officers of the Company are payable in accordance with the terms of the applicable Employee Bonus Plan, (c) a pro rata portion of any Bonus for the fiscal year in which the Termination Date occurs, paid in a lump sum at such time as bonuses for the annual period are paid to other executive officers of the Company in accordance with the terms of the applicable Employee Bonus Plan, and determined by multiplying the Employee's target Bonus for such period by a fraction, the numerator of which is the number of days from the first day of the fiscal year of the Company in which such termination occurs through and including the Termination Date and the denominator of which is 365 (“ Pro Rata Bonus ”), and (d) any other amounts that may be reimbursable by the Employer to the Employee as expressly provided under this Agreement paid in a lump sum within thirty (30) days following the Termination Date, and the Employer thereafter will have no further obligation to the Employee under this Agreement, other than for payment of any amounts accrued and vested under any employee benefit plans or programs of the Related Parties in accordance with the terms of such plans or programs and any payments or benefits required to be made or provided under applicable law.

6.2. Disability . In the event of the Employee's termination by reason of Disability pursuant to Section 5.5 , the Employee will continue to receive his Base Salary and

participate in applicable employee benefit plans or programs of the Related Parties (on an equivalent basis to Section 6.4(a)(iv) below) through the Termination Date, subject to offset dollar-for-dollar by the amount of any disability income payments provided to the Employee under any bona fide disability policy or program (within the meaning of Final Treasury Regulation Section 1.409A-1(a)(5)) funded by any of the Related Parties that covers a substantial number of employees of the Related Parties and was established prior to the date the Employee incurred a Disability, and will receive the amount of (a) the Employee's accrued but unpaid Base Salary through the Termination Date paid in a lump sum within thirty (30) days following the Termination Date (or, if earlier, as required by applicable law), (b) any accrued but unpaid Bonus paid in a lump sum, which Bonus will be payable at such time as the bonuses of other executive officers of the Company are payable in accordance with the terms of the applicable Employee Bonus Plan, (c) the Employee's Pro-Rata Bonus paid in a lump sum, payable at such time as bonuses for the annual period are paid to other executive officers of the Company in accordance with the terms of the applicable Employee Bonus Plan, and (d) any other amounts that may be reimbursable by the Employer to the Employee as expressly provided under this Agreement paid in a lump sum within thirty (30) days following the Termination Date, and the Employer thereafter will have no further obligation to the Employee under this Agreement, other than for payment of any amounts accrued and vested under any employee benefit plans or programs of the Related Parties in accordance with the terms of such plans or programs and any payments or benefits required to be made or provided under applicable law.

6.3. By the Employer for Cause or the Employee Without Good Reason . If the Employee's employment is terminated by the Employer for Cause, or if the Employee terminates Employee's employment other than for Good Reason, the Employee will receive the amount of (a) the Employee's accrued but unpaid Base Salary through the Termination Date paid in a lump sum within thirty (30) days following the Termination Date (or, if earlier, as required by applicable law), (b) any accrued but unpaid Bonus paid in a lump sum, which Bonus will be payable at such time as the bonuses of other executive officers of the Company are payable in accordance with the terms of the applicable Employee Bonus Plan, and (c) any other amounts that may be reimbursable by the Employer to the Employee as expressly provided under this Agreement paid in a lump sum within thirty (30) days following the Termination Date, and the Employer thereafter will have no further obligation to the Employee under this Agreement, other than for payment of any amounts accrued and vested under any employee benefit plans or programs of the Related Parties in accordance with the terms of such plans or programs and any payments or benefits required to be made or provided under applicable law.

6.4. By the Employee for Good Reason or the Employer other than for Cause .

(a) Severance Benefits on Non-Change of Control Termination . Subject to the provisions of Section 6.4(b) and Section 6.4(d) , if prior to or more than one (1) year after the occurrence of a Change of Control (as defined below) the Employer terminates the Employee's employment without Cause, or the Employee terminates his employment for Good Reason, then the Employee will be entitled to the following benefits (the “ Severance Benefits ”):

(i) an amount equal to (A) the Employee's accrued but unpaid Base Salary through the Termination Date paid in a lump sum within thirty (30)

days following the Termination Date (or, if earlier, as required by applicable law), (B) any accrued but unpaid Bonus paid in a lump sum, which Bonus will be payable at such time as the bonuses of other executive officers of the Company are payable in accordance with the terms of the applicable Employee Bonus Plan, and (C) any other amounts that may be reimbursable by the Employer to the Employee as expressly provided under this Agreement paid in a lump sum within thirty (30) days following the Termination Date or, if earlier, as required by applicable law;

(ii) twenty-four (24) monthly payments paid on the first monthly payroll date of the Company each month in an amount equal to one-twelfth (1/12) of the Employee's annual Base Salary at the highest rate in effect at any time during the thirty-six (36) month period prior to the Termination Date plus the average annual Bonus of the two (2) years preceding the Termination Date, commencing with the first monthly payroll date of the Company in the first month beginning after sixty (60) days following the Termination Date;

(iii) a cash amount equal to the Employee's Pro-Rata Bonus for the fiscal year in which the Termination Date occurs, paid in a lump sum at such time as bonuses for the annual period are paid to other executive officers of the Company in accordance with the terms of the applicable Employee Bonus Plan; and

(iv) to the extent that the Employee elects COBRA continuation coverage, the Employer will pay the full cost of the Employee's COBRA continuation coverage for the maximum period as COBRA continuation coverage is required to be provided under applicable law; provided , however , that the benefits described in this Section 6.4(a)(iv) may be discontinued prior to the end of the period provided in this Section 6.4(a)(iv) to the extent, but only to the extent, that the Employee receives substantially similar benefits from a subsequent employer (“ COBRA Benefit ”).

