UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~March~~June 3130, 2018

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-33249

Legacy Reserves LP

(Exact name of registrant as specified in its charter)



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

303 W. Wall, Suite 1800 Midland, Texas		79701
(Address of principal executive offices)		(Zip code)

(432) 689-5200

(Registrant’s telephone number, including area code)

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

x Yes o No

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

x Yes o No

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



Large accelerated filer o		Accelerated filer x
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o
		Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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

76,~~893~~929,~~759~~029 units representing limited partner interests in the registrant were outstanding as of ~~April~~July 3031, 2018.

TABLE OF CONTENTS

		Page
	Glossary of Terms	Page 3
	Part I - Financial Information
Item 1.	Financial Statements.
	Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017 (Unaudited).	Page 6
	Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 (Unaudited).	Page 6
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017 (Unaudited).	Page 8
	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017 (Unaudited).	Page 8
	Condensed Consolidated Statement of Partners' Deficit for the three months ended March 31, 2018 (Unaudited).	Page 9
	Condensed Consolidated Statement of Partners' Deficit for the six months ended June 30, 2018 (Unaudited).	Page 9
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017 (Unaudited).	Page 10
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017 (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 3336
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	Page 4752
Item 4.	Controls and Procedures.	Page 4752
	Part II - Other Information
Item 1.	Legal Proceedings.	Page 4954
Item 1A.	Risk Factors.	Page 4955
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	Page 5055
Item 6.	Exhibits.	Page 5256
	Signatures	Page 5457

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 or PDPs. Reserves that can be expected to be recovered through: (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

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

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

Proved undeveloped reserves or PUDs. Proved undeveloped oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Proved reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Proved undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

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

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

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

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

Reserve replacement cost. An amount per Boe equal to the sum of costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural gas prices in recent years have increased the economic life of reserves, adding additional reserves with

Page 4

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.

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

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

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

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

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

Page 5

Part I – FINANCIAL INFORMATION

Item 1. Financial Statements.

LEGACY RESERVES LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

ASSETS
	March 31, 2018			December 31, 2017
	June 30, 2018			December 31, 2017
	(In thousands)
Current assets:
Cash	$	—5,948		$	1,246
Accounts receivable, net:
Oil and natural gas	6657,~~254~~676			62,755
Joint interest owners	2116,~~074~~515			27,420
Other	26			2
Fair value of derivatives (Notes 7 and 8)	15,034			13,424
Fair value of derivatives (Notes 8 and 9)	28,046			13,424
Prepaid expenses and other current assets (Note 1)	710,~~575~~457			7,757
Total current assets	~~109~~118,~~939~~648			112,604
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	3,~~423~~497,~~592~~220			3,529,971
Unproved properties	2931,~~492~~661			28,023
Accumulated depletion, depreciation, amortization and impairment	(2,~~093~~157,~~640~~542		)	(2,204,638		)
	1,359,444			1,353,356
	1,371,339			1,353,356
Other property and equipment, net of accumulated depreciation and amortization of $11,746 and $11,467, respectively	2,739			2,961
Other property and equipment, net of accumulated depreciation and amortization of $11,971 and $11,467, respectively	2,532			2,961
Operating rights, net of amortization of $5,855 and $5,765, respectively	1,162			1,251
Operating rights, net of amortization of $5,944 and $5,765, respectively	1,072			1,251
Fair value of derivatives (Notes 7 and 8)	14,150			14,099
Fair value of derivatives (Notes 8 and 9)	9,968			14,099
Other assets	86,~~175~~991			8,811
Total assets	$	1,~~495~~510,~~609~~550		$	1,493,082

See accompanying notes to condensed consolidated financial statements.

Page 6

LEGACY RESERVES LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

LIABILITIES AND PARTNERS' DEFICIT
	March 31, 2018			December 31, 2017
	June 30, 2018			December 31, 2017
	(In thousands)
Current liabilities:
Accounts payable	$	3,363		$	13,093
Current debt, net (Notes 1 and 2)	$	505,222		$	—
Accrued oil and natural gas liabilities (Note 1)	72,602			81,318
Accounts payable	6,626			13,093
Fair value of derivatives (Notes 7 and 8)	18,164			18,013
Accrued oil and natural gas liabilities (Note 1)	119,086			81,318
Asset retirement obligation (Note 9)	3,214			3,214
Fair value of derivatives (Notes 8 and 9)	27,740			18,013
Other	42,602			29,172
Asset retirement obligation (Note 10)	3,214			3,214
Total current liabilities	139,945			144,810
Other	46,538			29,172
Long-term debt, net (Note 2)	1,296,953			1,346,769
Total current liabilities	708,426			144,810
Asset retirement obligation (Note 9)	258,554			271,472
Long-term debt, net (Notes 1 and 2)	784,753			1,346,769
Fair value of derivatives (Notes 7 and 8)	628			1,075
Asset retirement obligation (Note 10)	261,031			271,472
Fair value of derivatives (Notes 8 and 9)	6,682			1,075
Other long-term liabilities	643			643
Total liabilities	1,~~696~~761,~~723~~535			1,764,769
Commitments and contingencies (Note 6)
Commitments and contingencies (Note 7)
Partners' deficit (Note 10):
Partners' deficit (Note 11):
Series A Preferred equity - 2,300,000 units issued and outstanding at March 31, 2018 and December 31, 2017	55,192			55,192
Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2018 and December 31, 2017	55,192			55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at March 31, 2018 and December 31, 2017	174,261			174,261
Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2018 and December 31, 2017	174,261			174,261
Incentive distribution equity - 100,000 units issued and outstanding at March 31, 2018 and December 31, 2017	30,814			30,814
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2018 and December 31, 2017	30,814			30,814
Limited partners' deficit - 76,658,829 and 72,594,620 units issued and outstanding at March 31, 2018 and December 31, 2017, respectively	(461,236		)	(531,794		)
Limited partners' deficit - 76,793,940 and 72,594,620 units issued and outstanding at June 30, 2018 and December 31, 2017, respectively	(511,095		)	(531,794		)
General partner's deficit (approximately 0.02%)	(~~145~~157		)	(160		)
Total partners' deficit	(~~201~~250,~~114~~985		)	(271,687		)
Total liabilities and partners' deficit	$	1,~~495~~510,~~609~~550		$	1,493,082

See accompanying notes to condensed consolidated financial statements.

Page 7

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended						Six Months Ended
	March 31,
	June 30,						June 30,
	2018			2017			2018			2017
	(In thousands, except per unit data)
Revenues:
Oil sales	$	9399,~~411~~799		$	4946,~~142~~096		$	193,210		$	95,238
Natural gas liquids (NGL) sales	75,~~396~~735			54,~~050~~921			13,131			9,971
Natural gas sales	3633,~~672~~747			4541,~~355~~830			70,419			87,185
Total revenues	~~137~~139,~~479~~281			9992,~~547~~847			276,760			192,394
Expenses:
Oil and natural gas production	4749,~~967~~431			5144,~~217~~802			97,398			96,019
Production and other taxes	7,~~326~~658			4,~~159~~145			14,984			8,304
General and administrative	2422,~~090~~496			108,~~552~~581			46,586			19,133
Depletion, depreciation, amortization and accretion	3638,~~547~~139			2827,~~796~~689			74,686			56,485
Impairment of long-lived assets	—35,381			81,~~062~~821			35,381			9,883
Gain on disposal of assets	(20,395		)	(5,524		)
(Gains) losses on disposal of assets	(1,145		)	11,049			(21,540		)	5,525
Total expenses	95151,~~535~~960			9798,~~262~~087			247,495			195,349
Operating income	41,944			2,285
Operating (loss) income	(12,679		)	(5,240		)	29,265			(2,955		)
Other income (expense):
Interest income	123			18			15			9
Interest expense (Notes 2, 7 and 8)	(27,368		)	(20,133		)
Interest expense (Notes 2, 8 and 9)	(28,589		)	(20,614		)	(55,957		)	(40,747		)
Gain on extinguishment of debt (Note 2)	~~51,693~~—			—			51,693			—
Equity in income of equity method investees	173			111			20			12
Net gains (losses) on commodity derivatives (Notes 7 and 8)	(1,704		)	34,669
Net gains (losses) on commodity derivatives (Notes 8 and 9)	(9,315		)	14,516			(11,019		)	49,185
Other	~~275~~(2		)	~~(40~~402		)	273			362
Income before income taxes	64,869			16,793
Income (loss) before income taxes	(50,579		)	(10,927		)	14,290			5,866
Income tax expense	(~~487~~130		)	(~~421~~150		)	(617		)	(571		)
Net income	$	64,382		$	16,372
Net income (loss)	$	(50,709	)	$	(11,077	)	$	13,673		$	5,295
Distributions to preferred unitholders	(4,750		)	(4,750		)	(9,500		)	(9,500		)
Net income attributable to unitholders	$	59,632		$	11,622
Net income (loss) attributable to unitholders	$	(55,459	)	$	(15,827	)	$	4,173		$	(4,205	)
Income per unit - basic and diluted (Note 10)	$	0.78		$	0.16
Income (loss) per unit - basic & diluted (Note 11)	$	(0.72	)	$	(0.22	)	$	0.05		$	(0.06	)
Weighted average number of units used in computing net income per unit -
Weighted average number of units used in computing net income (loss) per unit -
Basic	76,~~350~~725			72,~~103~~354			76,539			72,229
Diluted	76,~~657~~725			72,~~103~~354			77,433			72,229

See accompanying notes to condensed consolidated financial statements.

Page 8

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' DEFICIT

FOR THE ~~THREE~~SIX MONTHS ENDED ~~MARCH~~JUNE 3130, 2018

(UNAUDITED)

	Series A Preferred Equity			Series B Preferred Equity			Incentive Distribution Equity			Partners' Deficit
	Units	Amount		Units	Amount		Units	Amount		Limited Partner Units	Limited Partner Amount			General Partner Amount			Total Partners' Deficit
	(In thousands)
Balance, December 31, 2017	2,300	$	55,192	7,200	$	174,261	100	$	30,814	72,595	$	(531,794	)	$	(160	)	$	(271,687	)
Unit-based compensation	—	—		—	—		—	—		—	263			—			263
Units issued to Legacy Board of Directors for services	—	—		—	—		—	—		60	522			—			522
Vesting of restricted and phantom units	—	—		—	—		—	—		264	—			—			—
Unit-based compensation	—	—		—	—		—	—		—	579			—			579
Vesting of restricted and phantom units	—	—		—	—		—	—		339	—			—			—
Units issued in exchange for Standstill Agreement	—	—		—	—		—	—		3,800	5,928			—			5,928
Net income	—	—		—	—		—	—		—	6413,~~367~~670			153			6413,~~382~~673
Balance, March 31, 2018	2,300	$	55,192	7,200	$	174,261	100	$	30,814	76,659	$	(461,236	)	$	(145	)	$	(201,114	)
Balance, June 30, 2018	2,300	$	55,192	7,200	$	174,261	100	$	30,814	76,794	$	(511,095	)	$	(157	)	$	(250,985	)

See accompanying notes to condensed consolidated financial statements.

Page 9

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	Six Months Ended June 30,
	2018			2017
	(In thousands)
Cash flows from operating activities:
Net income	$	6413,~~382~~673		$	165,~~372~~295
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	3674,~~547~~686			2856,~~796~~485
Amortization of debt discount and issuance costs	710,~~509~~752			13,~~805~~713
Gain on extinguishment of debt	(51,693		)	—
Impairment of long-lived assets	—35,381			89,~~062~~883
(Gain) loss on derivatives	~~837~~10,052			(3549,~~511~~942		)
Equity in income of equity method investees	(17		)	(11		)
Unit-based compensation	24,994			2,827
Unit-based compensation	12,324			1,401
(Gain) loss on disposal of assets	(21,540		)	5,525
Gain on disposal of assets	(20,395		)	(5,524		)
Changes in assets and liabilities:
Increase in accounts receivable, oil and natural gas	(3,499		)	(2,698		)
Decrease in accounts receivable, oil and natural gas	5,079			1,003
Decrease in accounts receivable, joint interest owners	6,346			2,298
Decrease (increase) in accounts receivable, joint interest owners	10,905			(3,259		)
Decrease (increase) in other assets	843			(1,870		)
Increase in accounts receivable, other	(4		)	(399		)
Decrease in accounts payable	(9,730		)	(4,899		)
(Increase) decrease in other assets	(880		)	148
(Decrease) increase in accrued oil and natural gas liabilities	3,787			19,119
Decrease in accounts payable	(6,467		)	(109		)
Increase in other liabilities	6,776			7,552
Increase in accrued oil and natural gas liabilities	12,035			8,519
Total adjustments	(10,365		)	18,520
Decrease in other liabilities	(1,989		)	(4,558		)
Net cash provided by operating activities	54,017			34,892
Total adjustments	101,311			29,836
Net cash provided by operating activities	114,984			35,131
Cash flows from investing activities:
Investment in oil and natural gas properties	(73118,~~870~~324		)	(2861,~~961~~910		)
Proceeds associated with sale of assets	27,100			4,397
Proceeds (costs) associated with sale of assets	29,235			(199		)
Investment in other equipment	(57130		)	(62110		)
Net cash settlements (paid) received on commodity derivatives	(25,~~795~~209		)	410,~~236~~807
Net cash used in investing activities	(4994,~~622~~428		)	(2051,~~390~~412		)
Cash flows from financing activities:
Proceeds from long-term debt	~~265~~382,626			94211,000
Payments of long-term debt	(~~248~~375,384		)	(~~109~~196,000		)
Payments of debt issuance costs	(2223,~~875~~096		)	(4960		)
Net cash used in financing activities	(5,633		)	(15,049		)
Net cash (used in) provided by financing activities	(15,854		)	14,940
Net decrease in cash and cash equivalents	(1,238		)	(547		)
Net increase (decrease) in cash and cash equivalents	4,702			(1,341		)
Cash, beginning of period (1)	4,~~438~~450			65,~~161~~747
Cash, end of period (1)	$	39,~~200~~152		$	54,~~614~~406
Non-cash investing and financing activities:
Asset retirement obligations associated with properties sold	$	(15,708	)	$	(809	)
Asset retirement obligation costs and liabilities	$	39		$	—
Asset retirement obligations associated with properties sold	$	(16,107	)	$	(5,650	)
Asset retirement obligations associated with property acquisitions	$	156		$	—
Note receivable received in exchange for sale of oil and natural gas properties	$	—		$	748
Units issued in exchange for Standstill Agreement	$	5,928		$	—
Change in accrued capital expenditures	$	~~(12~~25,~~503~~733	)	$	—

See accompanying notes to condensed consolidated financial statements.

(1) Inclusive of $3.2 million ~~and $3.8 million~~ of restricted cash ~~for~~as ~~March~~of 31June 30, 2018 and 2017~~, respectively~~. See "—Footnote 1—Summary of Significant Accounting Policies" for further discussion.

Page 10

LEGACY RESERVES LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


(1)	Summary of Significant Accounting Policies


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

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

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of ~~March~~June 3130, 2018 and for the three and six months ended ~~March~~June 3130, 2018 and 2017 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, 2017.

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 0.02% general partner interest in LRLP.

Significant information regarding rights of unitholders includes the following:

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

•No limited partner shall have any management power over LRLP’s business and affairs; the general partner shall conduct, direct and manage LRLP’s activities.

•The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRGPLLC and its affiliates, provided that a unit majority has elected a successor general partner.

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

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

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

(b) Recent Developments

On March 26, 2018, the Partnership announced its intent to consummate a transaction, pursuant to an agreement and plan of merger (the "Initial Merger Agreement"), that would result in the Partnership and LRGPLLC becoming subsidiaries of a newly formed Delaware corporation, Legacy Reserves Inc. (“New Legacy”), and the Partnership’s unitholders and preferred unitholders becoming common stockholders of New Legacy (such Transaction referred to herein collectively as the “Corporate Reorganization”). Upon the consummation of the Corporate Reorganization:

• New Legacy, which is currently a wholly owned subsidiary of LRGPLLC, will acquire all of the issued and outstanding limited liability company interests in LRGPLLC and will become the sole member of LRGPLLC; and

Page 11

• ~~the~~New ~~Partnership will merge with~~ Legacy ~~Reserves Merger Sub LLC~~, awhich ~~Delaware~~is ~~limited~~currently ~~liability company and~~ a wholly owned subsidiary of ~~New Legacy~~LRGPLLC, ~~with~~will ~~the~~acquire ~~Partnership~~all ~~continuing~~of as the ~~surviving~~issued ~~entity~~ and asoutstanding ~~a subsidiary of New Legacy (the “Merger”), the~~ limited ~~partner~~liability company interests ~~of the Partnership other than the incentive distribution units~~ in ~~the~~LRGPLLC ~~Partnership~~and ~~being~~will ~~exchanged~~become ~~for New Legacy common stock and~~ the ~~general~~sole ~~partner~~member ~~interest~~of ~~remaining~~LRGPLLC; ~~outstanding.~~and

~~Legacy's~~• ~~Revolving~~the ~~Credit~~Partnership ~~Agreement~~will ismerge ~~classified~~with asLegacy aReserves ~~long-term~~Merger ~~liability~~Sub ~~as of March 31~~LLC, ~~2018; however, it became~~ a ~~current~~Delaware limited liability ascompany ~~of April 1, 2018 as the credit facility matures on April 1, 2019. Legacy expects to refinance or extend the maturity of this obligation prior to its expiration date~~ and ~~Legacy~~a ~~believes~~wholly ~~that~~owned ~~the~~subsidiary ~~consummation~~ of ~~the~~New ~~Corporate Reorganization will improve its ability to do so; however, there is no assurance that~~ Legacy ~~will~~("Merger ~~be able to execute this refinancing or extension or~~Sub"), ifwith ~~Legacy~~the isPartnership ~~able~~continuing toas ~~refinance or extend this obligation, that~~ the ~~terms~~surviving ofentity ~~such~~and ~~refinancing or extension would be~~ as ~~favorable~~a assubsidiary ~~the terms~~ of New Legacy's ~~existing Revolving Credit Agreement. If~~ (the ~~Corporate Reorganization is not consummated~~“Merger”), ~~Legacy~~the ~~believes~~limited ~~its~~partner ~~ability~~interests ~~to refinance or extend the maturity~~ of the ~~Revolving~~Partnership ~~Credit~~other ~~Agreement~~than ~~will be limited. Legacy anticipates that~~ the ~~Corporate~~incentive ~~Reorganization~~distribution ~~will~~units ~~close~~ in the ~~middle~~Partnership ofbeing ~~2018,~~exchanged ~~but~~for ~~there~~New isLegacy nocommon ~~assurance~~stock ofand ~~any~~the ~~timing,~~general ifpartner atinterest ~~all~~remaining outstanding.