(b) Change of Control Benefits. Subject to the provisions of Section 6.4(d) , if within the one (1) year period following the occurrence of a Change of Control, the Employer terminates the Employee's employment without Cause, or the Employee terminates the Employee's employment for Good Reason, then, in lieu of the Severance Benefits under Section 6.4(a) , the Employee will be entitled to benefits (the “ Change of Control Benefits ”) identical to those set forth in Section 6.4(a) except that the amount described in clause (ii) will be equal to thirty-six (36) monthly payments and will be paid in a lump sum within sixty (60) days following the Termination Date, provided that if the sixty (60) day period begins in one taxable year and ends in a second taxable year, the payment shall not be made until the second taxable year.

(c) Definition of Change of Control. For purposes of this Agreement, a “ Change of Control ” will mean the first to occur of the following, provided that such Change of Control qualifies as a change in ownership, change in effective control or a change in ownership of a substantial portion of assets of Legacy within the meaning of

Section 409A of the Code:

(i) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “ Exchange Act ”)) (a “ Person ”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act), of 35% or more of either (A) the then-outstanding equity interests of Legacy (the “ Outstanding Legacy Equity ”) or (B) the combined voting power of the then-outstanding voting securities of Legacy entitled to vote generally in the election of directors (the “Outstanding Legacy Voting Securities” ); provided, however, that, for purposes of this Section 6.4(c)(i) , the following acquisitions will not constitute a Change of Control: (1) any acquisition directly from Legacy; (2) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Legacy or any affiliated company; (3) any acquisition by any corporation or other entity pursuant to a transaction that complies with Section 6.4(c)(iii)(A) , Section 6.4(c)(iii)(B) or Section 6.4(c)(iii)(C) ; or (4) any acquisition of Units from Legacy arising out of or in connection with an IPO or private placement of Legacy's securities;

(ii) Any time at which individuals who, as of the date hereof, constitute the Board (the “Incumbent Board” ) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by Legacy's Unitholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(iii) Consummation of a reorganization, merger, statutory share exchange or consolidation or similar corporate transaction involving Legacy or any of its subsidiaries, a sale or other disposition of all or substantially all of the assets of Legacy or any of its subsidiaries (each, a “Business Combination ”), in each case unless, following such Business Combination, (A) all or substantially all of the individuals and entities that were the beneficial owners of the Outstanding Legacy Equity and the Outstanding Legacy Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of the then-outstanding equity interests and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation, resulting from such Business Combination (including, without limitation, a corporation or other entity that, as a result of such transaction, owns Legacy or all or substantially all of Legacy's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Business Combination of the Outstanding Legacy Equity and the

Outstanding Legacy Voting Securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of Legacy or such corporation or other entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then-outstanding equity interests of the corporation or other entity resulting from such Business Combination or the combined voting power of the then-outstanding voting securities of such corporation or other entity, except to the extent that such ownership existed prior to the Business Combination, and (C) at least a majority of the members of the board of directors of the corporation or equivalent body of any other entity resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement or of the action of the Board providing for such Business Combination.

(d) Conditions to Receipt of Severance Benefits .

(i) Release . Any Severance Benefits or Change of Control Benefits to which the Employee may be entitled under Section 6.4(a) or Section 6.4(b) shall be payable only upon a termination of employment of the Employee, provided the Employee executes (and does not revoke) a release (“the “ Release ”), which, among other things, will include an affirmation of the restrictive covenants set forth in Section 7 and a non-disparagement provision, in a form and substance satisfactory to the Employer, of any claims, whether arising under federal, state or local statute, common law or otherwise, against the Employer and the Related Parties which arise or may have arisen on or before the date of the Release, other than any claims under this Agreement or any rights to indemnification from the Employer and the Related Parties pursuant to any provision of the Related Parties' organizational documents or any directors and officers liability insurance maintained by any of the Related Parties. The Release shall be provided to the Employee within five (5) business days following the Termination Date and must be signed by the Employee and returned to the Employer (and not revoked) within fifty-five (55) days following the Termination Date. If the Employee fails or otherwise refuses to execute a Release, the Employee will not be entitled to any Severance Benefits or Change of Control Benefits, as the case may be, or any other benefits provided under this Agreement, and the Employer will have no further obligations with respect to the provision of those benefits except as may be required by law.

(ii) Limitation on Benefits . If, following a termination of employment that gives the Employee a right to the payment of Severance Benefits under Section 6.4(a) or Section 6.4(b) , the Employee violates in any material respect any of the covenants in Section 7 or any other provision of the Release, the Employee will have no further right or claim to any payments or other benefits to which the Employee may otherwise be entitled under Section 6.4(a) or Section 6.4(b) from and after the date on which the Employee engages in such activities and the Employer will have no further obligations with respect to such

payments or benefits, and the covenants in Section 7 will nevertheless continue in full force and effect.

6.5. Severance Benefits Not Includable for Employee Benefits Purposes . Except to the extent the terms of any applicable benefit plan, policy or program provide otherwise, any benefit programs of any of the Related Parties that take into account the Employee's income or length of service will exclude any and all Severance Benefits and Change of Control Benefits provided under this Agreement.

6.6. Exclusive Severance Benefits . The Severance Benefits payable under Section 6.4(a) or the Change of Control Benefits payable under Section 6.4(b) , if they become applicable under the terms of this Agreement, will be in lieu of any other severance or similar benefits that would otherwise be payable under any other agreement, plan, program or policy of the Employer.

6.7. Section 280G of the Code .

(a) Notwithstanding anything in this Agreement to the contrary, in the event that any severance and other benefits provided to or for the benefit of the Employee or his legal representatives and dependents pursuant to this Agreement and any other agreement, benefit, plan, or policy of the Related Parties (this Agreement and such other agreements, benefits, plans, and policies collectively being referred to herein as the “ Change of Control Arrangements ”) constitute “parachute payments” within the meaning of Section 280G(b)(2) of the Code (such severance and other benefits being referred to herein as the “ Change of Control Payments ”) that would be subject to the excise tax imposed by Section 4999 of the Code (such excise tax referred to in this Agreement as the “ Excise Tax ”), then (i) if the shareholder approval exemption set forth in Section 280G(b)(5) is available, then the Employer and the Employee shall take all steps necessary, including, without limitation, waiver of rights by the Employee, to seek shareholder approval for such Change of Control Payments in accordance with Section 280G(b)(5) of the Code and the regulations promulgated thereunder; or (ii) if the shareholder approval exemption set forth in Section 280G(b)(5) is not available, then the Employer will provide the Employee with a computation of (A) the maximum amount of Change of Control Payments that could be made under the Change of Control Arrangements, without the imposition of the Excise Tax (said maximum amount being referred to as the “ Capped Amount ”); (B) the value of all Change of Control Payments that could be made pursuant to the terms of the Change in Control Arrangements (all said payments, distributions and benefits being referred to as the “ Uncapped Payments ”); (C) the dollar amount of Excise Tax which the Employee would become obligated to pay pursuant to Section 4999 of the Code as a result of receipt of the Uncapped Payments; and (D) the net value of the Uncapped Payments after reduction by (1) the amount of the Excise Tax, (2) the estimated income taxes payable by the Employee on the difference between the Uncapped Payments and the Capped Amount, assuming that the Employee is paying the highest marginal tax rate for state, local and federal income taxes, and (3) the estimated hospital insurance taxes payable by the Employee on the difference between the Uncapped Payments and the Capped Amount based on the hospital insurance tax rate under Section 3101(b) of the Code (the “ Net Uncapped Amount ”). If the Capped Amount is greater than the Net Uncapped Amount, the Employee shall be entitled to receive or commence to receive the Change of Control Payments equal to the Capped Amount; or if the Net Uncapped

Amount is greater than the Capped Amount, the Employee shall be entitled to receive or commence to receive the Change of Control Payments equal to the Uncapped Payments. If the Employee receives the Uncapped Payments, then the Employee shall be solely responsible for the payment of the Excise Tax due from the Employee and attributable to such Uncapped Payments, with no right of additional payment from any of the Related Parties as reimbursement for such taxes.

(b) Unless the Employer and the Employee otherwise agree in writing, any determination required under this Section 6.7 shall be made in writing by tax counsel or by an independent public accounting firm agreed to by the Employer and the Employee (the “ Auditor ”), whose determination shall be conclusive and binding upon the Employer and the Employee. For purposes of making the calculations required by this Section 6.7 , the Auditor may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of Sections 280G and 4999 of the Code. The Employer and the Employee shall furnish to the Auditor such information and documents as the Auditor may reasonably request in order to make a determination under this Section 6.7 . The Employer shall bear all costs the Auditor may reasonably incur in connection with any calculations contemplated by this Section 6.7 .


7.	RESTRICTIVE COVENANTS .

7.1. Confidential Information . The Employee hereby acknowledges that in connection with the Employee's employment by the Employer the Employee has been provided and will be provided Confidential Information (as defined below) (including, without limitation, procedures, memoranda, notes, records and customer and supplier lists whether such information has been or is made, developed or compiled by the Employee or otherwise has been or is made available to Employee), including information Employee has not received before, regarding the business and operations of the Related Parties. The Employee further acknowledges that such Confidential Information is unique, valuable, considered trade secrets and deemed proprietary by the Related Parties, and that the receipt of this Confidential information creates a special relationship of trust and confidence between the Employer, the Company, Legacy and the Employee. Employee thus acknowledges and agrees that it is fair and reasonable for the Employer, the Company and Legacy to take steps to protect itself. For purposes of this Agreement, “ Confidential Information ” includes, without limitation, any information heretofore or hereafter acquired, developed or used by any of the Related Parties relating to Business Opportunities or Intellectual Property or other geological, geophysical, economic, financial or management aspects of the business, operations, properties or prospects of the Related Parties, whether oral or in written form. The Employee agrees that all Confidential Information is and will remain the property of the Related Parties. The Employee further agrees, except for disclosures occurring in the good faith performance of Employee's duties for the Related Parties, during the Employment Term and at all times thereafter, to hold in the strictest confidence all Confidential Information, and not to, directly or indirectly, duplicate, sell, use, lease, commercialize, disclose or otherwise divulge to any person or entity any portion of the Confidential Information or use any Confidential Information for Employee's own benefit or profit or allow any person, entity or third party, other than the Related Parties and authorized executives of the same, to use or otherwise gain access to any Confidential Information. The Employee will have no obligation under this Agreement with respect to any information that

becomes generally available to the public other than as a result of a disclosure by the Employee or Employee's agent or other representative or becomes available to the Employee on a non-confidential basis from a source other than the Related Parties through no breach of any agreement with the Employer or any of the Related Parties. Further, the Employee will have no obligation under this Agreement to keep confidential any of the Confidential Information to the extent that a disclosure of it is required by law or is consented to by the Employer, the Company or Legacy in writing; provided , however , that if and when such a disclosure is required by law, the Employee promptly will provide the Employer with notice of such requirement, so that an appropriate protective order may be sought, and will cooperate with the Employer in any attempt by Employer to obtain any such appropriate protective order.

7.2. Return of Property . The Employee agrees that all Confidential Information, whether prepared by the Employee or otherwise coming into Employee's possession, is and shall remain the exclusive property of the Employer and/or Related Parties. Employee further agrees to deliver promptly to the Employer, upon termination of Employee's employment hereunder, or at any other time when the Employer so requests, all documents relating to the business of the Related Parties, including without limitation: all geological and geophysical reports and related data such as maps, charts, logs, seismographs, seismic records and other reports and related data, calculations, summaries, memoranda and opinions relating to the foregoing, production records, electric logs, core data, pressure data, lease files, well files and records, land files, abstracts, title opinions, title or curative matters, contract files, notes, records, drawings, manuals, correspondence, financial and accounting information, customer lists, statistical data and compilations, patents, copyrights, trademarks, trade names, inventions, formulae, methods, processes, agreements, contracts, manuals or any documents relating to the business of the Related Parties and all copies thereof and therefrom; provided, however, that the Employee will be permitted to retain copies of any documents or materials solely of a personal nature or otherwise related to the Employee's rights under this Agreement. Employee further agrees that, after Employee provides a copy of such information or documents to the Employer, Employee will immediately delete any information or documents relating to the Employer's business from any computer, cellular phone or other digital or electronic device owned by Employee.