On June 22, 2018, the Partnership, New Legacy, LRGPLLC and the plaintiff in a consolidated class action challenging the Merger that was filed in the Court of Chancery of the State of Delaware (the “Court”) reached an agreement in principal to settle the consolidated action. The parties submitted a stipulation and agreement of settlement (the “Settlement Agreement”) to the Court on July 6, 2018. The Court has entered a scheduling order setting September 12, 2018 as the date for a hearing for consideration of the Settlement Agreement. See Note 7 and Note 14 for further discussion of the Settlement Agreement. The Settlement Agreement, if approved by the Court, will grant holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in New Legacy in addition to the approximately 16,913,592 shares those holders would collectively receive pursuant to the exchange ratios that were included in the Initial Merger Agreement.

On July 9, 2018, New Legacy, the Partnership, LRGPLLC and Merger Sub entered into an Amended and Restated Agreement and Plan of Merger (the “A&R Merger Agreement”). The A&R Merger Agreement amends the Initial Merger Agreement to provide, among other things, that (i) with respect to the 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of the Partnership (the “Series A Preferred Units”), each Series A Preferred Unit will be converted into the right to receive 2.92033118 shares of common stock in New Legacy, (ii) with respect to the 8% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of the Partnership (the “Series B Preferred Units”), each Series B Preferred Unit will be converted into the right to receive 2.90650421 shares of common stock in New Legacy, (iii) for the purposes of clarification, phantom units that settle in units representing limited partner interests in the Partnership are included in the definition of “Restricted Unit”, and (iv) the board of directors of LRGPLLC shall take all necessary actions to allow the Partnership’s unitholders to vote at a special meeting of the unitholders (the “Special Meeting”) on a proposal to approve the classification of the board of directors of New Legacy, to be in effect following the closing of the A&R Merger Agreement (the “Classified Board Proposal”).

As of June 30, 2018, Legacy’s ratio of consolidated current assets to consolidated current liabilities was less than 1.0 to 1.0, in violation of a covenant contained in the Current Credit Agreement. On July 31, 2018, Legacy received a waiver with respect to compliance with such covenant for the fiscal quarter ended June 30, 2018. Except with respect to compliance with the financial covenant that has been waived, as of June 30, 2018, Legacy was in compliance with all financial and other covenants of the Current Credit Agreement.

Legacy's Revolving Credit Agreement became a current liability as of April 1, 2018 as the credit facility matures on April 1, 2019. Legacy expects to refinance or extend the maturity of this obligation prior to its expiration date and Legacy believes that the consummation of the Corporate Reorganization will improve its ability to do so; however, there is no assurance that Legacy will be able to execute this refinancing or extension or, if Legacy is able to refinance or extend this obligation, that the terms of such refinancing or extension would be as favorable as the terms of Legacy's existing Revolving Credit Agreement. If the Corporate Reorganization is not consummated, Legacy believes its ability to refinance or extend the maturity of the Revolving Credit Agreement will be limited. Legacy anticipates that the Corporate Reorganization will close in September of 2018, but there is no assurance of any timing, if at all.

Page 12

Below are the components of accrued oil and natural gas liabilities as of ~~March~~June 3130, 2018 and December 31, 2017:

	March 31, 2018		December 31, 2017
	June 30, 2018		December 31, 2017
	(In thousands)
Revenue payable to joint interest owners	$	21,052	$	18,510
Accrued capital expenditures	$	58,931	$	33,198
Accrued lease operating expense	1718,~~693~~493		18,179
Accrued capital expenditures	20,695		33,198
Revenue payable to joint interest owners	26,831		18,510
Accrued ad valorem tax	78,~~249~~956		5,807
Other	5,~~913~~875		5,624
	$	72119,~~602~~086	$	81,318

(d) Restricted Cash

Restricted cash on our Consolidated Balance Sheet as of ~~March~~June 3130, 2018 and December 31, 2017 is $3.2 million ~~and $3.2 million, respectively,~~ in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. Legacy adopted Accounting Standards Update ("ASU") No. 2016-18, "Restricted Cash" as of January 1, 2018.

(e) Recent Accounting Pronouncements

In February 2016, the FASB issued ASU No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is currently required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the consolidated financial statements, with certain practical expedients available. ~~Legacy is currently evaluating the impact of its pending adoption of ASU 2016-02 on our consolidated financial statements.~~

~~Page~~In 12January 2018, the FASB issued an Exposure Draft titled “Leases (Topic 842): Targeted Improvements,” which includes a proposed amendment to ASU 2016-02 allowing entities an additional transition method to the existing requirements. Under this additional transition method, an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption.

~~(2)~~Legacy ~~Long~~is currently evaluating the impact of its pending adoption of ASU 2016-~~Term~~02 on ~~Debt~~its consolidated financial statements. Legacy's ASU 2016-02 implementation approach includes educating key stakeholders within the organization, analyzing systems reports to identify the types and volume of contracts that may meet the definition of a lease under ASU 2016-02 and performing a detailed review of material contracts identified through that analysis. Based on the results obtained, Legacy will assess what impacts ASU 2016-02 could have on its financial statements and disclosures, existing accounting policies and internal controls, as well as whether a financial lease accounting system solution will need to be implemented to comply.

~~Long-term~~Legacy ~~debt~~is ~~consists~~also ofin the ~~following~~process as of ~~March 31,~~evaluating ~~2018~~ASU 2016-02’s currently available and ~~December 31,~~proposed ~~2017:~~practical expedients upon transition.

	March 31,			December 31,
	2018			2017
	(In thousands)
Credit Facility due 2019	$	518,000		$	499,000
Second Lien Term Loans due 2020	338,626			205,000
8% Senior Notes due 2020	232,989			232,989
6.625% Senior Notes due 2021	245,579			432,656
	1,335,194			1,369,645
Unamortized discount on Second Lien Term Loans and Senior Notes	(12,946		)	(13,101		)
Unamortized debt issuance costs	(25,295		)	(9,775		)
Total Long-Term Debt, net	$	1,296,953		$	1,346,769

Page 13


(2)	Debt

Debt consists of the following as of June 30, 2018 and December 31, 2017:



	June 30,			December 31,
	2018			2017
	(In thousands)
Current debt
Credit Facility due 2019	$	508,000		$	—
Unamortized debt issuance costs	(2,778		)	—
Total current debt, net	505,222			—

Long-term debt
Credit Facility due 2019	—			499,000
Second Lien Term Loans due 2020	338,626			205,000
8% Senior Notes due 2020	232,989			232,989
6.625% Senior Notes due 2021	245,579			432,656
	817,194			1,369,645
Unamortized discount on Second Lien Term Loans and Senior Notes	(12,228		)	(13,101		)
Unamortized debt issuance costs	(20,213		)	(9,775		)
Total long-term debt, net	$	784,753		$	1,346,769
Total debt, net	$	1,289,975		$	1,346,769

Credit Facility

On April 1, 2014, Legacy entered into a five-year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, Compass Bank, as syndication agent, UBS Securities LLC and U.S. Bank National Association, as co-documentation agents and the lenders party thereto (as amended, the “Current Credit Agreement”). Borrowings under the Current Credit Agreement mature on April 1, 2019. Legacy's obligations under the Current Credit Agreement are secured by mortgages on over 95% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries. The amount available for borrowing at any one time is limited to the borrowing base and contains a $2 million sub-limit for letters of credit. The borrowing base was reaffirmed at $575 million as part of the spring 2018 redetermination. The borrowing base is subject to semi-annual redeterminations on or about April 1 and October 1 of each year with the next redetermination scheduled for October 2018. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. Legacy also has the right, once during each calendar year, to request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement so long as it does not increase the borrowing base then in effect. The Current Credit Agreement contains a covenant that prohibits Legacy from paying distributions to its limited partners, including holders of its preferred units, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than 4.00 to 1.00 or (ii) Legacy has unused lender commitments of not less than 15% of the total lender commitments then in effect.

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


•	as of any day, first lien debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to not be greater than 2.50 to 1.00;

Page 14


•	as of the last day of any fiscal quarter, secured debt to EBITDA as of the last day of any fiscal quarter for the four fiscal quarters then ending of not more than 4.5 to 1.0, beginning with the fiscal quarter ending on December 31, 2018;


•	as of the last day of any fiscal quarter, total EBITDA over the last four quarters to total interest expense over the last four quarters to be greater than 2.0 to 1.0;

• 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 FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives; and

Page 13

excluding non-cash assets and liabilities under FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives; and

•

as of the last day of any fiscal quarter, the ratio of (a) the sum of (i) the net present value using NYMEX forward pricing, discounted at 10 percent per annum, of Legacy’s proved developed producing oil and gas properties as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be (giving pro forma effect to material acquisitions or dispositions since the date of such reports) (“PDP PV-10”), (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents, in each case as of such date to (b) Secured Debt as of such day to be equal to or less than 1.00 to 1.00.

On March 23, 2018, the Partnership entered into an amendment to the Current Credit Agreement (the “Current Credit Agreement Amendment”). The Current Credit Agreement Amendment, subject to certain conditions, among which is the consummation of the Corporate Reorganization, amends certain provisions set forth in the Current Credit Agreement to, among other items:


•	permit the Corporate Reorganization and modify certain provisions to reflect the new corporate structure;

• provide that New Legacy and ~~the~~LRGPLLC ~~General Partner~~ will guarantee the debt outstanding under the Current Credit Agreement;


•	provide that the Partnership may make unlimited restricted payments, subject to no default or event of default, pro forma availability under the Current Credit Agreement of at least 20%, and pro forma total leverage of not more than 3.00 to 1.00, as well as to pay taxes and ordinary course overhead expenses of New Legacy;


•	waive any “Change in Control” (as defined in the Current Credit Agreement) triggered by the Corporate Reorganization; and


•	permit redemptions of the 2020 Senior Notes, 2021 Senior Notes and loans under the Second Lien Term Loan Credit Agreement (as defined below) with the cash proceeds from the sale of equity interests (or exchanges for equity interests) of New Legacy.

All capitalized terms not defined in the foregoing description have the meaning assigned to them in the Current Credit Agreement Amendment.

As of ~~March~~ June 30, 2018, Legacy’s ratio of consolidated current assets to consolidated current liabilities was less than 1.0 to 1.0, in violation of a covenant contained in the Current Credit Agreement. On July 31, 2018, Legacy received a waiver with respect to compliance with such covenant for the fiscal quarter ended June 30, 2018. Except with respect to compliance with the financial covenant that has been waived, as of June 30, 2018, Legacy was in compliance with all financial and other covenants of the Current Credit Agreement. Depending on future oil and natural gas prices, Legacy could breach certain financial covenants under its Current Credit Agreement, which would constitute a default under its Current Credit Agreement. Such default, if not remedied, would require a waiver from Legacy's lenders in order for it to avoid an event of default and, subject to certain limitations, subsequent acceleration of all amounts outstanding under its Current Credit Agreement and potential foreclosure on its oil and natural gas properties. If the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under its Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of its other outstanding indebtedness, including its Second Lien Term Loans (as defined below), its 8% Senior Notes due 2020 (the "2020 Senior Notes") and its 6.625% Senior Notes due 2021 (the "2021 Senior Notes" and, together with the 2020 Senior Notes, the “Senior Notes”), and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, Legacy believes the long-term global outlook for commodity prices and its efforts to date will be viewed positively by its lenders. The Current Credit Agreement contains a covenant that currently prohibits us from paying distributions to our limited partners, including holders of our preferred units.

AsPage of March 31, 2018, Legacy had approximately $518.0 million drawn under the Current Credit Agreement at a weighted-average interest rate of 4.68%, leaving approximately $56.2 million of availability under the Current Credit Agreement. For the three-month period ended March 31, 2018, Legacy paid in cash $6.2 million of interest expense on the Current Credit Agreement.15

As of June 30, 2018, Legacy had approximately $508 million drawn under the Current Credit Agreement at a weighted-average interest rate of 4.76%, leaving approximately $66.2 million of availability under the Current Credit Agreement. For the six-month period ended June 30, 2018, Legacy paid in cash $12.7 million of interest expense on the Current Credit Agreement.

Second Lien Term Loan Credit Agreement

On October 25, 2016, Legacy entered into a Term Loan Credit Agreement (as amended, the “Second Lien Term Loan Credit Agreement”) among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, providing for term loans up to an aggregate principal amount of $300.0 million (the “Second Lien Term Loans”). The Second Lien Term Loans under the Second Lien Term Loan Credit Agreement are issued with an upfront fee of 2% and bear interest at a rate of 12.00% per annum payable quarterly in cash or, prior to the 18 month anniversary of the Second Lien Term Loan Credit Agreement, Legacy may elect to pay in kind up to 50% of the interest payable. GSO Capital Partners L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Second Lien Term Loan Credit Agreement matures on August 31, 2021; provided that, if on July 1, 2020, Legacy has greater than or equal to a face amount of $15.0 million of Senior Notes that were outstanding on the date the Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Term Loan Credit Agreement will mature on August 1, 2020. The Second Lien Term Loans are secured on a second lien priority basis by the same collateral that secures Legacy's Current Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that are guarantors under the Current Credit Agreement. As of June 30, 2018, Legacy had approximately $338.6 million drawn under the Second Lien Term Loan Credit Agreement. On December 31, 2017, Legacy entered into the Third Amendment to the Second Lien Term Loan Credit Agreement (the "Third Amendment") among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, including GSO and certain funds and accounts managed, advised or sub-advised by GSO, which, among other things, increased the maximum amount available for borrowing under the Second Lien Term Loans to $400.0 million, extended the availability of undrawn principal ($61.4 million of availability as of June 30, 2018) to October 25, 2019 and relaxed the asset coverage ratio to 0.85 to 1.00 until the fiscal quarter ended December 31, 2018. The Third Amendment became effective on January 5, 2018. The Second Lien Term Loan Credit Agreement contains a covenant that prohibits Legacy from paying distributions to its limited partners, including holders of its preferred units, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than 4.00 to 1.00 or (ii) Legacy has unused lender commitments of not less than 15% of the total lender commitments then in effect.

Page 14

Partners L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Second Lien Term Loan Credit Agreement matures on August 31, 2021; provided that, if on July 1, 2020, Legacy has greater than or equal to a face amount of $15.0 million of Senior Notes that were outstanding on the date the Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Term Loan Credit Agreement will mature on August 1, 2020. The Second Lien Term Loans are secured on a second lien priority basis by the same collateral that secures Legacy's Current Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that are guarantors under the Current Credit Agreement. As of March 31, 2018, Legacy had approximately $338.6 million drawn under the Second Lien Term Loan Credit Agreement. On December 31, 2017, Legacy entered into the Third Amendment to the Second Lien Term Loan Credit Agreement (the "Third Amendment") among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, including GSO and certain funds and accounts managed, advised or sub-advised by GSO, which, among other things, increased the maximum amount available for borrowing under the Second Lien Term Loans to $400.0 million, extended the availability of undrawn principal ($61.4 million of availability as of March 31, 2018) to October 25, 2019 and relaxed the asset coverage ratio to 0.85 to 1.00 until the fiscal quarter ended December 31, 2018. The Third Amendment became effective on January 5, 2018. The Second Lien Term Loan Credit Agreement contains a covenant that prohibits Legacy from paying distributions to its limited partners, including holders of its preferred units, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than 4.00 to 1.00 or (ii) Legacy has unused lender commitments of not less than 15% of the total lender commitments then in effect.

The Second Lien Term Loan Credit Agreement also contains covenants that, among other things, requires Legacy to:


•	not permit, as of the last day of any fiscal quarter, the ratio of the sum of (i) the net present value using NYMEX forward pricing of Legacy’s PDP PV-10, (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents to Secured Debt to be less than 0.85 to 1.00 until the fiscal quarter ended December 31, 2018 and 1.00 to 1.00 thereafter; and


•	not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, Legacy’s ratio of Secured Debt as of such day to EBITDA for the four fiscal quarters then ending to be greater than 4.50 to 1.00.

On March 23, 2018, the Partnership entered into the Fourth Amendment to the Second Lien Term Loan Credit Agreement (the “Term Loan Amendment”). The Term Loan Amendment, subject to certain conditions, among which is the consummation of the Corporate Reorganization, amends certain provisions set forth in the Second Lien Term Loan Credit Agreement to, among other items:


•	permit the Corporate Reorganization and modify certain provisions to reflect the new corporate structure;

• provide that New Legacy and ~~the~~LRGPLLC ~~General Partner~~ will guarantee the debt outstanding under the Second Lien Term Loan Credit Agreement;


•	provide that the Partnership may make unlimited restricted payments, subject to no default or event of default, pro forma availability under the Second Lien Term Loan Credit Agreement of at least 20%, and pro forma total leverage of not more than 3.00 to 1.00, as well as to pay taxes and ordinary course overhead expenses of New Legacy;


•	waive any “Change in Control” (as defined in the Second Lien Term Loan Credit Agreement) triggered by the Corporate Reorganization;

Page 16


•	waive any requirement to prepay the Term Loans using the Partnership’s Free Cash Flow or limit Capital Expenditures (each as defined in the Second Lien Term Loan Credit Agreement) prior to March 31, 2019; and


•	permit redemptions of the 2020 Senior Notes and the 2021 Senior Notes with the cash proceeds from the sale of equity interests (or exchanges for equity interests) of New Legacy.

All capitalized terms used but not defined in the foregoing description have the meaning assigned to them in the Second Lien Term Loan Credit Agreement.

In connection with the Second Lien Term Loan Credit Agreement, a customary intercreditor agreement was entered into by Wells Fargo Bank National Association, as priority lien agent, and Cortland Capital Markets Services LLC, as junior lien agent, and acknowledged and accepted by Legacy and the subsidiary guarantors.

~~Page~~As 15of June 30, 2018, Legacy was in compliance with all financial and other covenants of the Second Lien Term Loan Credit Agreement.

As of March 31, 2018, Legacy was in compliance with all financial and other covenants of the Second Lien Term Loan Credit Agreement.

8% Senior Notes Due 2020 ("2020 Senior Notes")

On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of its 2020 Senior Notes, which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par.

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



Year	Percentage
2017	102.000	%
2018 and thereafter	100.000	%

Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture as supplemented. Legacy's and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other, debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to "—Footnote 1213—Subsidiary Guarantors" for further details on Legacy's guarantors.

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

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grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. The indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the 2020 Senior Notes. However, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2020 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness.

On April 2, 2018, following receipt of the requisite consents of the holders of the 2020 Senior Notes, the Partnership entered into the Second Supplemental Indenture (the “2020 Notes Supplemental Indenture”), to the 2020 Notes Indenture. Pursuant to the 2020 Notes Supplemental Indenture, the 2020 Notes Indenture was amended to, among other things, (i) exclude the Corporate Reorganization from the definition of “Change of Control” in the 2020 Notes Indenture, (ii) permit the Corporate Reorganization, (iii) provide for the issuance of an unconditional and irrevocable guarantee of the 2020 Senior Notes by New Legacy and LRGPLLC, (iv) provide that certain covenants and other provisions under the 2020 Notes Indenture previously applicable to the Partnership and its restricted subsidiaries will apply to New Legacy and its restricted subsidiaries, (v) make certain changes to the restricted payments covenant to reflect that the Partnership will no longer be a publicly traded master limited partnership following the Corporate Reorganization and (vi) effect certain other conforming changes.