7.3. Non-Compete Obligations . In consideration of the payments, benefits and other obligations of the Employer to the Employee pursuant to this Agreement, including, without limitation, the Employer's obligation to provide the Employee with Confidential Information pursuant to Section 7.1 hereof, and in order to protect such Confidential Information and preserve the goodwill of the Related Parties, the Employee hereby covenants and agrees to the following provisions.

(a) Non-Compete Obligations During Employment Term . The Employee agrees that during the Employment Term:

(i) the Employee will not, other than through the Related Parties, unless approved in writing by a majority of the Board of Directors, engage or participate in any manner, whether directly or indirectly, through any family member or as an employee, employer, consultant, agent, principal, partner, more than one percent shareholder, officer, director, licensor, lender, lessor or in

any other individual or representative capacity, in any business or activity which is engaged in leasing, acquiring, exploring, or producing, gathering or marketing hydrocarbons and related products (“ Competing Business ”), unless set forth on the approved activities list on Exhibit A; and

(ii) all investments made directly or indirectly by the Employee (whether in Employee's own name or in the name of any family members or other nominees or made by the Employee's controlled affiliates) in a Competing Business will be made solely through the Related Parties, unless approved in writing by a majority of the Board of Directors or unless such activity is set forth on Exhibit A; and the Employee will not directly or indirectly through any family members or other person or entity and will not permit any of Employee's controlled affiliates to: (A) invest or otherwise participate alongside the Related Parties in any Business Opportunities relating to or arising from a Competing Business, or (B) invest or otherwise participate in any business or activity relating to or arising from a Competing Business, regardless of whether any of the Related Parties ultimately participates in such business or activity, in either case, except through the Related Parties, unless approved in writing by a majority of the Board of Directors or unless such activity is set forth on Exhibit A.

(b) Non-Compete Obligations After Termination Date . The Employee agrees that the Employee will not in the Geographic Area engage or participate in any manner, whether directly or indirectly through any family member or other person or as an employee, employer, consultant, agent principal, partner, more than one percent shareholder, officer, director, licensor, lender, lessor or in any other individual or representative capacity, unless approved in writing by a majority of the Board of Directors or unless such activity is set forth on Exhibit A:

(i) During the 90-day period following the Termination Date, in any business or activity that is a Competing Business; and/or

(ii) During the one (1) year-period following the Termination Date, in any business or activity which is a publicly traded oil and gas income distribution company or partnership or a privately held company or partnership that is contemplating an initial public offering as an oil and gas income distribution company or partnership that is in direct competition with the business of the Related Parties in the leasing, acquiring, exploring, producing, gathering or marketing of hydrocarbons and related products; provided, that this subsection (ii) will not preclude the Employee from making investments in securities of oil and gas companies that are registered on a national stock exchange if (A) the aggregate amount owned by the Employee and all family members and affiliates does not exceed 5% of such company's outstanding securities, and (B) the aggregate amount invested in such investments by the Employee and all family members and affiliates after the date hereof does not exceed $500,000.

(iii) If Employee, in the future, seeks or is offered employment, or any other position or capacity with a Competing Business, Employee agrees to

inform each new employer or entity, before accepting employment, of the existence of the restrictions in Section 7. Further, before taking any employment position with any Competing Business during the two-year period following the Termination Date, Employee agrees to give prior written notice to the Employer of the name of such Competing Business and Employee's intent to take a position with such Competing Business. The Employer shall be entitled to advise such Competing Business of the provisions of Section 7 and to otherwise deal with such Competing Business to ensure that the provisions of Section 7 are enforced and duly discharged.

(c) Not Applicable Following Change of Control Termination . If Employee's employment is terminated within one (1) year after a Change of Control by the Employee for Good Reason or by the Employer without Cause, the Employee will not be subject to the covenants contained in this Section 7.3 .

(d) Geographic Area . For purposes of this Agreement, the “ Geographic Area ” shall mean (i) any county or parish in which the Related Parties own any oil and gas interests or conducts operations on the Termination Date or in which the Related Parties have owned any oil and gas interests or conducted operations at any time during the six months immediately preceding the Termination Date; or (ii) any county or parish adjacent to any county or parish described in clause (i) of this Section 7.3(d) .

7.4. Non-Solicitation . During the Employment Term and for a period of twenty-four (24) months after the Termination Date, the Employee, directly or indirectly, will not, whether for Employee's own account or for the account of any other person or entity:

(a) Other than for the benefit of and on behalf of the Related Parties during the Employment Term, solicit, attempt to transact business with, accept business from, transact business with, encourage or entice to end a relationship with any of the Related Parties, encourage or entice to lessen or alter a relationship with any of the Related Parties any client or customer of any of the Related Parties with whom Employee had any contact with - whether orally, in person or in any writing - during Employee's employment with the Employer or about whom or which the Employee learned of or obtained Confidential Information about during the Employee's employment with the Employer. The restrictions in this Section 7.4(a) concerning solicitations, attempting to transact business, transacting business, or accepting business applies only to solicitations for, or accepting business on behalf of, any Competing Business. Additionally, Employee agrees that, among other actions, any notification, update or other communication to any such client or customer of Employee's non-employment with the Employer or Employee's relationship or status with any other company, individual or entity - whether such notification or update is through LinkedIn, Facebook, any other social media outlet, email, letter or by any other method - constitutes a solicitation of business and an attempt to transact business with such client or customer; and

(b) solicit, hire, endeavor to entice away from the Related Parties, discuss or encourage leaving employment with the Related Parties or working for or providing services to any person or entity other than the Related Parties, or otherwise

interfere with the relationship of the Related Parties with any person who is currently employed by the Related Parties (including, without limitation, any independent contractors, engineers, geologists, sales representatives or organizations) or who had such a relationship with any of the Related Parties within the twelve (12) months preceding such solicitation, hiring, enticement, discussion, encouragement or interference.