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

During the fiscal year ended December 31, 2016, Legacy repurchased a face amount of $52.0 million of its 2020 Senior Notes on the open market.

Page 16

On June 1, 2016, Legacy exchanged 2,719,124 units representing limited partner interests in the Partnership for $15.0 million of face amount of its outstanding 2020 Senior Notes.

See "—Footnote 13—Subsequent Events" for further discussion of the 2020 Senior Notes.

6.625% Senior Notes Due 2021 ("2021 Senior Notes")

On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of its 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par.

On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of the 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on February 10, 2015. These 2021 Senior Notes were issued at 99.0% of par.

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

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

Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture, as supplemented. The Partnership is in compliance with all financial and other covenants of the 2021 Senior Notes. However, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2021 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness.

On April 2, 2018, following receipt of the requisite consents of the holders of the 2021 Senior Notes, the Partnership entered into the Second Supplemental Indenture (the “2021 Notes Supplemental Indenture”) to the initial indenture governing the 2021 Notes (the "2021 Notes Indenture").

Page 18

Pursuant to the 2021 Notes Supplemental Indenture, the 2021 Notes Indenture was amended to, among other things, (i) exclude the Corporate Reorganization from the definition of “Change of Control” in the 2021 Notes Indenture, (ii) permit the Corporate Reorganization, (iii) provide for the issuance of an unconditional and irrevocable guarantee of the 2021 Senior Notes by New Legacy and LRGPLLC, (iv) provide that certain covenants and other provisions under the 2021 Notes Indenture previously applicable to the Partnership and its restricted subsidiaries will apply to New Legacy and its restricted subsidiaries, (v) make certain changes to the restricted payments covenant to reflect that the Partnership will no longer be a publicly traded master limited partnership following the Corporate Reorganization and (vi) effect certain other conforming changes.

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

During the fiscal year ended December 31, 2016, Legacy repurchased a face amount of $117.3 million of its 2021 Senior Notes on the open market.

On December 31, 2017, Legacy entered into a definitive agreement with certain funds managed by Fir Tree Partners ("Fir Tree") pursuant to which Legacy acquired $187.0 million of the 6.625% Notes for a price of approximately $132 million inclusive of accrued but unpaid interest with a settlement date of January 5, 2018. Legacy treated these repurchases for accounting purposes as an extinguishment of debt. Accordingly, Legacy recognized a gain of $51.7 million for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.

See "—Footnote 13—Subsequent Events" for further discussion of the 2021 Senior Notes.


(3)	Impact of ASC 606 Adoption

On January 1, 2018, Legacy adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition applied to all contracts. ASU 2014-09 created ASC 606 - Revenue from Contracts with Customers ("ASC 606"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP and includes a five step process to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services.

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The impact of adoption on Legacy's current period results is as follows (in thousands):

	Three months ended March 31, 2018
	Three Months Ended June 30, 2018									Six Months Ended June 30, 2018
	Under ASC 606			Under ASC 605			Change			Under ASC 606			Under ASC 605			Change
	(In thousands)
Revenues:
Oil Sales	$	9399,~~411~~799		$	9399,~~443~~936		$	(32137	)	$	193,210		$	193,379		$	(169	)
Natural gas liquids (NGL) sales	75,~~396~~735			75,~~545~~898			(~~149~~163		)	13,131			13,443			(312		)
Natural gas sales	3633,~~672~~747			3835,~~133~~452			(1,~~461~~705		)	70,419			73,585			(3,166		)
	$	~~137~~139,~~479~~281		$	~~139~~141,~~121~~286		$	(12,~~642~~005	)	$	276,760		$	280,407		$	(3,647	)
Costs and expenses:
Oil and natural gas production	$	4749,~~967~~431		$	4951,~~609~~436		$	(12,~~642~~005	)	$	97,398		$	101,045		$	(3,647	)
Net income	$	64,382		$	64,382		$	—
Net income (loss)	$	(50,709	)	$	(50,709	)	$	—		$	13,673		$	13,673		$	—
Partners' deficit, as of January 1, 2018	$	(271,687	)	$	(271,687	)	$	—		$	(271,687	)	$	(271,687	)	$	—

The change to oil sales and a related change to oil production expense are due to the conclusion that Legacy transfers control of oil production to purchasers at or near the wellhead. As such, certain transportation expenses that are deducted from the sales price Legacy receives from the purchaser are presented net in revenue in accordance with ASC 606. This represents a change from Legacy's prior practice under ASC 605 of presenting those transportation costs gross as an oil and natural gas production expense.

The change to natural gas and NGL sales and the related change to natural gas production expense are due to the conclusion that Legacy represents an agent in certain gas processing agreements with midstream entities in accordance with the control model in ASC 606. This represents a change from Legacy's previous conclusion utilizing the principal versus agent indicators under ASC 605 that Legacy acted as the principal in those arrangements. As a result, Legacy is required to present certain gathering and processing expenses net in natural gas and NGL sales under ASC 606.

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(4)	Revenue from Contracts with Customers

Oil, NGL and natural gas sales revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. This generally occurs when oil or natural gas has been delivered to a pipeline or ~~a tank lifting has occurred~~truck. A more detailed summary of the sale of each product type is included below.

Oil Sales

Legacy's oil sales contracts are generally structured such that Legacy sells its oil production to the purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality and physical location. Legacy recognizes revenue when control transfers to the purchaser upon delivery at the net price received from purchaser.

NGL and Natural Gas Sales

Under Legacy's gas processing contracts, Legacy delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to Legacy for the resulting sales of NGLs and residue gas. In these scenarios, Legacy evaluates whether it is the principal or the agent in the transaction. In virtually all of Legacy's gas processing contracts, Legacy has concluded that it is the agent, and the midstream processing entity is Legacy's customer. Accordingly, Legacy recognizes revenue upon delivery based on the net amount of the proceeds received from the midstream processing entity. Proceeds are generally tied to the prevailing index prices for residue gas and NGLs less deductions for gathering, processing, transportation and other expenses.

Under Legacy's dry gas sales that do not require processing, Legacy sells its natural gas production to third party purchasers at a contractually specified delivery point at or near the wellhead. Pricing provisions are tied to a market index, with certain deductions based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. Legacy recognizes revenue upon delivery of the natural gas to third party purchasers based on the relevant index price net of deductions.

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natural gas supplies. Legacy recognizes revenue upon delivery of the natural gas to third party purchasers based on the relevant index price net of deductions.

Imbalances

Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2017 and 2016.

Disaggregation of Revenue

Legacy has identified three material revenue streams in its business: oil sales, NGL sales, and natural gas sales. Revenue attributable to each of Legacy's identified revenue streams is disaggregated in the table below.

	Three Months Ended		Six Months Ended
	March 31,
	June 30,
	2018		2018
	(In thousands)
Revenues:
Oil sales	$	9399,~~411~~799	$	193,210
Natural gas liquids (NGL) sales	75,~~396~~735		13,131
Natural gas sales	3633,~~672~~747		70,419
Total revenues	~~137~~139,~~479~~281		276,760

Page 20

Significant Judgments

Principal versus agent

Legacy engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on Legacy's behalf, such as Legacy's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether Legacy is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction price allocated to remaining performance obligations

A significant number of Legacy's product sales are short-term in nature with a contract term of one year or less. For those contracts, Legacy has utilized the practical expedient in ASC 606 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For Legacy's product sales that have a contract term greater than one year, Legacy has utilized the practical expedient in ASC 606 that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under Legacy's product sales contracts, it is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional, and record invoiced amounts as “Accounts receivable - oil and natural gas” in its consolidated balance sheet.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. In this scenario, payment is also unconditional, as Legacy has satisfied its performance obligations through delivery of the relevant product. As a result, Legacy has concluded that its product sales do not give rise to contract assets or liabilities under ASC 606.

Page 19

is also unconditional, as Legacy has satisfied its performance obligations through delivery of the relevant product. As a result, Legacy has concluded that its product sales do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

Legacy records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, Legacy is required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated.

Legacy records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Legacy has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended ~~March~~June 3130, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.


(5)	Asset Acquisition and Dispositions

On August 1, 2017, Legacy made a payment in the amount of $141 million (the “Acceleration Payment”) in connection with its First Amended and Restated Development Agreement (the “Restated Agreement”) with Jupiter JV, LP (“Jupiter”). The Acceleration Payment caused the reversion to Legacy of additional working interests in all wells and associated personal property and infrastructure (collectively, the “Wells”) and all undeveloped assets subject to the Restated Agreement. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties.

~~During~~Page the three months ended March 31, 2018, Legacy divested certain individually immaterial oil and natural gas assets for net cash proceeds of $27.1 million. These dispositions were treated as asset sales and resulted in a gain on disposition of assets of $20.4 million during the period.21

~~(6)~~During ~~Commitments~~the six months ended June 30, 2018, Legacy divested certain individually immaterial oil and ~~Contingencies~~natural gas assets for net cash proceeds of $29.2 million. These dispositions were treated as asset sales and resulted in a gain on disposition of assets of $21.5 million during the period.

~~On March 28, 2018, a purported holder of the Partnership’s Preferred Units filed a putative class action challenging the Merger against the Partnership, LRGPLLC and New Legacy~~ (~~the “Doppelt Action”~~6). ~~The~~Related ~~Doppelt~~Party Action contains two causes of action challenging the Merger, including breach of the Fifth Amended and Restated Agreement of Limited Partnership of the Partnership (the "Partnership Agreement") and breach of the implied covenant of good faith and fair dealing. The plaintiff in the Doppelt Action seeks injunctive relief prohibiting consummation of the Merger or, in the event the Merger is consummated, rescission or rescissory damages, as well as reasonable attorneys’ and experts’ fees and expenses. Additionally, on April 4, 2018, a motion to expedite was filed in connection with the Doppelt Action, by which the plaintiff sought a hearing on a motion for a preliminary injunction prior to the close of the Merger and requested that the court set an expedited discovery schedule prior to any such hearing. The plaintiff in the Doppelt Action also filed a lawsuit against the Partnership and the Partnership GP in 2017 for breach of the Partnership Agreement based on the treatment of the accrued but unpaid preferred distributions as “guaranteed payments” for tax purposes. A second putative class action lawsuit challenging the Merger was filed on April 3, 2018 against the Partnership, the LRGPLLC and New Legacy (the “Chammah Ventures Action”). The Chammah Ventures Action contains the same causes of action and that plaintiff seeks substantially the same relief as the plaintiff in the Doppelt Action. On April 13, 2018, the Court issued an order consolidating the Doppelt and Chammah actions and appointing Plaintiff Doppelt as lead plaintiff and his counsel as lead counsel for the putative class action. On April 13, 2018, the Court also granted the motion to expedite the consolidated action. On April 23, 2018 Plaintiff Doppelt filed an Amended Complaint, adding an additional count for breach of the Partnership Agreement. A hearing on Plaintiff's motion for a preliminary injunction and Legacy's motion to dismiss has been set for June 4, 2018.Transactions

Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which Cary D. Brown and Dale A. Brown, both directors of Legacy, are principals. Legacy has contracted with Blue Quail to provide water transfer services and paid $120,241 and $9,758 in the six month periods ended June 30, 2018 and 2017, respectively, to Blue Quail for such services. Blue Quail charged Legacy prices consistent with that of other vendors for services rendered.


(7)	Commitments and Contingencies

On March 28, 2018, a purported holder of the Partnership’s Preferred Units filed a putative class action challenging the Merger against the Partnership, LRGPLLC and New Legacy (the “Doppelt Action”). The Doppelt Action contains two causes of action challenging the Merger, including breach of the Fifth Amended and Restated Agreement of Limited Partnership of the Partnership (the "Partnership Agreement") and breach of the implied covenant of good faith and fair dealing. The plaintiff in the Doppelt Action seeks injunctive relief prohibiting consummation of the Merger or, in the event the Merger is consummated, rescission or rescissory damages, as well as reasonable attorneys’ and experts’ fees and expenses. Additionally, on April 4, 2018, a motion to expedite was filed in connection with the Doppelt Action, by which the plaintiff sought a hearing on a motion for a preliminary injunction prior to the close of the Merger and requested that the court set an expedited discovery schedule prior to any such hearing. The plaintiff in the Doppelt Action also filed a lawsuit against the Partnership and the LRGPLLC in 2017 for breach of the Partnership Agreement based on the treatment of the accrued but unpaid preferred distributions as “guaranteed payments” for tax purposes. A second putative class action lawsuit challenging the Merger was filed on April 3, 2018 against the Partnership, the LRGPLLC and New Legacy (the “Chammah Ventures Action”). The Chammah Ventures Action contains the same causes of action and that plaintiff seeks substantially the same relief as the plaintiff in the Doppelt Action. On April 13, 2018, the Court issued an order consolidating the Doppelt and Chammah actions (together, the "Consolidated Actions") and appointing Plaintiff Doppelt as lead plaintiff and his counsel as lead counsel for the putative class action. On April 13, 2018, the Court also granted the motion to expedite the consolidated action. On April 23, 2018 Plaintiff Doppelt filed an Amended Complaint, adding an additional count for breach of the Partnership Agreement. A hearing on Plaintiff's motion for a preliminary injunction and Legacy's motion to dismiss occurred on June 4, 2018.

On June 22, 2018, the Partnership, New Legacy, LRGPLLC and the plaintiff in the Consolidated Action reached an agreement in principle to settle the Consolidated Action. The parties submitted a Settlement Agreement to the Court on July 6, 2018. The Court has entered a scheduling order setting September 12, 2018 as the date for a hearing for consideration of the Settlement Agreement. See Note 1 and Note 14 for further discussion of the Settlement Agreement.

A third putative class action lawsuit challenging the Merger was filed against the Partnership, LRGPLLC, New Legacy and Merger Sub on April 27, 2018 by Patrick Irish in the District Court in Midland County, Texas (the “Irish Action”). The Irish Action contains the same general causes of action as the initial complaint filed in the Doppelt Action and the Chammah Ventures Action and seeks the same relief. The Partnership, LRGPLLC, New Legacy and the plaintiff’s counsel in the Consolidated Action have agreed to coordinate efforts to obtain a dismissal of the Irish Action following the consummation of the Merger.

The Partnership cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this quarterly report, nor can the Partnership predict the amount of time and expense that will be required to resolve such litigation. The Partnership believes the lawsuits are without merit and intends to vigorously defend against the lawsuits.

Page 20

Legacy’s consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on Legacy cannot be predicted with certainty.

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~~Page has employment agreements and retention bonus agreements with its officers and certain other employees. The employment agreements with its officers 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. The retention bonus agreements provide for fixed bonus amounts to be paid to employees contingent upon various criteria including their continuous employment or a change in control.22

~~(7)~~Legacy ~~Fair~~has ~~Value~~employment ~~Measurements~~agreements with its officers and retention bonus agreements with certain other employees. The employment agreements with its officers 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. The retention bonus agreements provide for fixed bonus amounts to be paid to employees contingent upon various criteria including their continuous employment or a change in control.


(8)	Fair Value Measurements

Fair value is defined as 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. Fair value measurements are classified and disclosed in one of the following categories:



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 collars 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 currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

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.

Page 2123

Fair Value on a Recurring Basis

	Fair Value Measurements at March 31, 2018 Using:
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs		Total Carrying Value as of
Description	(Level 1)		(Level 2)			(Level 3)		March 31, 2018
	(In thousands)
LTIP (a)	$	—	$	(14,007	)	$	—	$	(14,007	)
Oil and natural gas derivatives	—		(2,500		)	9,909		7,409
Interest rate swaps	—		2,983			—		2,983
Total	$	—	$	(13,524	)	$	9,909	$	(3,615	)

The following tables summarize (i) the valuation of each of Legacy’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the financial instruments are subject to netting arrangements and qualify for net presentation in the Legacy’s consolidated balance sheets at June 30, 2018 and December 31, 2017. Legacy nets the fair value of derivative instruments by counterparty in its consolidated balance sheets.

(a) See Note 11 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method.



	June 30, 2018
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Current
Commodity derivatives	$	—	$	12,703		$	30,134	$	42,837		$	(12,703	)	$	30,134
Interest rate derivatives	—		2,300			—		2,300			—			2,300
Noncurrent
Commodity derivatives	—		7,701			1,482		9,183			(4,388		)	4,795
Interest rate derivatives	—		784			—		784			—			784

Liabilities:
Current
Commodity derivatives	—		(44,830		)	—		(44,830		)	12,703			(32,127		)
LTIP liability	—		(25,840		)	—		(25,840		)	—			(25,840		)
Noncurrent
Commodity derivatives	—		(6,682		)	—		(6,682		)	4,388			(2,294		)

Net fair value instruments	$	—	$	(53,864	)	$	31,616	$	(22,248	)	$	—		$	(22,248	)


(a)	See Note 12 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method.

Page 24



	December 31, 2017
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Assets:
Current
Commodity derivatives	$	—	$	19,792		$	—		$	19,792		$	(7,204	)	$	12,588
Interest rate derivatives	—		837			—			837			(1		)	836
Noncurrent
Commodity derivatives	—		14,278			—			14,278			(1,460		)	12,818
Interest rate derivatives	—		1,281			—			1,281						1,281

Liabilities:
Current
Commodity derivatives	—		(21,027		)	(4,191		)	(25,218		)	7,204			(18,014		)
Interest rate derivatives	—		(1		)	—			(1		)	1			—
LTIP liability	—		(1,947		)	—			(1,947		)				(1,947		)
Noncurrent
Commodity derivatives	—		(1,637		)	(897		)	(2,534		)	1,460			(1,074		)

Net fair value instruments	$	—	$	11,576		$	(5,088	)	$	6,488		$	—		$	6,488


(a)	See Note 12 for further discussion on unit-based compensation expenses and the related Long-Term Incentive Plan ("LTIP") liability for certain grants accounted for under the liability method.

Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including three-way collars and enhanced swaps, using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published London interbank offered rates ("LIBOR") and interest rate swaps. Due to the lack of an active market for periods beyond one-month from the balance sheet date for its oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that most of our current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change.

Page 2225

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 EndedMarch 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2018			2017			2018			2017
	(In thousands)
Beginning balance	$	(59,~~088~~909	)	$	81,666		$	(5,088	)	$	8
Total gains	14,060			1,239
Total gains (losses)	26,356			(747		)	40,416			492
Settlements, net	~~937~~(4,649		)	~~419~~(289		)	(3,712		)	130
Ending balance	$	931,~~909~~616		$	~~1,666~~630		$	31,616		$	630
Gains included in earnings relating to derivatives still held as of March 31, 2018 and 2017	$	13,939		$	1,142
Gains (losses) included in earnings relating to derivatives still held as of June 30, 2018 and 2017	$	23,158		$	(631	)	$	34,232		$	89

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

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

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

Fair Value on a Non-Recurring Basis

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; measurements of oil and natural gas property impairments; and the initial recognition of asset retirement obligations ("ARO") for which fair value is used. These ARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of Legacy’s asset retirement obligation is presented in Note 910.

~~The~~Nonrecurring ~~carrying amount of the revolving long-term debt of $518 million as of March 31, 2018 approximates~~ fair value ~~because~~measurements ~~Legacy's~~of ~~current~~proved ~~borrowing~~oil ~~rate~~and ~~does~~natural ~~not~~gas ~~materially~~properties ~~differ~~during ~~from market rates for similar bank borrowings. Legacy has classified~~ the ~~revolving long~~six-~~term~~month ~~debt~~period asended a Level 2 item within the fair value hierarchy. The carrying amount of the second lien term loan debt under Legacy’s Second Lien Term Loan Credit Agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar borrowings. Legacy has classified the Second Lien Term Loans as a Level 2 item within the fair value hierarchy.June ~~As of March 31~~30, 2018, ~~the~~consist ~~fair values~~ of the 2020 Senior Notes and the 2021 Senior Notes were $187.9 million and $186.3 million, respectively. As these valuations are based on unadjusted quoted prices in an active market, the fair values are classified as Level 1 items within the fair value hierarchy.:

Page 23

Fair Value Measurements During the Six Months Ended June 30, 2018 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)

—

26,195

(8a) ~~Derivative~~Legacy ~~Financial~~periodically ~~Instruments~~reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the six-month period ended June 30, 2018, Legacy incurred impairment charges of $35.4 million as oil and natural gas properties with a net cost basis of $61.6 million were written down to their fair value of $26.2 million. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations

Page 26

of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

The carrying amount of the revolving long-term debt of $508 million as of June 30, 2018 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 debt as a Level 2 item within the fair value hierarchy. The carrying amount of the second lien term loan debt under Legacy’s Second Lien Term Loan Credit Agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar borrowings. Legacy has classified the Second Lien Term Loans as a Level 2 item within the fair value hierarchy. As of June 30, 2018, the fair values of the 2020 Senior Notes and the 2021 Senior Notes were $195.1 million and $196.5 million, respectively. As these valuations are based on unadjusted quoted prices in an active market, the fair values are classified as Level 1 items within the fair value hierarchy.


(9)	Derivative Financial Instruments

Commodity derivative transactions

Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes and required no upfront or deferred cash premium paid or payable to our counterparty.

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

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

The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the three and six months ended ~~March~~June 3130, 2018 and 2017:

	Three Months Ended March 31,
	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Beginning fair value of commodity derivatives	$	67,~~318~~409		$	1243,~~698~~131		$	6,318		$	12,698
Total gain (loss) - oil derivatives	(~~742~~7,082		)	157,~~000~~776			(7,824		)	22,776
Total gain (loss) - natural gas derivatives	(~~962~~2,233		)	196,~~669~~740			(3,195		)	26,409
Crude oil derivative cash settlements paid (received)	46,~~894~~309			(3,~~139~~559		)	11,203			(6,698		)
Natural gas derivative cash settlements received	(23,~~099~~895		)	(13,~~097~~012		)	(5,994		)	(4,109		)
Ending fair value of commodity derivatives	$	~~7,409~~508		$	4351,~~131~~076		$	508		$	51,076

Page 2427

~~Certain~~As of ~~our~~June 30, ~~commodity~~2018, ~~derivatives~~Legacy ~~and~~had ~~interest rate derivatives are presented on a net basis on~~ the ~~Consolidated Balance Sheets. The~~ following ~~table~~NYMEX ~~summarizes~~West ~~the~~Texas ~~gross~~Intermediate ~~fair~~("WTI") ~~values~~crude ofoil ~~our~~swaps ~~derivative~~paying ~~instruments,~~floating ~~presenting~~prices ~~the~~and ~~impact~~receiving offixed ~~offsetting~~prices ~~the~~for ~~derivative~~a ~~assets~~portion ~~and~~of ~~liabilities~~its onfuture ~~our~~oil ~~Consolidated~~production ~~Balance Sheets~~ as ~~of the dates~~ indicated below ~~(in thousands)~~:

	March 31, 2018
			Average	Price
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Time Period	Volumes (Bbls)		Price per Bbl	Range per Bbl
Offsetting Derivative Assets:				(In thousands)
July-December 2018	1,527,200		$54.76	$51.20	-	$63.68
Commodity derivatives	$	38,737		$	(12,536	)	$	26,201
2019	2,190,000		$58.88	$57.15	-	$61.20
Interest rate derivatives	2,983			—			2,983
Total derivative assets	$	41,720		$	(12,536	)	$	29,184
Offsetting Derivative Liabilities:
Commodity derivatives	$	(31,328	)	$	12,536		$	(18,792	)
Total derivative liabilities	$	(31,328	)	$	12,536		$	(18,792	)
	December 31, 2017
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets:				(In thousands)
Commodity derivatives	$	34,070		$	(8,664	)	$	25,406
Interest rate derivatives	2,118			(1		)	2,117
Total derivative assets	$	36,188		$	(8,665	)	$	27,523
Offsetting Derivative Liabilities:
Commodity derivatives	$	(27,752	)	$	8,664		$	(19,088	)
Interest rate derivatives	(1		)	1			—
Total derivative liabilities	$	(27,753	)	$	8,665		$	(19,088	)

As of ~~March~~June 3130, 2018, Legacy had the following ~~NYMEX~~Midland-to-Cushing ~~West Texas Intermediate ("WTI")~~ crude oil differential swaps paying a floating ~~prices~~differential and receiving a fixed ~~prices~~differential for a portion of its future oil production as indicated below:

		Average	Price
Time Period	Volumes (Bbls)	Price per Bbl	Range per Bbl
April-December 2018	2,282,500	$54.76	$51.20	-	$63.68
July-December 2018	2,024,000	$(1.13)	$(1.25)	-	$(0.80)
2019	1730,~~095,~~000	$57(1.6715)	$57(1.15)	-	~~$58.69~~

As of ~~March~~June 3130, 2018, Legacy had the following ~~Midland-to-Cushing~~NYMEX WTI crude oil ~~differential~~costless ~~swaps~~collars ~~paying~~that acombine ~~floating differential and receiving~~ a ~~fixed~~long ~~differential~~put ~~for~~with a ~~portion~~short ofcall ~~its future oil production~~ as indicated below:

		Average	Price
		Average Long	Average Short
Time Period	Volumes (Bbls)	Put Price per Bbl	~~Range~~Call Price per Bbl
April-December 2018	3,025,000	$(1.13)	$(1.25)	-	$(0.80)
July-December 2018	782,000	$47.06	$60.29
2019	730,000	$(1.15)	$(1.15)

~~Page~~As 25of June 30, 2018, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and long put with a fixed-price swap as indicated below:

As of March 31, 2018, Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below:



		Average Long	Average Short	Average
Time Period	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Swap Price per Bbl
July-December 2018	64,400	$57.00	$82.00	$90.50

		Average Long	Average Short
Time Period	Volumes (Bbls)	Put Price per Bbl	Call Price per Bbl
April-December 2018	1,168,750	$47.06	$60.29

As of June 30, 2018, Legacy had the following NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:

As of March 31, 2018, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put and long put with a fixed-price swap as indicated below:



		Average	Price
Time Period	Volumes (MMBtu)	Price per MMBtu	Range per MMBtu
July-December 2018	18,160,000	$3.23	$3.04	-	$3.39
2019	25,800,000	$3.36	$3.29	-	$3.39

		Average Long	Average Short	Average
Time Period	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Swap Price per Bbl
April-December 2018	96,250	$57.00	$82.00	$90.50

As of March 31, 2018, Legacy had the following NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:

		Average	Price
Time Period	Volumes (MMBtu)	Price per MMBtu	Range per MMBtu
April-December 2018	27,200,000	$3.23	$3.04	-	$3.39
2019	25,800,000	$3.36	$3.29	-	$3.39

Interest rate derivative transactions

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

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

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

	Three Months Ended March 31,
	2018			2017
	(In thousands)
Beginning fair value of interest rate swaps	$	2,117		$	183
Total gain on interest rate swaps	943			424
Cash settlements (received) paid	(77		)	418
Ending fair value of interest rate swaps	$	2,983		$	1,025

Page 28

Page 26



	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(In thousands)
Beginning fair value of interest rate swaps	$	2,983		$	1,025		$	2,117		$	183
Total gain on interest rate swaps	372			(334		)	1,315			90
Cash settlements (received) paid	(271		)	249			(348		)	667
Ending fair value of interest rate swaps	$	3,084		$	940		$	3,084		$	940

The table below summarizes the interest rate swap position as of ~~March~~June 3130, 2018:

Weighted Average

Estimated Fair Value at

Notional Amount

Fixed Rate

Effective Date

Maturity Date

~~March~~June 3130, 2018

(Dollars in thousands)

235,000

1.363

9/1/2015

9/1/2019

23,~~983~~084

(910) Asset Retirement Obligation

AROs associated with the retirement of a tangible long-lived asset are recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at Legacy’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

The following table reflects the changes in the ARO during the ~~three~~six months ended ~~March~~June 3130, 2018 and year ended December 31, 2017:

	March 31, 2018			December 31, 2017
	June 30, 2018			December 31, 2017
	(In thousands)
Asset retirement obligation - beginning of period	$	274,686		$	272,148
Liabilities incurred with properties acquired	—156			62
Liabilities incurred with properties drilled	—39			39
Liabilities settled during the period	(~~358~~812		)	(1,891		)
Liabilities associated with properties sold	(1516,~~708~~107		)	(8,464		)
Current period accretion	36,~~148~~283			12,792
Asset retirement obligation - end of period	$	~~261~~264,~~768~~245		$	274,686

(1011) Partners' Deficit

Preferred Units

As of ~~March~~June 3130, 2018, 2,300,000 of Legacy's 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series A Preferred Units") were outstanding.

As of ~~March~~June 3130, 2018, 7,200,000 of Legacy's 8.00% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series B Preferred Units" and, together with the Series A Preferred Units, the "Preferred Units") were outstanding

Distributions on the Preferred Units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership's general partner. Distributions on the Series A Preferred Units will be payable from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions on the Series B Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A and 5.26% for Series B, based on the $25.00 liquidation preference per preferred unit.

Page 29

Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A and 5.26% for Series B, based on the $25.00 liquidation preference per preferred unit.

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

Page 27

The Series A Preferred Units and the Series B Preferred Units trade on NASDAQ under the symbols "LGCYP" and "LGCYO,” respectively.

On January 21, 2016, Legacy announced that its general partner suspended monthly cash distributions for both its Series A Preferred Units and its Series B Preferred Units. As of ~~March~~June 3130, 2018, $4.4292 of distributions per unit were in arrears, representing a total cumulative arrearage of approximately $4246.07 million.

Incentive Distribution Units

On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units to WPX Energy Rocky Mountain, LLC (“WPX”) as part of Legacy’s purchase of a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado. The Incentive Distribution Units issued to WPX include 100,000 Incentive Distribution Units that immediately vested along with the ability to vest in up to an additional 200,000 Incentive Distribution Units (the “Unvested IDUs”) in connection with any future asset sales or transactions completed with Legacy pursuant to the terms of the IDR Holders Agreement. Incentive Distribution Units that are not issued to WPX or other parties will remain in Legacy's treasury for the benefit of all limited partners until such time as Legacy may make future issuances of Incentive Distribution Units.

The Incentive Distribution Units represent a right to incremental cash distributions from Legacy after certain target levels of distributions are paid to unitholders, which targets are set above the current levels of Legacy's distributions to unitholders. As of June 4, 2017, all of the Unvested IDUs had been forfeited pursuant to their terms of issuance.

In addition, the vested and outstanding Incentive Distribution Units held by WPX may be converted by Legacy, subject to applicable conversion factors, into units on a one-for-one basis at any time when Legacy has made a distribution in respect of its units for each of the four full fiscal quarters prior to the delivery of its conversion notice, and the amount of the distribution in respect of the units for the full quarter immediately preceding delivery of its conversion notice was equal to at least $0.90 per unit; and the amount of all distributions during each quarter within the four-quarter period immediately preceding delivery of its conversion notice did not exceed the adjusted operating surplus, as defined in Legacy's Partnership Agreement, for such quarter. Further, WPX also has the ability to similarly convert any of its vested Incentive Distribution Units ~~beginning three years after June 4, 2014~~. WPX may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX.

~~Income~~Page ~~per unit~~30

Income (loss) per unit

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

	Three Months Ended						Six Months Ended
	March 31,
	June 30,						June 30,
	2018			2017			2018			2017
	(In thousands)
Net income	$	64,382		$	16,372
Net income (loss)	$	(50,709	)	$	(11,077	)	$	13,673		$	5,295
Distributions to preferred unitholders	(4,750		)	(4,750		)	(9,500		)	(9,500		)
Net income attributable to unitholders	$	59,632		$	11,622
Net income (loss) attributable to unitholders	$	(55,459	)	$	(15,827	)	4,173			(4,205		)
Weighted average number of units outstanding - basic	76,~~350~~725			72,~~103~~354			76,539			72,229
Effect of dilutive securities:
Restricted and phantom units	~~307~~—			—			894			—
Weighted average units and outstanding - diluted	76,657			72,103
Weighted average number of units outstanding - diluted	76,725			72,354			77,433			72,229
Basic and diluted income per unit	$	0.78		$	0.16
Basic & diluted income (loss) per unit	$	(0.72	)	$	(0.22	)	$	0.05		$	(0.06	)

For the three months ended ~~March~~June 3130, 2018, ~~191~~135,~~430~~089 restricted units and 1,~~160,~~424,114 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect. For the six months ended June 30, 2018, 57,625 restricted units and 607,488 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect. For the three and six months ended ~~March~~June 3130, 2017, ~~473~~324,~~647~~604 restricted units and 1,389,773 phantom units were excluded from the calculation of diluted income per unit due to their anti-dilutive effect.

Page 2831

(1112) Unit-Based Compensation

Long-Term Incentive Plan

On March 15, 2006, the LTIP for Legacy was implemented for its employees, consultants and directors, its affiliates and its general partner. On June 12, 2015, the unitholders of Legacy approved an amendment to the LTIP to provide for an increase in the number of units available for issuance from 2,000,000 to 5,000,000. The awards under the LTIP may include unit grants, restricted units, phantom units, unit options and unit appreciation rights ("UARs"). As of ~~March~~June 3130, 2018, grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 3,~~399~~459,~~767~~197 units had been made, comprised of 266,014 unit option awards, 988,~~873~~207 restricted unit awards, 1,424,114 phantom unit awards and ~~720~~780,~~766~~862 unit awards. The UAR awards and certain phantom unit awards granted under the LTIP may only be settled in cash, and therefore are not included in the aggregate number of units granted under the LTIP. The LTIP is administered by the compensation committee (the “Compensation Committee”) of the board of directors of LRGPLLC.

The cost of employee services in exchange for an award of equity instruments is measured based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Because the UARs are settled in cash, Legacy accounts for them by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost is recognized based on the change in the liability between periods.

Unit Appreciation Rights

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

Legacy did not issue UARs to employees during the year ended December 31, 2017 or the ~~three~~six-month period ended ~~March~~June 3130, 2018.

For the ~~three~~six-month periods ended ~~March~~June 3130, 2018 and 2017, Legacy recorded $~~825,811~~1.5 million and $69(0.1) million,~~851,~~ respectively, of compensation (benefit) expense due to the change in liability from December 31, 2017 and 2016, respectively, based on its use of the Black-Scholes model to estimate the ~~March~~June 3130, 2018 and 2017 fair value of these UARs (see Note 7). As of ~~March~~June 3130, 2018, there was a total of approximately $~~93,310~~0.1 million of unrecognized compensation costs related to the unexercised and non-vested portion of these UARs. At ~~March~~June 3130, 2018, this cost was expected to be recognized over a weighted-average period of approximately 0.4522 years. Compensation expense is based upon the fair value as of ~~March~~June 3130, 2018 and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 8792% and employed the Black-Scholes model to estimate the ~~March~~June 3130, 2018 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 5.6%. Legacy will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed no annual distribution.

A summary of UAR activity for the six months ended June 30, 2018 is as follows:

	Units		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2018	722,021		$	20.13	2.99	$	—
Expired and forfeited	(334	)	4.70
Exercised	(2,667	)	4.80
Outstanding at March 31, 2018	721,687		$	20.14	3.05	$	2,955
Expired & Forfeited	(22,167	)	28.21
UARs exercisable at March 31, 2018	599,854		$	23.04	2.76	$	1,555
Outstanding at June 30, 2018	697,187		$	19.93	2.87	$	225,371
UARs exercisable at June 30, 2018	579,853		$	22.81	2.60	$	60,370

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The following table summarizes the status of Legacy’s non-vested UARs since January 1, 2018:

	Non-Vested UARs
	Number of Units		Weighted-Average Exercise Price
Non-vested at January 1, 2018	129,499		$	5.97
Vested	(79,~~332~~988	)	8.1995
Forfeited	(~~334~~2,167	)	45.7066
Non-vested at March 31, 2018	121,833		$	5.84
Non-vested at June 30, 2018	117,344		$	5.72

Legacy has used a weighted-average risk-free interest rate of 2.46% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at ~~March~~June 3130, 2018 whose terms are consistent with the expected life of the UARs. Expected life represents the period of time that UARs are expected to be outstanding and is based on Legacy’s best estimate. The following table represents the weighted-average assumptions used for the Black-Scholes option-pricing model.

	Three Months Ended
	Six Months Ended
	March 31, 2018
	June 30, 2018
Expected life (years)	32.0587
Risk free interest rate	2.46	%
Annual distribution rate per unit	$0.00
Volatility	8791.57	%

Phantom Units

Legacy has also issued phantom units under the LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either one Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy is accounting for the phantom units settled in Partnership units by utilizing the equity method. Legacy is accounting for the phantom units settled in cash by utilizing the liability method.

On February 21, 2017, the Compensation Committee approved the award to Legacy's executive officers of 396,850 subjective, or service-based, phantom units that, upon vesting, settle in units, 793,701 subjective phantom units that, upon vesting, settle in cash and a maximum of 1,587,402 objective, or performance-based, phantom units that, upon vesting, settle in cash. The phantom units settled in units had a grant date fair value of $2.25 per unit.

On February 16, 2018, the Compensation Committee approved the award to Legacy's executive officers of 635,590 subjective, or service-based, phantom units that, upon vesting, settle in units, 317,794 subjective phantom units that, upon vesting, settle in cash and a maximum of 3,813,536 objective, or performance-based, phantom units that, upon vesting, settle in cash. The phantom units had a grant date fair value of $3.69 per unit.