7.5. Assignment of Developments . Employee hereby assigns to the Employer any rights Employee may have or acquire in Business Opportunities (defined below) and Proprietary Information (defined below) and recognizes that all Proprietary Information shall be the sole property of the Employer and its assigns and that the Employer and its assigns shall be the sole owner of all trade secret rights, patent rights, copyrights, and all other rights throughout the world (collectively, “ Proprietary Rights ”) related thereto. “ Proprietary Information ” means trade secrets, confidential knowledge, data or any other proprietary information of the Employer. By way of illustration but not limitation, Proprietary Information includes: (i) trade secrets, inventions, ideas, processes, formulas, source and object codes, data, programs, other works of authorship, knowhow, improvements, discoveries, developments, designs and techniques (hereinafter collectively referred to as “ Inventions ”); and (ii) tangible and intangible information relating to formulations, products, processes, know-how, designs, formulas, methods, developmental or experimental work, testing trials, improvements, discoveries, plans for research, new products, marketing and selling, business plans, budgets and unpublished financial statements, licenses, prices and costs, suppliers and customers, and information regarding the skills and compensation of other employees of the Employer. Employee further hereby assigns to the Employer all of Employee's right, title and interest in and to any and all Inventions (and all Proprietary Rights with respect thereto) whether or not patentable or registrable under copyright or similar statutes, made or conceived or reduced to practice or learned by Employee, either alone or jointly with others, during the Employee's employment with Employer, prior to the Effective Date or in conjunction or at the request of any other person or entity and related in any manner to leasing, acquiring, exploring, or producing, gathering or marketing hydrocarbons and related products, or any other line of business in which the Employer becomes involved during Employee's employment with the Employer (collectively, “ Prior O&G Inventions ”). Inventions and Prior O&G Inventions are hereinafter referred to as “ Company Inventions .” Employee recognizes that this Agreement does not require assignment of any invention which Employee developed entirely on Employee's own time without using the Employer's equipment, supplies, facilities or trade secret information, unless that invention (a) relates at the time of conception or reduction to practice of the invention to leasing, acquiring, exploring, or producing, gathering or marketing hydrocarbons and related products, or any other portion of the Employer's business or actual or demonstrably anticipated research or development of the Employer; or (b) results from any services performed by Employee for the Employer. Employee also assigns to, or as directed by, the Employer all of Employee's right, title and interest in and to any and all Inventions, full title to which is required to be in the United States by a contract between the Employer and the United States or any of its agencies. Employee also acknowledges that all original works of authorship which are made by Employee (solely or jointly with others) within the scope of the services that Employee provides to the Employer and which are protectable by copyright are “works made for hire,” as that term is defined in the United States Copyright Act (17 U.S.C., Section 101). Employee also agrees to promptly and fully disclose to Employer any and all Company Inventions and to assign to the Employer in the future when any such Company Inventions are first reduced to practice or first fixed in a tangible form all of Employee's right,

title and interest in and to any and all such Company Inventions. Employee further agrees to assist the Employer in every proper way to obtain and from time to time enforce United States and foreign Proprietary Rights relating to Company Inventions in any and all countries. To that end, Employee will execute, verify and deliver such documents and perform such other acts (including appearances as a witness) as the Employer may reasonably request for use in applying for, obtaining, perfecting, evidencing, sustaining and enforcing such Proprietary Rights and the assignment thereof. In addition, Employee will execute, verify and deliver assignments of such Proprietary Rights to the Employer or its designee. In the event the Employer is unable for any reason, after reasonable effort, to secure Employee's signature on any document needed in connection with the actions specified in this Section 7.5 , Employee hereby irrevocably designates and appoints the Employer and its duly authorized officers and agents as Employee's agent and attorney in fact, which appointment is coupled with an interest, to act for and in Employee's behalf to execute, verify and file any such documents and to do all other lawfully permitted acts to further the purposes of this Section 7.5 with the same legal force and effect as if executed by Employee. Employee hereby waives and quitclaims to the Employer any and all claims, of any nature whatsoever, which Employee now or may hereafter have for infringement of any Proprietary Rights assigned hereunder to the Employer. Employee agrees to keep and maintain adequate and current records (in the form of notes, sketches, drawings and in any other form that may be required by the Employer) of all Proprietary Information developed by Employee and all Inventions made by Employee during Employee's employment with the Employer, which records shall be available to and remain the sole property of the Employer at all times. Except for the Prior O&G Inventions, those Inventions, if any, patented or unpatented, that Employee made prior to Employee's employment with the Employer are excluded from the scope of this Agreement. For purposes of this Agreement, “ Business Opportunities ” means all business ideas, prospects, proposals or other opportunities pertaining to the lease, acquisition, exploration, production, gathering or marketing of hydrocarbons and related products and the exploration potential of geographical areas on which hydrocarbon exploration prospects are located, which are wholly or partially developed by the Employee or by a Competing Business during the Employment Term or originated by any third party and brought to the attention of the Employee during the Employment Term, together with information relating thereto (including, without limitation, geological and seismic data and interpretations thereof, whether in the form of maps, charts, logs, seismographs, calculations, summaries, memoranda, opinions or other written or charted means). However, Business Opportunities do not include the activities listed on Exhibit A hereto as described by Employee to the Board on or before the Effective Date of this Agreement.