Compensation expense related to the phantom units was $1123.82 million and $1.39 million for the ~~three~~six months ended ~~March~~June 3130, 2018 and 2017, respectively. As of ~~March~~June 3130, 2018, there was a total of $2938.56 million of unrecognized compensation expense remaining. This cost ~~was~~is expected to be recognized over a weighted average period of approximately 2.42 years.

Restricted Units

~~During the year ended December 31, 2017,~~ Legacy did not issue restricted units to any employees. ~~During~~during the ~~three-month~~year ~~period~~ ended ~~March~~December 31, ~~2018,~~2017 ~~Legacy~~or ~~did~~the ~~not~~six-month ~~issue~~period ~~restricted~~ended ~~units~~June 30, ~~to any employees~~2018. Compensation expense related to restricted units was $0.24 million and $01.50 million for the ~~three~~six months ended ~~March~~June 3130, 2018 and 2017, respectively. As of ~~March~~June 3130, 2018, there was a total of $0.64 million of unrecognized compensation expense related to the unvested portion of these restricted units. At ~~March~~June 3130, 2018, this cost was expected to be recognized over a weighted-average period of 1.67 years. Pursuant to the provisions of ASC 718, Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at ~~March~~June 3130, 2018, do not include ~~234~~135,~~930~~089 units related to unvested restricted unit awards.

Page 3033

Board Units

On May 16, 2017, Legacy granted and issued 47,847 units to each of the six non-employee directors who receive compensation for their service on Legacy's board of directors. The value of each unit was $2.04 at the time of issuance.

(On May 15, 2018, Legacy granted and issued 12),019 ~~Subsidiary~~units ~~Guarantors~~to four non-employee directors who are anticipated to serve on the Board of Directors of New Legacy and 6,010 units to two non-employee directors who are not anticipated to serve on the Board of Directors of New Legacy. The value of each unit was $8.69 at the time of issuance.

The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of Legacy's 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by Legacy's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (~~the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”~~13). ~~The~~Subsidiary Subsidiaries are 100% owned, directly or indirectly, by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in “—Footnote 2—Long-Term Debt.” The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors.

~~Page~~The 31Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of Legacy's 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by Legacy's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned, directly or indirectly, by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in “—Footnote 2—Debt.” The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors.

(1314) Subsequent Events

On ~~March 26~~June 22, 2018, the Partnership, New Legacy, LRGPLLC and the plaintiff in ~~connection~~the Consolidated Action reached an agreement in principle to settle the Consolidated Action. The parties submitted the Settlement Agreement to the Court on July 6, 2018 and, on July 11, 2018, the Court entered a scheduling order for consideration of the Settlement Agreement (the “Scheduling Order”). The Scheduling Order sets September 12, 2018 as the date for the hearing at which the Court will consider (i) the fairness of the Settlement Agreement; (ii) whether a judgment should be entered dismissing the Consolidated Action with prejudice; (iii) the ~~Corporate~~plaintiff’s ~~Reorganization~~counsel’s application for fees and expenses; and (iv) any objections to the Settlement Agreement. The Settlement Agreement, if approved by the Court, will grant holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in New Legacy in addition to the approximately 16,913,592 shares those holders would collectively receive pursuant to the exchange ratios that were included in the Initial Merger Agreement. In exchange, the class of holders of Preferred Units (dating back to January 21, 2016 through the consummation of the Merger) have agreed to release the Partnership, ~~commenced~~LRGPLLC ~~consent~~and ~~solicitations~~New ~~relating~~Legacy, and any of their parent entities, controlling persons, associates, affiliates, including any person or entity owning, directly or indirectly, any portion of LRGPLLC, or subsidiaries and each and all of their respective officers, directors, stockholders, employees, representatives, advisors, consultants and other released parties, from liability for any claims related to or arising out of the ~~2020~~rights ~~Senior~~inhering ~~Notes~~to the Preferred Units (subject to limited exceptions related to tax liabilities), including all claims brought in the Consolidated Action. As part of the Settlement Agreement, the lawsuit filed against the Partnership and LRGPLLC by the ~~2021~~Plaintiff ~~Senior~~in ~~Notes~~the Doppelt Action based on the treatment of the accrued but unpaid preferred distributions as "guaranteed payments" for tax purposes will be dismissed. Each of the administrative agent for the Current Credit Agreement and the majority lenders under the Second Lien Term Loan Credit Agreement have consented to the terms of the Settlement Agreement, as required pursuant to the terms of the Current Credit Agreement and the Second Lien Term Loan Credit Agreement, respectively.

On ~~April 2~~July 9, 2018, ~~following~~New ~~receipt~~Legacy, the Partnership, LRGPLLC and Merger Sub entered into the A&R Merger Agreement. The A&R Merger Agreement amends the Initial Merger Agreement to provide, among other things, that (i) with respect to the Series A Preferred Units, each Series A Preferred Unit will be converted into the right to receive 2.92033118 shares of common stock in New Legacy, (ii) with respect to the ~~requisite~~Series ~~consents~~B Preferred Units, each Series B Preferred Unit will be converted into the right to receive 2.90650421 shares of common stock in New Legacy, (iii) for the ~~holders~~purposes of clarification, phantom units that settle in units representing limited partner interests in the ~~2020 Senior~~Partnership ~~Notes~~are ~~and~~included in the ~~2021~~definition ~~Senior~~of ~~Notes~~“Restricted Unit”, asand ~~applicable,~~(iv) the board of directors of LRGPLLC shall take all necessary actions to allow the Partnership’s ~~entered~~unitholders ~~into:~~to vote at the Special Meeting on the Classified Board Proposal.

•Page the Second Supplemental Indenture (the “2020 Notes Supplemental Indenture”), by and among the Partnership, New Legacy, LRGPLLC, Legacy Reserves Finance Corporation, a Delaware corporation and a subsidiary of the Partnership (“Finance Corp.”), the guarantors named therein and Wilmington Trust, National Association, as successor trustee (the “Trustee”), to the Indenture, dated as of December 4, 2012 (the “2020 Notes Indenture”), by and among the Partnership, Finance Corp., the guarantors named therein and the Trustee; and34

•On ~~the~~July ~~Second~~31, ~~Supplemental Indenture (the “2021 Notes Supplemental Indenture” and~~2018, ~~together with~~ the ~~2020~~lenders ~~Notes~~for ~~Supplemental Indenture,~~ the ~~“Supplemental~~Current ~~Indentures”),~~Credit byAgreement ~~and~~agreed ~~among~~to waive the Partnership,’s ~~New~~compliance ~~Legacy,~~with ~~LRGPLLC,~~ the ~~guarantors~~ratio ~~named~~of ~~therein~~consolidated ~~and~~current ~~the~~assets ~~Trustee,~~ to ~~the~~consolidated ~~Indenture,~~current ~~dated~~liabilities ascovenant ofcontained ~~May~~in ~~28, 2013 (~~the ~~“2021~~Current ~~Notes~~Credit ~~Indenture”~~Agreement ~~and,~~for ~~together with~~ the ~~2020~~fiscal ~~Notes~~quarter ~~Indenture,~~ended ~~the~~June ~~“Indentures”)~~30, ~~by and among the Partnership, Finance Corp~~2018.~~, the guarantors named therein and the Trustee.~~

~~Pursuant~~Page to the Supplemental Indentures, the parties amended the Indentures to, among other things, (i) exclude the Corporate Reorganization from the definition of “Change of Control” in the Indentures, (ii) permit the Corporate Reorganization, (iii) provide for the issuance of an unconditional and irrevocable guarantee of the 2020 Senior Notes and the 2021 Senior Notes by New Legacy and LRGPLLC, (iv) provide that certain covenants and other provisions under the Indentures previously applicable to the Partnership and its restricted subsidiaries will apply to New Legacy and its restricted subsidiaries, (v) make certain changes to the restricted payments covenant to reflect that the Partnership will no longer be a publicly traded master limited partnership following the Corporate Reorganization and (vi) effect certain other conforming changes.35

Page 32

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 ability to consummate the Corporate Reorganization (as defined below);

•~~our~~ ~~business~~the ~~strategy:~~outcome of any legal proceedings that may have been instituted against the Partnership relating to the Corporate Reorganization;

•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 identify, acquire, exploit and appropriately finance additional oil and natural gas properties at economically attractive prices;


•	our ability to replace reserves and increase reserve value;

•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 our capital expenditures;


•	our ability to comply with, renegotiate or receive waivers of debt covenants under our Revolving Credit Agreement and our Term Loan Credit Agreement (as defined below);


•	our ability to engage in lending and capital markets activity which may include debt refinancings or extensions, exchanges or repurchases or debt or equity issuances;


•	our ability to divest non-core assets at economically attractive prices;

•our ability to resume cash distributions to our limited partners;

•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, 2017 in Item 1A under “Risk Factors.” The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly.

Page 3336

Recent Developments

On March 26, 2018, the Partnership announced its intent to consummate a transaction pursuant to an Agreement and Plan of Merger (the "Initial Merger Plan") that would result in the Partnership and its general partner, Legacy Reserves GP, LLC, a Delaware limited liability company (the “General Partner”), becoming subsidiaries of a newly formed Delaware corporation, Legacy Reserves Inc. (“New Legacy”), and the Partnership’s unitholders and preferred unitholders becoming common stockholders of New Legacy (such transaction referred to herein collectively as the “Corporate Reorganization”). Upon the consummation of the Corporate Reorganization:


•	New Legacy, which is currently a wholly owned subsidiary of the General Partner, will acquire all of the issued and outstanding limited liability company interests in the General Partner and will become the sole member of the General Partner; and

• the Partnership will merge with Legacy Reserves Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of New Legacy ("Merger Sub"), with the Partnership continuing as the surviving entity and as a subsidiary of New Legacy (the "Merger"), the limited partner interests of the Partnership other than the incentive distribution units in the Partnership being exchanged for New Legacy common stock and the General Partner interest remaining outstanding.

On June 22, 2018, the Partnership, New Legacy, the General Partner and the plaintiff in a consolidated class action challenging the Merger that was filed in the Court of Chancery of the State of Delaware (the “Court”) reached an agreement in principal to settle the consolidated action. The parties submitted a stipulation and agreement of settlement (the “Settlement Agreement”) to the Court on July 6, 2018. The Court has entered a scheduling order setting September 12, 2018 as the date for a hearing for consideration of the Settlement Agreement. The Settlement Agreement, if approved by the Court, will grant holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in New Legacy in addition to the approximately 16,913,592 shares those holders would collectively receive pursuant to the exchange ratios that were included in the Initial Merger Agreement.

On July 9, 2018, New Legacy, the Partnership, the General Partner and Merger Sub entered into an Amended and Restated Agreement and Plan of Merger (the “A&R Merger Agreement”). The A&R Merger Agreement amends the Initial Merger Agreement to provide, among other things, that (i) with respect to the 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of the Partnership (the “Series A Preferred Units”), each Series A Preferred Unit will be converted into the right to receive 2.92033118 shares of common stock in New Legacy, (ii) with respect to the 8% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units of the Partnership (the “Series B Preferred Units”), each Series B Preferred Unit will be converted into the right to receive 2.90650421 shares of common stock in New Legacy, (iii) for the purposes of clarification, phantom units that settle in units representing limited partner interests in the Partnership are included in the definition of “Restricted Unit”, and (iv) the board of directors of the General Partner shall take all necessary actions to allow the Partnership’s unitholders to vote at a special meeting of the unitholders (the “Special Meeting”) on a proposal to approve the classification of the board of directors of New Legacy, to be in effect following the closing of the A&R Merger Agreement (the “Classified Board Proposal”).

Overview

The oil and natural gas industry is in a challenging environment, especially over the past four years, as evidenced by volatility in the crude oil prices that ranged from over $100 per barrel in early 2014 to less than $30 per barrel in 2016 with 2017 bringing a recovery off the lows experienced in 2016 but below levels seen in 2014. As crude oil prices have strengthened through 2018, development activity in the Permian Basin has created certain basin-wide operational challenges. Crude oil and associated natural gas production growth has strained existing takeaway capacity and caused widening basis differentials in the Permian Basin relative to benchmark crude oil and natural gas prices, which affect the prices we realize for our crude oil and natural gas production. The narrowing of these basis differentials is largely dependent on the construction of new takeaway capacity and other factors beyond our control. While we believe that a significant number of these projects will be completed in 2019, there is no guarantee that these projects will be completed on time or at all. In addition, the availability of services related to drilling, completion and other well site activity is becoming tighter. We do not have the ability to control the supply of these services and if we are unable to find adequate services for our operations at economic prices, there could be a material adverse impact on our financial condition. Also, production from our horizontal development within the Permian Basin has, from time to time, been temporarily shut-in or constrained due to proximate development operations. We cannot control or accurately forecast the timing, duration or other operational impositions associated with such well interference but the impacts could have a material adverse effect on our financial condition. Our development capital expenditures are expected to be approximately $225 million in 2018 and will be focused on the development of our Permian Basin horizontal assets. We intend to continue to prudently manage our historical low-decline proved developed producing oil and gas properties to support the development of our high return prospects as we pursue additional cash flow and increase oil and natural gas reserves. To illustrate the sensitivity of our proved reserves to fluctuations in commodity prices, we recalculated our proved reserves as of December 31, 2017, using the five-year average forward price as of March 31, 2018 for both WTI oil and NYMEX natural gas. While this 5-year NYMEX forward strip price is not necessarily indicative of our overall outlook on future commodity prices, this commonly used methodology may help provide investors with an understanding of the impact of a volatile commodity price environment. Under such assumptions, we estimate the cumulative projected production from our year-end proved reserves would increase by approximately 1.5% to 182.7 MMBoe from the reported 180.0 MMBoe, which is calculated as required by the SEC.

~~Should~~Page we experience a decline in oil and natural gas prices or basis differentials widen significantly in 2018, we could breach certain financial covenants under our $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and the lenders party thereto as amended most recently by the Ninth Amendment thereto (as amended, the “Revolving Credit Agreement”) and our second lien term loan credit agreement (as amended, our “Term Loan Credit Agreement”), which would constitute a default under our Revolving Credit Agreement or our Term Loan Credit Agreement. Such default, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and subsequent acceleration of all amounts outstanding under our Revolving Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas properties. Certain payment defaults or acceleration under our Revolving Credit Agreement or our Term Loan Credit Agreement could cause a cross-default or cross-acceleration of all of our indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, we believe the long-term global outlook for commodity prices and our efforts to date will be viewed positively by our lenders. For further discussion on the consequences of a breach of such covenants, including a potential cross-default of all our existing indebtedness, please read “Risk Factors-Risks Related to Our Business-Continued low commodity prices may impact our ability to comply with debt covenants” in our Annual Report on Form 10-K for the year ended December 31, 2017.37

~~Page~~proved 34developed producing oil and gas properties to support the development of our high return prospects as we pursue additional cash flow and increase oil and natural gas reserves. To illustrate the sensitivity of our proved reserves to fluctuations in commodity prices, we recalculated our proved reserves as of December 31, 2017, using the five-year average forward price as of June 30, 2018 for both WTI oil and NYMEX natural gas. While this 5-year NYMEX forward strip price is not necessarily indicative of our overall outlook on future commodity prices, this commonly used methodology may help provide investors with an understanding of the impact of a volatile commodity price environment. Under such assumptions, we estimate the cumulative projected production from our year-end proved reserves would decrease by approximately 0.4% to 179.2 MMBoe from the reported 180.0 MMBoe, which is calculated as required by the SEC.

~~Considering~~We may breach certain financial covenants under our $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and the ~~current~~lenders ~~environment~~party ~~for~~thereto as amended most recently by the Ninth Amendment thereto (as amended, the “Revolving Credit Agreement”) and our second lien term loan credit agreement (as amended, our “Term Loan Credit Agreement”), which would constitute a default under our Revolving Credit Agreement or our Term Loan Credit Agreement. Such default, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and subsequent acceleration of all amounts outstanding under our Revolving Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas ~~industry,~~properties. Certain payment defaults or acceleration under our ~~goals~~Revolving Credit Agreement or our Term Loan Credit Agreement could cause a cross-default or cross-acceleration of all of our indebtedness. While no assurances can be made that, in ~~2018~~the ~~are~~event of a covenant breach, such a waiver will be granted, we believe the long-term global outlook for commodity prices and our efforts to: date will be viewed positively by our lenders. For further discussion on the consequences of a breach of such covenants, including a potential cross-default of all our existing indebtedness, please read “Risk Factors-Risks Related to Our Business-Continued low commodity prices may impact our ability to comply with debt covenants” in our Annual Report on Form 10-K for the year ended December 31, 2017.

Considering the current environment for the oil and natural gas industry, our goals for the remainder of 2018 are to:


•	efficiently develop our horizontal inventory in the Permian Basin to meaningfully grow oil production and total company cash flow and reserve value;


•	minimize production declines and operating costs through efficient operations; and

• reposition our balance sheet by (i) ~~remaining free cash flow positive for the year, (ii)~~ consummating the Corporate Reorganization and (~~iii~~ii) evaluating and opportunistically pursuing alternatives to materially reduce our outstanding indebtedness and restructure our near term maturity indebtedness.

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 portion of our expected production, which allows us to mitigate, but not eliminate, oil and natural gas price risk. Such derivative instruments are not designated as cash flow hedges and, therefore, the mark-to-market adjustment reflecting the change in fair value associated with these instruments is recorded in current earnings.

We regularly conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine our ability to execute our capital investment programs, the value of our proved reserves, our projected borrowing base under our revolving credit facility and, more generally, our ability to meet future financial obligations.

We also 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 through a combination of acquiring additional reserves, drilling to find additional reserves, recompleting or adding pay in existing wellbores and improving artificial lift.

Production and Operating Costs Reporting

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

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

Page 3538

reflects these costs, much of our natural gas production is subject to such costs before the transfer of ownership to the purchaser, and we recognize these expenses as operating 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.