7.6. Non-Disparagement . Employee agrees that the Employer's goodwill and reputation are assets of great value to the Employer which were obtained through great cost, time and effort. Therefore, Employee agrees that during Employee's employment with the Employer and after the termination of Employee's employment for any reason, Employee will not in any way disparage, libel or defame the Employer or any of the Related Parties or any of their businesses or business practices, products or services, or employees, officers, directors or owners.

7.7. Injunctive Relief . The Employee acknowledges that a breach of any of the covenants contained in this Section 7 may result in material, irreparable injury to the Employer for which there is no adequate remedy at law, that it will not be possible to measure damages for

such injuries precisely and that, in the event of such a breach or threat of breach, the Employer will be entitled to obtain a temporary restraining order and/or a preliminary or permanent injunction restraining the Employee from engaging in activities prohibited by this Section 7 or such other relief as may be required to specifically enforce any of the covenants in this Section 7 . To the extent that the Employer seeks a temporary restraining order (but not a preliminary or permanent injunction), the Employee agrees that a temporary restraining order may be obtained ex parte .

7.8. Adjustment of Covenants . The parties consider the covenants and restrictions contained in this Section 7 to be reasonable, that they give rise to the Employer's interest in restraining Employee as specified herein, and do not impose a greater restraint than is necessary to protect the goodwill or other business interest of the Employer and/or the Related Parties. In addition, the Employee agrees that the Employee shall not assert that, and it should not be considered that, any provisions of this Section 7 are otherwise void, voidable or unenforceable or should be voided or held unenforceable. However, in the event any court of competent jurisdiction or arbitration panel holds any provision of this Agreement to be invalid or unenforceable, such invalid or unenforceable portion(s) shall be limited or excluded from this Agreement to the minimum extent required, and the remaining provisions shall not be affected and shall remain in full force and effect. Employee further agrees that in the event any of the covenants contained in Section 7 shall be held by any court or arbitration panel to be effective in any particular area or jurisdiction only if said covenant is modified to limit its duration or scope, then the court or arbitration panel, as applicable, shall have such authority to reform the covenant and the Employer and Employee shall consider such covenant(s) and/or other provisions of Section 7 to be amended with respect to that particular jurisdiction so as to comply with the order of any such court or arbitration panel and, as to all other jurisdictions, the covenants contained herein shall remain in full force and effect as originally written.

7.9. Forfeiture Provision .

(a) Detrimental Activities . If the Employee engages in any activity that violates any covenant or restriction contained in Section 7 , in addition to any other remedy the Employer may have at law or in equity, (i) the Employee will be entitled to no further payments or benefits from the Employer under this Agreement or otherwise, except for any payments or benefits required to be made or provided under applicable law, (ii) all unexercised Unit options, restricted Units and other forms of equity compensation held by or credited to the Employee will terminate effective as of the date on which the Employee engages in that activity in accordance with the terms of the applicable agreements and plans, as amended from time to time, unless terminated sooner by operation of another term or condition of this Agreement or the applicable plans and agreements, and (iii) any exercise, payment or delivery pursuant to any equity compensation award that occurred within one year prior to the date on which the Employee engages in that activity may be rescinded within one year after the first date that a majority of the members of the Board first became aware that the Employee engaged in that activity. In the event of any such rescission, the Employee will pay to the Employer the amount of any gain realized or payment received as a result of the rescinded exercise, payment or delivery, in such manner and on such terms and conditions as may be required.

(b) Right of Set-Off. The Employee consents to a deduction from any amounts the Employer owes the Employee from time to time (including amounts owed as wages or other compensation, fringe benefits, or vacation pay, as well as any other amounts owed to the Employee by the Employer), to the extent of the amounts the Employee owes the Employer under Section 7.9(a) above. Whether or not the Employer elects to make any set-off in whole or in part, if the Employer does not recover by means of set-off the full amount the Employee owes, calculated as set forth above, the Employee agrees to pay immediately the unpaid balance to the Employer. In the discretion of the Board, reasonable interest may be assessed on the amounts owed, calculated from the later of (i) the date the Employee engages in the prohibited activity and (ii) the applicable date of exercise, payment or delivery.


8.	Tax Matters .

8.1. Section 409A of the Code .

a. Notwithstanding anything herein to the contrary, this Agreement is intended to be interpreted and applied so that the payments and benefits set forth herein shall either be exempt from the requirements of Section 409A of the Code, or shall comply with the requirements of Section 409A of the Code, and, accordingly, to the maximum extent permitted, this Agreement shall be interpreted to be exempt from or in compliance with Section 409A of the Code. Notwithstanding anything in this Agreement or elsewhere to the contrary, a termination of employment shall not be deemed to have occurred for purposes of any provision of this Agreement providing for the payment of any amounts or benefits that constitute “non-qualified deferred compensation” within the meaning of Section 409A of the Code upon or following a termination of the Employee's employment unless such termination is also a “separation from service” within the meaning of Section 409A of the Code and, for purposes of any such provision of this Agreement, references to a “termination,” “termination of employment” or like terms shall mean “separation from service” and the date of such separation from service shall be the Termination Date for purposes of any such payment or benefits.

b. To the extent that the Employer determines that any provision of this Agreement would cause the Employee to incur any additional tax or interest under Section 409A of the Code, the Employer shall be entitled to reform such provision to attempt to comply with or be exempt from Section 409A of the Code through good faith modifications in accordance with applicable guidance. To the extent that any provision hereof is modified in order to comply with Section 409A of the Code, such modification shall be made in good faith and shall, to the maximum extent reasonably possible, maintain the original intent and economic benefit to the Employee and the Employer without violating the provisions of Section 409A of the Code and shall be made in accordance with applicable guidance.