Page 39

Operating Data

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

	Three Months Ended March 31,
	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
	(In thousands, except per unit data)
Revenues:
Oil sales	$	9399,~~411~~799		$	4946,~~142~~096	$	193,210		$	95,238
Natural gas liquids (NGL) sales	75,~~396~~735			54,~~050~~921		13,131			9,971
Natural gas sales	3633,~~672~~747			4541,~~355~~830		70,419			87,185
Total revenue	$	~~137~~139,~~479~~281		$	9992,~~547~~847	$	276,760		$	192,394
Expenses:
Oil and natural gas production, excluding ad valorem taxes	$	4546,~~585~~882		$	4942,~~228~~262	$	92,467		$	91,490
Ad valorem taxes	2,~~382~~549			12,~~989~~540		4,931			4,529
Total oil and natural gas production	$	4749,~~967~~431		$	5144,~~217~~802	$	97,398		$	96,019
Production and other taxes	$	7,~~326~~658		$	4,~~159~~145	$	14,984		$	8,304
General and administrative, excluding transaction costs and LTIP	$	98,~~502~~003		$	87,~~623~~046	$	17,505		$	15,669
Transaction related expenses	1,782			32
Transaction costs	1,607			52		3,389			84
LTIP expense	12,~~806~~886			1,~~897~~483		25,692			3,380
Total general and administrative	$	2422,~~090~~496		$	108,~~552~~581	$	46,586		$	19,133
Depletion, depreciation, amortization and accretion	$	3638,~~547~~139		$	2827,~~796~~689	$	74,686		$	56,485
Commodity derivative cash settlements:
Oil derivative cash settlements (paid) received	$	(46,~~894~~309	)	$	3,~~139~~559	$	(11,203	)	$	6,698
Natural gas derivative cash settlements received	$	23,~~099~~895		$	13,~~097~~012	$	5,994		$	4,109
Production:
Oil (MBbls)	1,~~547~~629			1,~~037~~044		3,176			2,081
Natural gas liquids (MGal)	911,~~244~~332			78,~~653~~514		20,576			16,167
Natural gas (MMcf)	14,~~280~~555			15,~~592~~604		28,835			31,196
Total (MBoe)	4,~~147~~325			3,~~818~~847		8,472			7,665
Average daily production (Boe/d)	4647,~~078~~527			42,~~422~~275		46,807			42,348
Average sales price per unit (excluding derivative cash settlements):
Oil price (per Bbl)	$	6061.3826		$	4744.3915	$	60.83		$	45.77
Natural gas liquids price (per Gal)	$	0.8051		$	0.6658	$	0.64		$	0.62
Natural gas price (per Mcf)	$	2.5732		$	2.9168	$	2.44		$	2.79
Combined (per Boe)	$	3332.1520		$	2624.0713	$	32.67		$	25.10
Average sales price per unit (including derivative cash settlements):
Oil price (per Bbl)	$	57.2239		$	5047.4256	$	57.31		$	48.98
Natural gas liquids price (per Gal)	$	0.8051		$	0.6658	$	0.64		$	0.62
Natural gas price (per Mcf)	$	2.7259		$	2.9887	$	2.65		$	2.93
Combined (per Boe)	$	3231.4865		$	2725.1884	$	32.05		$	26.51
Average WTI oil spot price (per Bbl)	$	6268.9107		$	5148.6210	$	65.55		$	49.85
Average Henry Hub natural gas spot price (per MMbtu)	$	32.0885		$	3.0208	$	2.96		$	3.05
Average unit costs per Boe:
Oil and natural gas production, excluding ad valorem taxes	$	10.9984		$	1210.8999	$	10.91		$	11.94
Ad valorem taxes	$	0.5759		$	0.5266	$	0.58		$	0.59
Production and other taxes	$	1.77		$	1.0908	$	1.77		$	1.08
General and administrative excluding transaction costs and LTIP	$	21.2985		$	21.2683	$	2.07		$	2.04
Total general and administrative	$	5.8120		$	2.7623	$	5.50		$	2.50
Depletion, depreciation, amortization and accretion	$	8.8182		$	7.5420	$	8.82		$	7.37

Page 3640

Results of Operations

Three-Month Period Ended ~~March~~June 3130, 2018 Compared to Three-Month Period Ended ~~March~~June 3130, 2017

Our revenues from the sale of oil were $9399.48 million and $4946.1 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. Our revenues from the sale of NGLs were $75.47 million and $54.19 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. Our revenues from the sale of natural gas were $3633.7 million and $4541.48 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. The $4453.37 million increase in oil revenues reflects an increase in production of ~~510~~585 MBbls (4956%) and an increase in the average realized price of $17.11 per Bbl (39%). The increase in production is due to our Permian horizontal drilling program and increased working interests under our amended and restated development agreement with an affiliate of TPG Sixth Street Partners (the "Amended and Restated Development Agreement"). ~~and~~The increase in oil revenues also reflects the increase in average realized price ~~of $12.99 per Bbl (27%)~~ due to an increase in the average West Texas Intermediate (“WTI”) crude oil ~~prices~~price of $1119.2997 per Bbl ~~and~~partially ~~increased~~offset ~~Permian~~by ~~production~~widening ~~which~~regional ~~has realized better~~ differentials ~~than our other regions~~. The $20.38 million increase in NGL sales reflects anincreased ~~increase~~ethane recoveries in our Piceance Basin properties partially offset by a decrease in the realized NGL price of approximately $0.1407 per Gal (2112%) ~~and increased ethane recoveries in our Piceance Basin properties~~. The $8.71 million decrease in natural gas revenues reflects lower ~~production and lower~~ realized natural gas prices and a decrease in production. Average realized natural gas prices decreased by $0.3436 per Mcf (1213%) during the three months ended ~~March~~June 3130, 2018 compared to the same period in 2017. Realized prices decreased due to lower NYMEX Henry Hub prices, widening regional differentials and $0.1012 attributable to our adoption of ASC 606. For further discussion of our adoption of ASC 606 and its effect on our financial statements, please see "—Footnote 3—Impact of ASC 606 Adoption" in the Notes to Consolidated Financial Statements. Our natural gas production decreased by approximately 1,~~312~~049 MMcf (87%) primarily due to natural production declines and individually immaterial divestitures partially offset by increased working interests under our Amended and Restated Development Agreement.

For the three-month period ended ~~March~~June 3130, 2018, we recorded $19.73 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the three-month period ended ~~March~~June 3130, 2018 are primarily due to unfavorable cash settlements on our oil derivatives and a decrease in the value of our derivative positions resulting from an increase in commodity prices during the quarter. This decrease was partially offset by an increase in the value of our Mid-Cush differential swaps and favorable cash settlements on our Mid-Cush and natural gas derivatives. For the three-month period ended ~~March~~June 3130, 2017, we recorded $3414.75 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash (payments) receipts of $(2.84) million and $46.26 million during the three months ended ~~March~~June 3130, 2018 and 2017, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, ~~decreased~~increased to $4546.69 million ($10.9984 per Boe) for the three-month period ended ~~March~~June 3130, 2018 from $4942.23 million ($1210.8999 per Boe) for the three-month period ended ~~March~~June 3130, 2017. This ~~decrease~~increase is primarily attributable to ~~cost containment efforts across all operating regions partially offset by~~ costs associated with increased production related to our Permian horizontal drilling program, ~~and~~ as well as increased working interests under our Amended and Restated Development Agreement. Our ad valorem tax expense ~~increased~~remained toconsistent at $2.45 million ~~($0.57 per Boe)~~ for the three-month period ended ~~March~~June 3130, 2018 compared to $2.05 million ~~($0.52~~or ~~per Boe) for~~ the three-month period ended ~~March~~June 3130, 2017. The increase was attributable to higher historical oil and natural gas commodity prices, resulting in higher reserve valuations, upon which much of our ad valorem taxes are based, resulting in higher ad valorem tax expense.

Our production and other taxes were $7.37 million and $4.21 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. Production and other taxes increased due to the increase in our ~~production and~~ weighted average product price asand ~~tax~~increased ~~rates remained relatively consistent~~production.

Our general and administrative expenses were $2422.15 million and $108.6 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. General and administrative expenses increased due to a $1011.94 million increase in LTIP expense related to the recent increase in our unit price, a $1.76 million increase in transaction ~~related~~costs ~~expenses~~ and general cost increases.

We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $3638.51 million and $2827.87 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. DD&A increased $710.85 million due primarily to increased horizontal Permian production.

WeIn ~~did not recognize impairment expense in~~ the three-month period ended ~~March~~June 3130, 2018~~. In the three-month period ended March 31~~, ~~2017,~~ we recognized impairment expense of $835.14 million on seven separate producing fields primarily related to the decline in ~~oil and~~ natural gas futures prices during the period since December 31, ~~2016~~2017. In the three-month period ended June 30, 2017, we recognized impairment expense of $1.8 million on four separate producing fields primarily related to increased operating expenses.

WePage recorded gains on disposal of assets of $20.4 million and $5.5 million for the three-month periods ended March 31, 2018 and 2017, respectively. The gains in 2018 and 2017 were primarily related to the disposition of marginal oil and natural gas assets partially offset by costs associated with disposal. 41

~~Page~~We 37recorded (gains) losses on disposal of assets of $(1.1) million and $11.0 million for the three-month periods ended June 30, 2018 and 2017, respectively. The gains in 2018 were primarily related to the disposition of marginal oil and natural gas assets. The losses in 2017 were primarily related to the disposition of oil and natural gas assets operated under a CO2 flood.

We recorded interest expense of $2728.46 million and $20.16 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. Interest expense increased period over period due to additional ~~expense~~expenses associated with new borrowings under our Second Lien Term Loan Credit Agreement and increased interest expense on our revolving credit facility partially offset by lower bond interest following our 2018 repurchase of Senior Notes.

As a result of the items described above, Legacy recorded net ~~income~~losses of $6450.47 million and $1611.41 million for the three-month periods ended ~~March~~June 3130, 2018 and 2017, respectively.

Six-Month Period Ended June 30, 2018 Compared to Six-Month Period Ended June 30, 2017

Our revenues from the sale of oil were $193.2 million and $95.2 million for the six-month periods ended June 30, 2018 and 2017, respectively. Our revenues from the sale of NGLs were $13.1 million and $10.0 million for the six-month periods ended June 30, 2018 and 2017, respectively. Our revenues from the sale of natural gas were $70.4 million and $87.2 million for the six-month periods ended June 30, 2018 and 2017, respectively. The $98.0 million increase in oil revenues reflects an increase in oil production of 1,095 MBbls (53%) due to our Permian horizontal drilling program and increased working interests under the Amended and Restated Development Agreement. The increase in oil revenues also reflects the increase in average realized price of $15.06 per Bbl (33%) due to an increase in average WTI crude oil prices of $15.70 per Bbl partially offset by widening regional differentials. The $3.2 million increase in NGL sales reflects increased ethane recoveries in our Piceance Basin properties and an increase in the realized NGL price of approximately $0.02 per Gal (3%) due to higher commodity prices. The $16.8 million decrease in natural gas revenues reflects lower realized natural gas prices and a decrease in natural gas production. Average realized natural gas prices decreased by $0.35 per Mcf (13%) during the six months ended June 30, 2018 compared to the same period in 2017 due to widening regional differentials, the decrease in average NYMEX Henry Hub natural gas prices of $0.09 per Mcf and $0.11 attributable to our adoption of ASC 606. For further discussion of our adoption of ASC 606 and its effect on our financial statements, please see "—Footnote 3—Impact of ASC 606 Adoption" in the Notes to Consolidated Financial Statements. Our natural gas production decreased by approximately 2,361 MMcf (8%) due to natural production declines and individually immaterial divestitures partially offset by increased working interests under our Amended and Restated Development Agreement.

For the six-month period ended June 30, 2018, we recorded $11.0 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the six-month period ended June 30, 2018 are primarily due to the increase in commodity prices during 2018 and unfavorable cash settlements on our oil derivatives. This decrease was partially offset by an increase in the value of our Mid-Cush differential swaps and favorable cash settlements on our Mid-Cush and natural gas derivatives. For the six-month period ended June 30, 2017, we recorded $49.2 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash (payments) receipts of $(5.2) million and $10.8 million during the six months ended June 30, 2018 and 2017, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, increased to $92.5 million for the six-month period ended June 30, 2018 from $91.5 million for the six-month period ended June 30, 2017. This increase is primarily attributable to increased well count due to our Permian horizontal drilling program and increased working interests under our Amended and Restated Development Agreement partially offset by general cost reduction efforts. Our ad valorem tax expense increased to $4.9 million ($0.58 per Boe) for the six-month period ended June 30, 2018 compared to $4.5 million ($0.59 per Boe) for the six-month period ended June 30, 2017 primarily due to increased well count and increased working interests under our Amended and Restated Development Agreement, resulting in a larger taxable asset base.

Our production and other taxes were $15.0 million and $8.3 million for the six-month periods ended June 30, 2018 and 2017, respectively. Production and other taxes increased due to the increase in our weighted average product price and increased production.

Our general and administrative expenses were $46.6 million and $19.1 million for the six-month periods ended June 30, 2018 and 2017, respectively. General and administrative expenses increased due to a $21.8 million increase in LTIP expense related to the recent increase in our unit price, a $3.3 million increase in transaction costs, and general cost increases.

We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $74.7 million and $56.5 million for the six-month periods ended June 30, 2018 and 2017, respectively. DD&A increased $18.2 million due primarily to increased horizontal Permian production.

Page 42

Impairment expense was $35.4 million and $9.9 million for the six-month periods ended June 30, 2018 and 2017, respectively. In the six-month period ended June 30, 2018, we recognized $35.4 million of impairment expense on seven separate producing fields related to the decline in natural gas futures prices during the period since December 31, 2017. Impairment expense for the six-month period ended June 30, 2017 was recognized on 11 separate producing fields primarily related to the further decline in oil and natural gas futures prices during the period and increased expenses.

We recorded (gains) losses on disposal of assets of $(21.5) million and $5.5 million for the six-month periods ended June 30, 2018 and 2017, respectively. The gains in 2018 were primarily related to the disposition of marginal oil and natural gas assets. The losses in 2017 were primarily related to the disposition of oil and natural gas assets operated under a CO₂ flood.

We recorded interest expense of $56.0 million and $40.7 million for the six-month periods ended June 30, 2018 and 2017, respectively. Interest expense increased approximately $15.2 million primarily due to additional interest expense associated with new borrowings under our Second Lien Term Loan Credit Agreement and increased interest expense on our revolving credit facility partially offset by lower bond interest expense following our 2018 repurchase of Senior Notes.

As a result of the items described above, Legacy recorded net income of $13.7 million and $5.3 million for the six-month periods ended June 30, 2018 and 2017, respectively.

Non-GAAP Financial Measure

Our management uses Adjusted EBITDA as a tool to provide additional information and metrics relative to the performance of our business. Our management believes that Adjusted EBITDA is useful to investors because this measure is used by many companies in the industry as a measure of operating and financial performance and is commonly employed by financial analysts and others to evaluate the operating and financial performance of the Partnership from period to period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.The following presents a reconciliation of “Adjusted EBITDA,” which is a non-GAAP measure, to its nearest comparable GAAP measure. Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance. Adjusted EBITDA is defined as net income (loss) plus:


•	Interest expense;


•	Gain on extinguishment of debt;


•	Income tax expense;


•	Depletion, depreciation, amortization and accretion;


•	Impairment of long-lived assets;


•	(Gain) loss on disposal of assets;


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


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


•	Minimum payments earned in excess of overriding royalty interest;


•	Net (gains) losses on commodity derivatives;


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

• Transaction ~~related expenses~~costs.

Page 3843

The following table presents a reconciliation of our consolidated net income to Adjusted EBITDA for the three and six months ended ~~March~~June 3130, 2018 and 2017, respectively.

	Three Months Ended						Six Months Ended
	March 31,
	June 30,						June 30,
	2018			2017			2018			2017
	(In thousands)
Net income	$	64,382		$	16,372
Net income (loss)	$	(50,709	)	$	(11,077	)	$	13,673		$	5,295
Plus:
Interest expense	2728,~~368~~589			20,~~133~~614			55,957			40,747
Gain on extinguishment of debt	~~(51,693~~—		)	—			(51,693		)	—
Income tax expense	~~487~~130			~~421~~150			617			571
Depletion, depreciation, amortization and accretion	3638,~~547~~139			2827,~~796~~689			74,686			56,485
Impairment of long-lived assets	—35,381			81,~~062~~821			35,381			9,883
Gain on disposal of assets	(20,395		)	(5,524		)
(Gain) loss on disposal of assets	(1,145		)	11,049			(21,540		)	5,525
Equity in income of equity method investees	(173		)	(111		)	(20		)	(12		)
Unit-based compensation expense	12,~~806~~886			1,~~897~~483			25,692			3,380
Minimum payments earned in excess of overriding royalty interest(a)	~~522~~334			~~445~~470			856			915
Net (gains) losses on commodity derivatives	19,~~704~~315			(3414,~~669~~516		)	11,019			(49,185		)
Net cash settlements (paid) received on commodity derivatives	(2,~~795~~414		)	46,~~236~~571			(5,209		)	10,807
Transaction costs	1,~~782~~607			3252			3,389			84
Adjusted EBITDA	$	7072,~~698~~110		$	4044,~~190~~305		$	142,808		$	84,495

____________________


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

For the three months ended ~~March~~June 3130, 2018 and 2017, respectively, Adjusted EBITDA increased 7663% to $7072.71 million from $4044.23 million. ~~This~~For ~~increase~~the ~~can~~six bemonths ~~attributed~~ended June 30, 2018 and 2017, Adjusted EBITDA increased 69% to $142.8 million from $84.5 million. These increases are attributable to the increase in realized commodity prices, increased oil production from our Permian horizontal drilling program and increased working interests under our Amended and Restated Development Agreement.

Capital Resources and Liquidity

Legacy’s primary sources of capital and liquidity have been cash flow from operations, the issuance of the Senior Notes, the issuance of additional units and Preferred Units, the Term Loan Credit Agreement and bank borrowings, or a combination thereof. To date, Legacy’s primary use of capital has been for the acquisition and development of oil and natural gas properties, the repayment of bank borrowings and repurchases of Senior Notes.

Based upon current oil and natural gas price expectations and our commodity derivatives positions, we anticipate that our cash flow from operations, commodity hedge realizations and borrowings under our Revolving Credit Agreement and Term Loan Credit Agreement will provide us sufficient liquidity to fund our operations in 2018. However, ~~should oil and natural gas prices decline significantly,~~ we could breach certain financial covenants under our Revolving Credit Agreement or our Term Loan Credit Agreement, which would constitute a default under our Revolving Credit Agreement or our Term Loan Credit Agreement. Such a default, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and potential subsequent acceleration of all amounts outstanding under our Revolving Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas properties. Certain payment defaults or acceleration under our Revolving Credit Agreement could cause a cross-default or cross-acceleration of all of our other indebtedness. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness. Our Revolving Credit Agreement and Term Loan Credit Agreement contain covenants that currently prevent us from making distributions to our limited partners, including holders of our preferred units, unless we meet certain financial criteria, which, as of ~~March~~June 3130, 2018, we do not meet. 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 operate or to maintain planned levels of capital expenditures. Please see “—Cash Flow from Financing Activities—Credit Facility.”

Page 3944

Our Revolving Credit Agreement ~~is classified as a long-term liability as of March 31, 2018; however, it~~ became a current liability as of April 1, 2018 as the credit facility matures on April 1, 2019. We expect to refinance or extend the maturity of this obligation prior to its expiration date and we believe that the consummation of the Corporate Reorganization will improve our ability to do so; however, there is no assurance that we will be able to execute this refinancing or extension or, if we are able to refinance or extend this obligation, that the terms of such refinancing or extension would be as favorable as the terms of our existing Revolving Credit Agreement. If the Corporate Reorganization is not consummated, we believe our ability to refinance or extend the maturity of the Revolving Credit Facility will be limited. We anticipate that the Corporate Reorganization will close in ~~the~~late ~~middle~~September of 2018, but there is no assurance of any timing, if at all.

The amounts available for borrowing under our Revolving Credit Agreement are subject to a borrowing base, which is currently set at $575 million following our spring 2018 redetermination. As of ~~April~~July 3031, 2018, we had $6952.2 million available for borrowing under our Revolving Credit Agreement. Our lenders redetermine the borrowing base semi-annually, with the next redetermination scheduled on or about October 1, 2018, subject to the parties' rights to have additional redeterminations between scheduled redeterminations.

As of ~~April~~July 3031, 2018, we had $61.4 million available for borrowing under our term loan credit agreement. Please see “—Cash Flow from Financing Activities—Second Lien Term Loan Credit Agreement.”

Our commodity derivatives position, which we use to mitigate commodity price volatility and (if positive) support our borrowing capacity, resulted in $25.82 million of unfavorable settlements in the ~~three~~six months ended ~~March~~June 3130, 2018.

For an example illustrating the potential effects of commodity prices on our estimates of proved reserves, see “Management’s Discussion and Analysis of Financial Condition—Overview.”

As market conditions warrant, we may, subject to certain limitations and restrictions, repurchase, exchange or otherwise pay down our outstanding debt, including our Senior Notes, in open market transactions, privately negotiated transactions, by tender offer or otherwise which may impact the trading liquidity of such securities. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Cash Flow from Operations

Our net cash provided by operating activities was $54115.0 million and $3435.91 million for the ~~three~~six-month periods ended ~~March~~June 3130, 2018 and 2017, respectively. The 2018 period was impacted primarily by higher realized oil prices.

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

Cash Flow from Investing Activities

We invested $73118.93 million of capital for the ~~three~~six-month period ended ~~March~~June 3130, 2018, which consisted of $72114.27 million for development projects, exclusive of accrued capital expenditures, individually immaterial acquisitions of oil and natural gas properties and prospective acreage as well as adjustments to prior period acquisitions. We received $2729.12 million of proceeds net of costs related to the divestiture of various oil and natural gas properties in individually immaterial transactions and post-close adjustments. We invested $2961.09 million of capital for the ~~three~~six-month period ended ~~March~~June 3130, 2017, which consisted of $2348.83 million for development projects, $513.26 million of individually immaterial acquisitions of oil and natural gas properties and prospective acreage as well as adjustments to prior period acquisitions. We ~~received~~paid $40.42 million of costs net of proceeds related to the divestiture of various oil and natural gas properties in individually immaterial transactions and post close adjustments.

Our annual capital expenditure budget for 2018, which predominantly consists of drilling, recompletion and well stimulation projects, is set at $225 million. During the ~~three~~six months ended ~~March~~June 3130, 2018, we incurred $59140.74 million of such capital expenditures inclusive of the effect of accrued capital expenditures. We anticipate that we will have sufficient sources of working capital, including our cash flow from operations and available borrowing capacity under our revolving credit facility and our term loan credit agreement to meet our cash obligations including our remaining planned capital expenditures. Our remaining borrowing capacity under our revolving credit facility is $6952.2 million as of ~~April~~July 3031, 2018. The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. We may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions, non-operated

Page 4045

~~a portion of our planned~~ capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions, non-operated capital requirements and internally generated cash flow. 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. We use derivatives to offset price volatility of oil and natural gas prices. For the ~~three~~six-month periods ended ~~March~~June 3130, 2018 and 2017, we ~~had~~ (~~unfavorable~~paid) ~~favorable~~received settlements of $(2.84) million and $46.26 million, respectively, related to our commodity derivatives.

By reducing the cash flow effects of price volatility from a portion of our oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy institutions deemed by management as competent and competitive market makers. In addition, none of our current counterparties require us to post margin. However, we cannot be assured that all of our counterparties will meet their obligations under our derivative contracts. Due to this uncertainty, we routinely monitor the creditworthiness of our counterparties.

The following tables summarize, for the periods indicated, our oil and natural gas derivatives currently in place as of ~~April~~July 3031, 2018, covering the period from ~~April~~July 1, 2018 through December 31, 2019. We use derivatives, including swaps, enhanced swaps and three-way collars, as our mechanism for offsetting the cash flow effects of changes in commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to reduce the effects on cash flow of the floating prices we are paid by purchasers of our oil and natural gas. These transactions are mostly settled based upon the monthly average closing price of the front-month NYMEX WTI oil, the price on the last trading day of front-month NYMEX Henry Hub natural gas.

Oil Swaps:

Time Period	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
April-December 2018	2,282,500	$54.76	$51.20	-	$63.68
July-December 2018	1,527,200	$54.76	$51.20	-	$63.68
2019	2,190,000	$58.88	$57.15	-	$61.20

Natural Gas Swaps:

Time Period	Volumes (MMBtu)	Average Price per MMBtu	Price Range per MMBtu
April-December 2018	27,200,000	$3.23	$3.04	-	$3.39
July-December 2018	18,160,000	$3.23	$3.04	-	$3.39
2019	25,800,000	$3.36	$3.29	-	$3.39

We have entered into regional crude oil differential swap contracts in which we have swapped the floating WTI-ARGUS (Midland) crude oil price for floating WTI-ARGUS (Cushing) crude oil price less a fixed-price differential. As noted above, we receive a discount to the NYMEX WTI crude oil price at the point of sale. Due to refinery downtime and limited takeaway capacity that has impacted the Permian Basin, the difference between the WTI-ARGUS (Midland) price, which is the price we receive on almost all of our Permian crude oil production, and the WTI-ARGUS (Cushing) price reached historic highs in late 2012 and early 2013 and again in late 2014. We entered into these differential swaps to negate a portion of this volatility. The following table summarizes the oil differential contracts currently in place as of ~~April~~July 3031, 2018, covering the period from ~~April~~July 1, 2018 through December 31, 2019:

		Average
Time Period	Volumes (Bbls)	Price per Bbl	Price Range per Bbl
April-December 2018	3,025,000	$(1.13)	$(1.25)	-	$(0.80)
July-December 2018	2,024,000	$(1.13)	$(1.25)	-	$(0.80)
2019	730,000	$(1.15)	$(1.15)

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We have also entered into multiple NYMEX WTI crude oil costless collar contracts. Each contract combines a long put option or "floor" with a short call option or "ceiling." At an annual WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $47.06, $50.00 and $60.29 for 2018. The following table summarizes the costless oil collar contracts currently in place as of ~~April~~July 3031, 2018, covering the period from ~~April~~July 1, 2018 through December 31, 2018:

		Average Long	Average Short
Time Period	Volumes (Bbls)	Put Price per Bbl	Call Price per Bbl
April-December 2018	1,168,750	$47.06	$60.29
July-December 2018	782,000	$47.06	$60.29

We have also entered into multiple NYMEX WTI crude oil derivative enhanced swap contracts. The enhanced swap contract combines buying a lower-priced put, selling a higher-priced put, and using the net proceeds from these positions to simultaneously obtain a swap at above market prices (“enhanced swap price”). If the market price is at or above the higher-priced short put, this contract allows us to settle at the enhanced swap price. If the market price is below the higher-priced short put but above the lower-priced long put, this contract allows us to settle for the market price plus the spread between the enhanced swap price and the higher-priced short put. If the market price is at or below the lower-priced long put, this contract allows us to settle for the lower-priced long put plus the spread between the enhanced swap price and the higher-priced short put. For example, at an annual average WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $65.50, $65.50 and $73.50 for 2018. The following table summarizes this type of enhanced swap contracts currently in place as of ~~April~~July 3031, 2018, covering the period from ~~April~~July 1, 2018 to December 31, 2018:

		Average Long	Average Short	Average
Time Period	Volumes (Bbls)	Put Price per Bbl	Put Price per Bbl	Swap Price per Bbl
April-December 2018	96,250	$57.00	$82.00	$90.50
July-December 2018	64,400	$57.00	$82.00	$90.50

Cash Flow from Financing Activities

Our net cash used in financing activities was $515.69 million for the ~~three~~six months ended ~~March~~June 3130, 2018, compared to cash ~~used~~provided inby financing activities of $1514.09 million for the ~~three~~six months ended ~~March~~June 3130, 2017. During the ~~three~~six months ended ~~March~~June 3130, 2018, total net borrowings under our revolving credit facility were $199.0 million and net borrowings under our Second Lien Term Loans were $133.6 million. Further, we used borrowings under our Term Loan Credit Agreement to repurchase $187.1 million of Senior Notes for $132.1 million, inclusive of accrued but unpaid interest.

During the ~~three~~six months ended ~~March~~June 3130, 2017, total net ~~payments~~borrowings under our revolving credit facility were $15.0 million.

Credit Facility

On April 1, 2014, we entered into our Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement mature on April 1, 2019. Our obligations under the Revolving Credit Agreement are secured by mortgages on over 95% of the total value of its oil and natural gas properties plus certain undeveloped properties as well as a pledge of all of its ownership interests in our operating subsidiaries. The amount available for borrowing at any one time is limited to the borrowing base and contains a $2 million sub-limit for letters of credit.

As of June 30, 2018, our ratio of consolidated current assets to consolidated current liabilities was less than 1.0 to 1.0, in violation of a covenant contained in our Revolving Credit Agreement. On July 31, 2018, we received a waiver with respect to compliance with such covenant for the fiscal quarter ended June 30, 2018. Except with respect compliance with the financial covenant that has been waived, as of ~~March~~June 3130, 2018, we were in compliance with all covenants of the Revolving Credit Agreement. Depending on future oil and natural gas prices, we could breach certain financial covenants under our Revolving Credit Agreement, which would constitute a default under our Revolving Credit Agreement. Such default, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and subsequent acceleration of all amounts outstanding under our Revolving Credit Agreement and potential foreclosure on our oil and natural gas properties. As previously noted, if the lenders under our Revolving Credit Agreement were to accelerate, subject to certain limitations, the indebtedness under our Revolving Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of our other outstanding indebtedness, and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, we believe the long-term global outlook for commodity prices and our efforts to date, which include the suspension of distributions to our unitholders and holders of our preferred units, as well as asset sales completed and anticipated as of the date of this filing, will be viewed positively by our lenders. If an event of default would occur and were continuing, we would be unable to make borrowings under the Revolving Credit Agreement, may be unable to make distributions to our unitholders and our financial condition and liquidity would be adversely affected. The Revolving Credit Agreement contains a covenant that currently prohibits us from paying distributions to our limited partners, including holders of our preferred units. For further information related to our Revolving Credit Agreement, please refer to "—Footnote 2—Long-Term Debt" in the Notes to Condensed Consolidated Financial Statements.

Page 4247

AsRevolving ofCredit ~~March 31,~~Agreement ~~2018,~~contains wea ~~had~~covenant ~~approximately~~that ~~$518~~currently ~~million~~prohibits ~~drawn~~us ~~under~~from ~~the~~paying ~~Revolving~~distributions ~~Credit~~to ~~Agreement~~our atlimited apartners, ~~weighted~~including ~~average~~holders ~~interest rate~~ of ~~4.68%,~~our ~~leaving~~preferred ~~approximately $56~~units.2 ~~million~~For offurther ~~availability~~information ~~under~~related ~~the~~to our Revolving Credit Agreement~~. For the three-month period ended March 31~~, ~~2018,~~please werefer ~~paid~~to in"—Footnote ~~cash $6.~~2—Debt" ~~million~~in ofthe ~~interest~~Notes ~~expense~~to onCondensed ~~the~~Consolidated ~~Revolving~~Financial ~~Credit Agreement~~Statements.

As ~~part~~ of ~~our~~June 30, ~~routine~~2018, ~~spring~~we ~~redetermination,~~had ~~our~~approximately ~~borrowing~~$508.0 ~~base~~million ~~was~~drawn ~~reaffirmed~~under the Revolving Credit Agreement at ~~$575.0~~a ~~million~~weighted average interest rate of 4.76%, leaving approximately $6966.2 million of availability under the Revolving Credit Agreement. asFor ofthe ~~April~~six-month period ended June 30, 2018, we paid in cash $12.7 million of interest expense on the Revolving Credit Agreement.

WeAs ~~periodically~~part ~~enter~~of ~~into~~our ~~interest~~routine ~~rate~~spring ~~swap~~redetermination, ~~transactions~~our toborrowing ~~mitigate~~base ~~the~~was ~~volatility~~reaffirmed ofat ~~interest rates~~$575.0 ~~As of March 31~~million, ~~2018,~~leaving weapproximately ~~had~~$52.2 ~~interest~~million ~~rate swaps on notional amounts~~ of ~~$235~~availability ~~million~~under ~~with~~the aRevolving ~~weighted~~Credit ~~average~~Agreement ~~fixed~~as ~~rate~~ of ~~1.36%.~~July 31, ~~These swaps mature in September 2019~~2018.

We periodically enter into interest rate swap transactions to mitigate the volatility of interest rates. As of June 30, 2018, we had interest rate swaps on notional amounts of $235 million with a weighted average fixed rate of 1.36%. These swaps mature in September 2019.

On March 23, 2018, the Partnership entered into an amendment to the Revolving Credit Agreement (the “Credit Agreement Amendment”). The Credit Agreement Amendment, subject to certain conditions, among which is the consummation of the Corporate Reorganization, amends certain provisions set forth in the Revolving Credit Agreement to, among other items:


•	permit the Corporate Reorganization and modify certain provisions to reflect the new corporate structure;


•	provide that New Legacy and the General Partner will guarantee the debt outstanding under the Revolving Credit Agreement;


•	provide that the Partnership may make unlimited restricted payments, subject to no default or event of default, pro forma availability under the Revolving Credit Agreement of at least 20%, and pro forma total leverage of not more than 3.00 to 1.00, as well as to pay taxes and ordinary course overhead expenses of New Legacy;


•	waive any “Change in Control” (as defined in the Credit Agreement) triggered by the Corporate Reorganization; and


•	permit redemptions of the 2020 Senior Notes, 2021 Senior Notes and loans under the Term Loan Credit Agreement with the cash proceeds from the sale of equity interests (or exchanges for equity interests) of New Legacy.

Second Lien Term Loan Credit Agreement

On October 25, 2016, we entered into the Term Loan Credit Agreement. The term loans under the Term Loan Credit Agreement are issued with an upfront fee of 2% and bear interest at a rate of 12.00% per annum payable quarterly in cash or, prior to the 18 month anniversary of the Term Loan Credit Agreement, Legacy may elect to pay in kind up to 50% of the interest payable. GSO Capital Partners LP ("GSO") and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Term Loan Credit Agreement is secured on a second lien priority basis by the same collateral that secures our Revolving Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of ours that are guarantors under the Revolving Credit Agreement. As of ~~March~~June 3130, 2018, we were in compliance with all covenants of the Term Loan Credit Agreement. The Term Loan Credit Agreement matures on August 31, 2020. The Term Loan Credit Agreement contains a covenant that currently prohibits us from paying distributions to our unitholders and holders of our preferred units. For further information related to our Term Loan Credit Agreement, please refer to "—Footnote 2—~~Long-Term~~ Debt" in the Notes to Condensed Consolidated Financial Statements.

As of ~~April~~July 3031, 2018, Legacy had approximately $338.6 million drawn under the Second Lien Term Loan Credit Agreement. On October 30, 2017 Legacy entered into the Second Amendment to the Term Loan Credit Agreement which, among other things, extends the availability of undrawn principal under our term loan credit agreement ($61.4 million as of ~~April~~July 3031, 2018) to October 25, 2018, with any borrowing being subject to approval by each lender thereunder.

On December 31, 2017, the Partnership entered into the Third Amendment to the Term Loan Credit Agreement (the “Third Term Loan Amendment”). The Third Term Loan Amendment, among other things, increased the maximum principal amount of term loans under the Term Loan Credit Agreement to $400.0 million, extended the availability of borrowings under the Term Loan Credit Agreement to October 25, 2019, relaxed the asset coverage ratio financial covenant from 1.0x to 0.85x during 2018 and required the Partnership to mortgage certain additional properties located in the Permian Basin.

Page 4348

On March 23, 2018, the Partnership entered into the Fourth Amendment to the Term Loan Credit Agreement (the “Fourth Term Loan Amendment”). The Fourth Term Loan Amendment, subject to certain conditions, among which is the consummation of the Corporate Reorganization, amends certain provisions set forth in the Term Loan Credit Agreement to, among other items:


•	permit the Corporate Reorganization and modify certain provisions to reflect the new corporate structure;


•	provide that New Legacy and the General Partner will guarantee the debt outstanding under the Term Loan Credit Agreement;


•	provide that the Partnership may make unlimited restricted payments, subject to no default or event of default, pro forma availability under the Term Loan Credit Agreement of at least 20%, and pro forma total leverage of not more than 3.00 to 1.00, as well as to pay taxes and ordinary course overhead expenses of New Legacy;


•	waive any “Change in Control” (as defined in the Term Loan Credit Agreement) triggered by the Corporate Reorganization;


•	waive any requirement to prepay the Term Loans using the Partnership’s Free Cash Flow or limit Capital Expenditures (each as defined in the Term Loan Credit Agreement) prior to March 31, 2019; and


•	permit redemptions of the 2020 Senior Notes and the 2021 Senior Notes with the cash proceeds from the sale of equity interests (or exchanges for equity interests) of New Legacy.

8% Senior Notes Due 2020

On December 4, 2012, we, together with our 100% owned subsidiary Legacy Reserves Finance Corporation, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300.0 million of our 2020 Senior Notes, which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. We received approximately $286.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by us.

During the fiscal year ended December 31, 2016, we repurchased a face amount of $52.0 million of our 2020 Senior Notes on the open market.

As of ~~March~~June 3130, 2018, we were in compliance with all financial and other covenants of the 2020 Senior Notes. As previously noted, if the lenders under our Revolving Credit Agreement were to accelerate the indebtedness under our Revolving Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of our other outstanding indebtedness and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. For further information related to our 2020 Senior Notes please refer to "—Footnote 2—~~Long-Term~~ Debt" in the Notes to Condensed Consolidated Financial Statements.

6.625% Senior Notes Due 2021

On May 28, 2013, we, together with our 100% owned subsidiary Legacy Reserves Finance Corporation, completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of our 2021 Senior Notes, which were subsequently registered through a public exchange offer that closed on March 18, 2014. This issuance of our 2021 Senior Notes was at 98.405% of par. We received approximately $240.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by us.

On May 13, 2014, we, together with our 100% owned subsidiary Legacy Reserves Finance Corporation, completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of our 6.625% 2021 Senior Notes. This issuance of our 2021 Senior Notes was at 99.0% of par. We received approximately $91.8 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by us.