c. Notwithstanding any provision in this Agreement or elsewhere to the contrary, if on his Termination Date the Employee is deemed to be a “specified employee” within the meaning of Section 409A of the Code, any payments or benefits due upon a termination of the Employee's employment under any arrangement that constitutes a “deferral of compensation” within the meaning of Section 409A of the Code (whether under this Agreement, any other plan, program, payroll practice or any equity grant) and which do not otherwise qualify

under the exemptions under Treas. Reg. § 1.409A-1 (including without limitation, the short-term deferral exemption and the permitted payments under Treas. Reg. § 1.409A-1(b)(9)(iii)(A)), shall be delayed and paid or provided to the Employee in a lump sum (whether they would have otherwise been payable in a single sum or in installments in the absence of such delay) on the earlier of (i) the date which is the 1st day of the 7th calendar month that begins after the date of the Employee's “separation from service” (as such term is defined in Section 409A of the Code) for any reason other than death, and (ii) the date of the Employee's death, and any remaining payments and benefits shall be paid or provided in accordance with the normal payment dates specified for such payment or benefit.

d. For purposes of the application of Treas. Reg. § 1.409A-1(b)(4) (or any successor provision), each payment under this Agreement to the Employee (including any installment payments) shall be deemed a separate payment.

e. In no event may the Employee, directly or indirectly, designate the calendar year of any payment to be made under this Agreement or otherwise which constitutes a “deferral of compensation” within the meaning of Section 409A of the Code.

f. With respect to any expense, reimbursement or in-kind benefit provided pursuant to this Agreement that constitutes a “deferral of compensation” within the meaning of Section 409A of the Code, (a) the expenses eligible for reimbursement or in-kind benefits provided to the Employee must be incurred during the Employment Term, (b) the amount of expenses eligible for reimbursement or in-kind benefits provided to the Employee during any calendar year will not affect the amount of expenses eligible for reimbursement or in-kind benefits provided to the Employee in any other calendar year, (c) the reimbursements for expenses for which the Employee is entitled to be reimbursed shall be made on or before the last day of the calendar year following the calendar year in which the applicable expense is incurred, and (d) the right to payment or reimbursement or in-kind benefits hereunder may not be liquidated or exchanged for any other benefit.

g. With respect to the payment of any amount under this Agreement to which Section 409A of the Code applies, neither the Employee nor the Related Parties may defer or accelerate any payment other than as provided hereunder or as provided under Treas. Reg. § 1.409A-2(b)(7) or Treas. Reg. § 1.409A-3(j)(4).

8.2. Tax Withholding . All payments (or transfers of property) to the Employee shall be subject to tax withholding in accordance with applicable law.


9.	MISCELLANEOUS .

9.1. No Expectation of Privacy . The Employee understands and agrees that the Employee has no expectation of privacy with respect to the Employer's telecommunications, networking, or information processing systems (including, without limitation, stored, created or accessed computer files, e-mail messages, and voice messages) and that the Employee's activity and any files or messages on or use of any such systems may be accessed, monitored, copied, disclosed, and saved by the Employer at any time without notice to the Employee.

9.2. Assignment; Successors; Binding Agreement . This Agreement may not be

assigned by either party, whether by operation of law or otherwise, without the prior written consent of the other party, except that any right, title or interest of the Employer arising out of this Agreement may be assigned to any corporation or entity controlling, controlled by, or under common control with the Employer, or succeeding to the business and substantially all of the assets of the Employer or any affiliates for which the Employee performs substantial services. Subject to the foregoing, this Agreement will be binding upon and will inure to the benefit of the parties and their respective heirs, legatees, devisees, personal representatives, successors and assigns.

9.3. Modification and Waiver . Except as otherwise provided below (or as set forth in Section 7.8 ), no provision of this Agreement may be modified, waived, or discharged unless such waiver, modification or discharge is duly approved by the Board and is agreed to in writing by the Employee and such officer(s) as may be specifically authorized by the Board to effect it. No waiver by any party of any breach by any other party of, or of compliance with, any term or condition of this Agreement to be performed by any other party, at any time, will constitute a waiver of similar or dissimilar terms or conditions at that time or at any prior or subsequent time.

9.4. Entire Agreement . This Agreement embodies the entire understanding of the parties hereof, and, upon the Effective Date, will supersede all other oral or written agreements or understandings between them regarding the subject matter hereof. However, this Agreement does not supersede any non-competition, non-disclosure, non-solicitation, confidentiality, intellectual property assignment, or non-disparagement provisions or agreements that the Employee and the Employer have previously entered, and the Employer and the Employee agree that this Agreement and any such prior provisions and/or agreements are both enforceable and may run concurrently and both be enforced. No agreement or representation, oral or otherwise, express or implied, with respect to the subject matter of this Agreement, has been made by either party which is not set forth expressly in this Agreement.

9.5. Governing Law . The validity, interpretation, construction and performance of this Agreement will be governed by the laws of the State of Texas other than the conflict of laws provision thereof.

9.6. Consent to Jurisdiction and Service of Process .

(a) Section 7 Disputes . In the event of any dispute, controversy or claim between the Employer and the Employee arising out of or relating to the interpretation, application or enforcement of the provisions of Section 7 , the Employer and the Employee agree and consent to the personal jurisdiction of the state and local courts of Midland County, Texas and/or the United States District Court for the Western District of Texas for resolution of the dispute, controversy or claim, and that those courts, and only those courts, will have jurisdiction to determine any dispute, controversy or claim related to, arising under or in connection with Section 7 of this Agreement. The Employer and the Employee also agree that those courts are convenient forums for the parties to any such dispute, controversy or claim and for any potential witnesses and that process issued out of any such court or in accordance with the rules of practice of that court may be served by mail or other forms of substituted service to the Employer at the

address of its principal executive offices and to the Employee at his last known address as reflected in the Employer's records.