During the fiscal year ended December 31, 2016, we repurchased a face amount of $117.3 million of our 2021 Senior Notes on the open market.

On December 31, 2017, we entered into a definitive agreement with certain funds managed by Fir Tree Partners ("Fir Tree") pursuant to which we acquired $187.0 million of the 6.625% Notes for a price of approximately $132 million inclusive of accrued but unpaid interest with a settlement date of January 5, 2018. We treated these repurchases for accounting purposes as an extinguishment of debt. Accordingly, we recognized a gain for the difference between (1) the face amount of the 2021 Senior

Page 4449

Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price during the three months ended March 31, 2018.

As of ~~March~~June 3130, 2018, we were in compliance with all financial and other covenants of the 2021 Senior Notes. As previously noted, if the lenders under our Revolving Credit Agreement were to accelerate the indebtedness under our Revolving Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of our other outstanding indebtedness and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. For further information related to our 2021 Senior Notes, please refer to "—Footnote 2—~~Long-Term~~ Debt" in the Notes to Condensed Consolidated Financial Statements.

Supplemental Indentures to the Senior Notes

On March 26, 2018, in connection with the Corporate Reorganization, the Partnership commenced consent solicitations relating to the 2020 Senior Notes and the 2021 Senior Notes.

On April 2, 2018, following receipt of the requisite consents of the holders of the 2020 Senior Notes and the 2021 Senior Notes, as applicable, the Partnership entered into:

•

the Second Supplemental Indenture (the “2020 Notes Supplemental Indenture”), by and among the Partnership, New Legacy, the General Partner, Legacy Reserves Finance Corporation, a Delaware corporation and a subsidiary of the Partnership (“Finance Corp.”), the guarantors named therein and Wilmington Trust, National Association, as successor trustee (the “Trustee”), to the Indenture, dated as of December 4, 2012 (the “2020 Notes Indenture”), by and among the Partnership, Finance Corp., the guarantors named therein and the Trustee; and

•

the Second Supplemental Indenture (the “2021 Notes Supplemental Indenture” and, together with the 2020 Notes Supplemental Indenture, the “Supplemental Indentures”), by and among the Partnership, New Legacy, the General Partner, the guarantors named therein and the Trustee, to the Indenture, dated as of May 28, 2013 (the “2021 Notes Indenture” and, together with the 2020 Notes Indenture, the “Indentures”), by and among the Partnership, Finance Corp., the guarantors named therein and the Trustee.

Pursuant to the Supplemental Indentures, the parties amended the Indentures to, among other things, (i) exclude the Corporate Reorganization from the definition of “Change of Control” in the Indentures, (ii) permit the Corporate Reorganization, (iii) provide for the issuance of an unconditional and irrevocable guarantee of the 2020 Senior Notes and the 2021 Senior Notes by New Legacy and the General Partner, (iv) provide that certain covenants and other provisions under the Indentures previously applicable to the Partnership and its restricted subsidiaries will apply to New Legacy and its restricted subsidiaries, (v) make certain changes to the restricted payments covenant to reflect that the Partnership will no longer be a publicly traded master limited partnership following the Corporate Reorganization and (vi) effect certain other conforming changes.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies and Estimates

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

As of ~~March~~June 3130, 2018, with the exception of the adoption of ASC 606 as discussed in "—Footnote 3—Impact of ASC 606 Adoption" in the Notes to Condensed Consolidated Financial Statements, our critical accounting policies were consistent with those discussed in our Annual Report on Form 10-K for the period ended December 31, 2017.

Page 4550

Use of Estimates

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

Recent Accounting Pronouncements

In February 2016, the FASB issued ~~Accounting~~ASU ~~Standards Update~~ No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is currently required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the consolidated financial statements, with certain practical expedients available. ~~We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements.~~

~~Page~~In 46January 2018, the FASB issued an Exposure Draft titled “Leases (Topic 842): Targeted Improvements,” which includes a proposed amendment to ASU 2016-02 allowing entities an additional transition method to the existing requirements. Under this additional transition method, an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption.

We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. Our ASU 2016-02 implementation approach includes educating key stakeholders within the organization, analyzing systems reports to identify the types and volume of contracts that may meet the definition of a lease under ASU 2016-02 and performing a detailed review of material contracts identified through that analysis. Based on the results obtained, we will assess what impacts ASU 2016-02 could have on our financial statements and disclosures, existing accounting policies and internal controls, as well as whether a financial lease accounting system solution will need to be implemented to comply.

We are also in the process of evaluating ASU 2016-02’s currently available and proposed practical expedients upon transition.

Page 51

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in "Item 1. Financial Statements—Notes to Consolidated Financial Statements —Footnote 89—Derivative Financial Instruments."

Commodity Price Risk

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

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

As of ~~March~~June 3130, 2018, the fair value of our commodity derivative positions was a net asset of $70.45 million based on NYMEX futures prices from ~~April~~July 2018 to December 2019 for both oil and natural gas. As of December 31, 2017, the fair market value of our commodity derivative positions was a net asset of $6.3 million based on NYMEX futures prices from January 2017 to December 2019 for both oil and natural gas. For more discussion about our derivative transactions and to see a table listing the oil and natural gas derivatives from ~~April~~July 2018 through December 2019, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Investing Activities.”

Interest Rate Risks

At ~~March~~June 3130, 2018, we had debt outstanding under our Revolving Credit Agreement of $~~518~~508.0 million, which incurred interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred by us under our Revolving Credit Agreement for the ~~three~~six-month period ended ~~March~~June 3130, 2018 was 4.7790%. A 1% increase in LIBOR on our outstanding debt under our revolving credit facility as of ~~March~~June 3130, 2018 would result in an estimated $2.87 million increase in annual interest expense assuming our current interest rate hedges remain in place and do not expire. We have entered into interest rate swaps with a weighted-average fixed rate of 1.36% to mitigate the volatility of interest rates on notional amounts of $235 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 ~~March~~June 3130, 2018. 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

Page 4752

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.

During the first quarter of 2018, we added internal control processes over financial reporting as a result of the adoption of the new revenue recognition standard (ASC 606). There have been no other changes in our internal control over financial reporting that occurred during our fiscal quarter ended ~~March~~June 3130, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Page 4853

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

On March 28, 2018, a purported holder of the Partnership’s Preferred Units filed a putative class action challenging the Merger against the Partnership, the General Partner and New Legacy (the “Doppelt Action”). The Doppelt Action contains two causes of action challenging the Merger, including breach of the Fifth Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) and breach of the implied covenant of good faith and fair dealing. The plaintiff in the Doppelt Action seeks injunctive relief prohibiting consummation of the Merger or, in the event the Merger is consummated, rescission or rescissory damages, as well as reasonable attorneys’ and experts’ fees and expenses. Additionally, on April 4, 2018, a motion to expedite was filed in connection with the Doppelt Action, by which the plaintiff sought a hearing on a motion for a preliminary injunction prior to the close of the Merger and requested that the court set an expedited discovery schedule prior to any such hearing. The plaintiff in the Doppelt Action also filed a lawsuit against the Partnership and the General Partner in 2017 for breach of the Partnership Agreement based on the treatment of the accrued but unpaid preferred distributions as “guaranteed payments” for tax purposes (the "Doppelt Tax Action"). A second putative class action lawsuit challenging the Merger was filed on April 3, 2018 against the Partnership, the Partnership GP and New Legacy (the “Chammah Ventures Action”). The Chammah Ventures Action contains the same causes of action and that plaintiff seeks substantially the same relief as the plaintiff in the Doppelt Action. On April 13, 2018, the Court issued an order consolidating the Doppelt and Chammah actions (together, the "Consolidated Action") and appointing Plaintiff Doppelt as lead plaintiff and his counsel as lead counsel for the putative class action. On April 13, 2018, the Court also granted the motion to expedite the consolidated action. On April 23, 2018 Plaintiff Doppelt filed an Amended Complaint, adding an additional count for breach of the Partnership Agreement. A hearing on Plaintiff's motion for a preliminary injunction and Legacy's motion to dismiss ~~has~~occurred ~~been~~on ~~set for~~ June 4, 2018.

On June 22, 2018, the Partnership, New Legacy, the General Partner and the plaintiff in the Consolidated Action reached an agreement in principle to settle the Consolidated Action. The parties submitted the Settlement Agreement to the Court on July 6, 2018 and, on July 11, 2018, the Court entered a scheduling order for consideration of the Settlement Agreement (the “Scheduling Order”). The Scheduling Order sets September 12, 2018 as the date for the hearing at which the Court will consider (i) the fairness of the Settlement Agreement; (ii) whether a judgment should be entered dismissing the Consolidated Action with prejudice; (iii) the plaintiff’s counsel’s application for fees and expenses; and (iv) any objections to the Settlement Agreement. The Settlement Agreement, if approved by the Court, will grant holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in New Legacy in addition to the approximately 16,913,592 shares those holders would collectively receive pursuant to the exchange ratios that were included in the Initial Merger Agreement. In exchange, the class of holders of Preferred Units (dating back to January 21, 2016 through the consummation of the Merger) have agreed to release the Partnership, the General Partner and New Legacy, and any of their parent entities, controlling persons, associates, affiliates, including any person or entity owning, directly or indirectly, any portion of the General Partner, or subsidiaries and each and all of their respective officers, directors, stockholders, employees, representatives, advisors, consultants and other released parties, from liability for any claims related to or arising out of the rights inhering to the Preferred Units (subject to limited exceptions related to tax liabilities), including all claims brought in the Consolidated Action. As part of the Settlement Agreement, the Doppelt Tax Action will be dismissed. Each of the administrative agent for the Revolving Credit Agreement and the majority lenders under the Term Loan Credit Agreement have consented to the terms of the Settlement Agreement, as required pursuant to the terms of the Current Credit Agreement and the Term Loan Credit Agreement, respectively.

A third putative class action lawsuit challenging the Merger was filed against the Partnership, the General Partner, New Legacy and Merger Sub on April 27, 2018 by Patrick Irish in the District Court in Midland County, Texas (the “Irish Action”). The Irish Action contains the same general causes of action as the initial complaint filed in the Doppelt Action and the Chammah Ventures Action and seeks the same relief. The Partnership, the General Partner, New Legacy and the plaintiff’s counsel in the Consolidated Action have agreed to coordinate efforts to obtain a dismissal of the Irish Action following the consummation of the Merger.

Legacy is also, from time to time, involved in litigation and claims arising out of its operations in the normal course of business. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on Legacy’s consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on Legacy cannot be predicted with certainty. 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.

Page 54

Item 1A. Risk Factors.

In addition to the information set forth in this report, you should carefully consider the risk factors discussed under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 and "Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, 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.

Risks Relating to the Corporate Reorganization

The Corporate Reorganization is subject to conditions, including some conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Corporate Reorganization, or significant delays in completing the Corporate Reorganization, could negatively affect the Partnership’s business and financial results and the price of the units or, following the consummation of the Corporate Reorganization, future business and financial results and the price of the common stock.

The consummation of the Corporate Reorganization is subject to a number of conditions. The consummation of the Corporate Reorganization is not assured and is subject to risks, including the risk that the unitholder approval of the Merger is not obtained. Further, the Corporate Reorganization may not be consummated even if such unitholder approval is obtained. The Merger Agreement contains conditions, some of which are beyond the parties’ control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger and the Corporate Reorganization not being consummated.

If the Corporate Reorganization is not completed, or if there are significant delays in completing the Corporate Reorganization, the Partnership’s future business and financial results and the trading price of the units could be negatively affected or, following the consummation of the Corporation Reorganization, New Legacy’s future business and financial results and the price of the common stock could be negatively affected, and the parties will be subject to several risks, including the following:

• there may be negative reactions from the financial markets due to the fact that the current price of the units may reflect a market assumption that the Corporate Reorganization will be completed; and

• the attention of management will have been diverted to the Corporate Reorganization rather than the Partnership’s own operations and pursuit of other opportunities that could have been beneficial to the Partnership’s business.

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The Partnership will incur substantial transaction-related costs in connection with the Corporate Reorganization.

The Partnership expects to incur substantial expenses in connection with completing the Corporate Reorganization, including fees paid to legal, financial and accounting advisors, filing fees and printing costs. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time.

The Partnership and New Legacy are subject to litigation related to the Merger.

The Partnership and New Legacy are subject to litigation related to the Merger. The ItPartnership, the General Partner and New Legacy have entered into the Settlement Agreement related to the Merger, which is subject to final court approval. There can be no assurances that final court approval will be obtained. In addition, it is possible that additional claims beyond those which have already been filed will be brought ~~by the current Plaintiff or by others~~ in an effort to enjoin the Merger or seek monetary relief from the Partnership or New Legacy. The Partnership and New Legacy cannot predict the outcome of this ~~lawsuit,~~existing or ~~others~~potential litigation, nor can wethey predict the amount of time and expense that will be required to resolve such litigation. An unfavorable resolution of any such litigation concerning the Merger could delay or prevent its consummation. In addition, the costs of defending the litigation, even if resolved in the Partnership’s or New Legacy’s favor, could be substantial and such litigation could distract the Partnership and New Legacy from pursuing the consummation of the Merger and other potentially beneficial business opportunities. The administrative agent for the Revolving Credit Agreement and the majority lenders under the Term Loan Credit Agreement each have consent rights relating to the settlement of certain litigation which may also limit the Partnership and New Legacy’s ability to resolve any litigation in order to consummate the Merger and the Corporate Reorganization.

In addition to the information set forth in this report, you should carefully consider the factors discussed under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017, 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.

No ruling has been requested with respect to the tax consequences of the Merger.

Although it is intended that the Merger will qualify as an exchange described in Section 351 of the Internal Revenue Code of 1986, as amended, and that the U.S. holders of units will generally not recognize any gain or loss as a result of the Merger (other than gain that may be recognized with respect to cash received in lieu of fractional shares), no ruling has been or will be requested from the Internal Revenue Service, or IRS, with respect to the tax consequences of the Merger. Under certain circumstances, the Merger may be treated as a taxable transaction, and result in tax liability, for a limited partner, depending on such limited partner’s particular situation.

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

Purchases of Equity Securities

	(a)	(b)	(c)	(d)
Period	Total number of units purchased	Price paid per unit	Total number of units purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value of units) that may yet be purchased under the plans or programs
January 15, 2018	395(1)	$2.07	—	—
May 18, 2018	666(1)	$8.01	—	—
January 30, 2018	119(2)	$2.36	—	—
May 19, 2018	24,160(2)	$8.01	—	—
February 8, 2018	154(3)	$2.21	—	—
February 18, 2018	82,527(4)	$2.29	—	—
March 29, 2018	290(5)	$4.71	—	—

(1) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $28.0701 per unit, the closing price of Legacy's units on the NASDAQ Global Market on ~~January~~May 1218, 2018.

(2) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $28.3601 per unit, the closing price of Legacy's units on the NASDAQ Global Market on ~~January~~May 3018, 2018.

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(3) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $2.21 per unit, the closing price of Legacy's units on the NASDAQ Global Market on February 8, 2018.

(4) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $2.29 per unit, the closing price of Legacy's units on the NASDAQ Global Market on February 16, 2018.

(5) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $4.71 per unit, the closing price of Legacy's units on the NASDAQ Global Market on March 29, 2018.

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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
2.1	Amended and Restated Agreement and Plan of Merger, dated as of ~~March~~July 239, 2018, by and among Legacy Reserves Inc., Legacy Reserves Merger Sub LLC, Legacy Reserves LP and Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP'’s Current Report on Form 8-K filed on ~~March~~July 2612, 2018, Exhibit 2.1)
2.2	GP Purchase Agreement, dated as of March 23, 2018, by and among Legacy Reserves Inc., Legacy Reserves LP, Legacy Reserves GP, LLC, Lion GP Interests, LLC, Moriah Properties Limited, Brothers Production Properties, Ltd., Brothers Production Company, Inc., Brothers Operating Company, Inc., J&W McGraw Properties, Ltd., DAB Resources, Ltd. and H2K Holdings, Ltd. (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed March 26, 2018, Exhibit 2.2)
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	Fifth 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 filed April 10, 2017, Exhibit 3.1)
3.3	Certificate of Formation of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.3)
3.4	Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.4)
3.5	First Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP's Quarterly Report on Form 10-Q (File No. 001-33249) filed May 4, 2012, Exhibit 3.6)
3.6	Second Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP's Quarterly Report on Form 10-Q (File No. 001-33249) filed May 4, 2012, Exhibit 3.7)
3.7	Third Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC. (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed March 26, 2018, Exhibit 3.1)
4.1	Second Supplemental Indenture, dated as of April 2, 2018, by and among Legacy Reserves LP, Legacy Reserves Inc., Legacy Reserves GP, LLC, Legacy Reserves Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 8% Senior Notes due 2020) (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed April 2, 2018, Exhibit 4.1)
4.2	Second Supplemental Indenture, dated as of April 2, 2018, by and among Legacy Reserves LP, Legacy Reserves Inc., Legacy Reserves GP, LLC, Legacy Reserves Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 6.625% Senior Notes due 2021) (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed April 2, 2018, Exhibit 4.2)
10.1	~~Ninth~~Stipulation ~~Amendment to Third Amended~~ and ~~Restated~~Agreement ~~Credit~~of ~~Agreement~~Settlement, dated asJuly ~~of March 23~~6, 2018, by and among Legacy Reserves Inc., Legacy Reserves LP, asLegacy ~~borrower~~Reserves GP, LLC, the ~~guarantors~~other ~~named~~released ~~therein~~parties thereto, ~~Wells~~plaintiff ~~Fargo~~Jeffrey ~~Bank~~Doppelt, ~~National~~the ~~Association,~~members of the Settlement Class (as ~~administrative~~defined ~~agent~~therein), and the ~~lenders~~other ~~signatory~~releasing parties thereto (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed ~~March~~on 26July 12, 2018, Exhibit 10.1)
10.2	Fourth Amendment to Term Loan Credit Agreement, dated as of March 23, 2018, by and among Legacy Reserves LP, Cortland Capital Market Services LLC and the lenders party thereto (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed March 26, 2018, Exhibit 10.2)
10.3	Amended and Restated Director Nomination Agreement, dated as of March 23, 2018, by and among Legacy Reserves GP, LLC, Legacy Reserves Inc. and GSO Capital Partners LP (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed March 26, 2018, Exhibit 10.3)
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 Extension Definition Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document

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101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document

* Filed herewith

** Filed electronically herewith.

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SIGNATURES

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

	LEGACY RESERVES LP By: Legacy Reserves GP, LLC, its General Partner
May 2, 2018	By:	/s/ James Daniel Westcott
August 7, 2018	By:	/s/ James Daniel Westcott
		James Daniel Westcott
		President and Chief Financial Officer
		(On behalf of the Registrant and as Principal Financial Officer)

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