(b) Disputes Other Than Under Section 7 . In the event of any dispute relating to this Agreement, other than a dispute relating solely to Section 7 , the parties will use their best efforts to settle the dispute, claim, question, or disagreement. To this effect, they will consult and negotiate with each other in good faith and, recognizing their mutual interests, attempt to reach a just and equitable solution satisfactory to both parties. If such a dispute cannot be settled through negotiation, the parties agree first to try in good faith to settle the dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules before resorting to arbitration, litigation, or some other dispute resolution procedure. If the parties do not reach such solution through negotiation or mediation within a period of sixty (60) days, then, upon notice by either party to the other, all disputes, claims, questions, or differences will be finally settled by arbitration administered by the American Arbitration Association in accordance with the provisions of its Commercial Arbitration Rules. The arbitrator will be selected by agreement of the parties or, if they do not agree on an arbitrator within thirty (30) days after either party has notified the other of his or its desire to have the question settled by arbitration, then the arbitrator will be selected pursuant to the procedures of the American Arbitration Association (the “ AAA ”) in Midland, Texas. The determination reached in such arbitration will be final and binding on all parties. Enforcement of the determination by such arbitrator may be sought in any court of competent jurisdiction. Unless otherwise agreed by the parties, any such arbitration will take place in Midland, Texas, and will be conducted in accordance with the Commercial Arbitration Rules of the AAA.

9.7. Withholding of Taxes . The Employer will withhold from any amounts payable under the Agreement all federal, state, local or other taxes as legally will be required to be withheld.

9.8. Notices . All notices, consents, waivers, and other communications under this Agreement must be in writing and will be deemed to have been duly given when (a) delivered by hand (with written confirmation of receipt), (b) sent by facsimile (with written confirmation of receipt), provided that a copy is mailed by registered mail, return receipt requested, or (c) when received by the addressee, if sent by a nationally recognized overnight delivery service (receipt requested), in each case to the appropriate addresses and facsimile numbers set forth below (or to such other addresses and facsimile numbers as a party may designate by notice to the other parties):

to the Employer, to:

Attn: Chairman of the Board

Legacy Reserves Services, Inc.

303 W. Wall, Suite 1600

Midland, Texas 79701

to the Employee, to:

James Daniel Westcott

303 W. Wall, Suite 1600

Midland, Texas 79701

Addresses may be changed by written notice sent to the other party at the last recorded address of that party.

9.9. Severability . The invalidity or unenforceability of any provision or provisions of this Agreement will not affect the validity or enforceability of any other provision of this Agreement, which will remain in full force and effect.

9.10. Counterparts . This Agreement may be executed in one or more counterparts, each of which will be deemed to be an original but all of which together will constitute one and the same instrument.

9.11. Headings . The headings used in this Agreement are for convenience only, do not constitute a part of the Agreement, and will not be deemed to limit, characterize, or affect in any way the provisions of the Agreement, and all provisions of the Agreement will be construed as if no headings had been used in the Agreement.

9.12. Construction . As used in this Agreement, unless the context otherwise requires: (a) the terms defined herein will have the meanings set forth herein for all purposes; (b) references to “Section” are to a section hereof; (c) “include,” “includes” and “including” are deemed to be followed by “without limitation” whether or not they are in fact followed by such words or words of like import; (d) “writing,” “written” and comparable terms refer to printing, typing, lithography and other means of reproducing words in a visible form; (e) “hereof,” “herein,” “hereunder” and comparable terms refer to the entirety of this Agreement and not to any particular section or other subdivision hereof or attachment hereto; (f) references to any gender include references to all genders; and (g) references to any agreement or other instrument or statute or regulation are referred to as amended or supplemented from time to time (and, in the case of a statute or regulation, to any successor provision).

9.13. Capacity; No Conflicts . The Employee represents and warrants to the Employer that: (i) the Employee has full power, authority and capacity to execute and deliver this Agreement, and to perform the Employee's obligations hereunder, (ii) such execution, delivery and performance will not (and with the giving of notice or lapse of time, or both, would not) result in the breach of any agreement or other obligation to which the Employee is a party or is otherwise bound, and (iii) this Agreement is the Employee's valid and binding obligation, enforceable in accordance with its terms.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, the parties have duly executed this Agreement effective as of the Effective Date.



		EMPLOYER
		LEGACY RESERVES SERVICES, INC.

		By:	/s/ Cary D. Brown
			Cary D. Brown, Chief Executive Officer

		COMPANY
		LEGACY RESERVES GP, LLC

		By:	/s/ Cary D. Brown
			Cary D. Brown, Chairman, President
			and Chief Executive Officer

		LEGACY
		LEGACY RESERVES LP
		By:	Legacy Reserves GP, LLC
			Its General Partner

		By:	/s/ Cary D. Brown
			Cary D. Brown, Chairman, President
			and Chief Executive Officer

		EMPLOYEE


		By:	/s/ James Daniel Westcott
			James Daniel Westcott

EXHIBIT A

APPROVED OUTSIDE ACTIVITIES AS OF EFFECTIVE DATE

None.

SCHEDULE 1 TO RESIGNATION, CONSENT AND APPOINTMENT AGREEMENT AND AMENDMENT AGREEMENT

(LEGACY RESERVES LP)

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Cary D. Brown, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Legacy Reserves LP (the “registrant”) for the quarter ended September 30, 2012 ;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



October 31, 2012	By:	/s/ Cary D. Brown
		Cary D. Brown
		Chairman of the Board, President and Chief Executive Officer of Legacy Reserves GP, LLC, general partner of Legacy Reserves LP (Principal Executive Officer)

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, James Daniel Westcott, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Legacy Reserves LP (the “registrant”) for the quarter ended September 30, 2012 ;


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



October 31, 2012	By:	/s/ James Daniel Westcott
		James Daniel Westcott
		Executive Vice President and Chief Financial Officer of Legacy Reserves GP, LLC, general partner of Legacy Reserves LP (Principal Financial Officer)

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Legacy Reserves LP (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of Legacy Reserves GP, LLC (the "Company”), the general partner of the Partnership, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.



/s/ Cary D. Brown		/s/ James Daniel Westcott
Cary D. Brown		James Daniel Westcott
Chairman of the Board, President and Chief Executive Officer		Executive Vice President and Chief Financial Officer

October 31, 2012		October 31, 2012

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.