Legacy Reserves 10Q 2018 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 1-38668

Legacy Reserves Inc.

(Exact name of registrant as specified in its charter)


Delaware						82-4919553
(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

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

106,442,278 shares of common stock, par value $0.01, were outstanding as of October 29, 2018.

TABLE OF CONTENTS


		Page
	Glossary of Terms	3

	Part I - Financial Information
Item 1.	Financial Statements.
	Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017 (Unaudited).	6
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017 (Unaudited).	8
	Condensed Consolidated Statement of Stockholders' Deficit / Partners' Deficit for the nine months ended September 30, 2018 (Unaudited).	9
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017 (Unaudited).	10
	Notes to Condensed Consolidated Financial Statements (Unaudited).	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	52
Item 4.	Controls and Procedures.	52
	Part II - Other Information
Item 1.	Legal Proceedings.	54
Item 1A.	Risk Factors.	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	68
Item 6.	Exhibits.	69
	Signatures	70

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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.

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NYMEX. New York Mercantile Exchange.

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

Page 4

calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural gas prices in recent years have increased the economic life of reserves, adding additional reserves with no required capital expenditures. On the other hand, increases in oil and natural gas prices have increased the cost of reserve purchases and reserves added through development projects. The reserve replacement cost may not be indicative of the economic value added of the reserves due to differing lease operating expenses per barrel and differing timing of production.

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%. Standardized measure does not give effect to derivative transactions. Standardized measure presented for periods prior to September 20, 2018 does not take into account provision for federal or state income tax because we were a limited partnership that allocated our taxable income to our unitholders and therefore will not be directly comparable to standardized measure presented for future periods.

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.

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Part I – FINANCIAL INFORMATION

Item 1. Financial Statements.

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


ASSETS
	September 30, 2018		December 31, 2017
	(In thousands)
Current assets:
Cash	$	3,305	$	1,246
Accounts receivable, net:
Oil and natural gas	61,109		62,755
Joint interest owners	14,516		27,420
Other	2		2
Fair value of derivatives (Notes 8 and 9)	19,228		13,424
Prepaid expenses and other current assets (Note 1)	10,231		7,757
Total current assets	108,391		112,604
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	3,497,024		3,529,971
Unproved properties	28,897		28,023
Accumulated depletion, depreciation, amortization and impairment	(2,192,877)		(2,204,638)
	1,333,044		1,353,356
Other property and equipment, net of accumulated depreciation and amortization of $12,179 and $11,467, respectively	2,464		2,961

Operating rights, net of amortization of $6,034 and $5,765, respectively	983		1,251
Fair value of derivatives (Notes 8 and 9)	3,183		14,099
Other assets	3,671		8,811

Total assets	$	1,451,736	$	1,493,082

See accompanying notes to condensed consolidated financial statements.

Page 6

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


LIABILITIES AND STOCKHOLDERS' DEFICIT / PARTNERS' DEFICIT
	September 30, 2018		December 31, 2017
	(In thousands)
Current liabilities:
Current debt, net (Notes 1 and 2)	$	527,391	$	—
Accounts payable	7,838		13,093
Accrued oil and natural gas liabilities (Note 1)	83,216		81,318
Fair value of derivatives (Notes 8 and 9)	39,072		18,013
Asset retirement obligation (Note 10)	3,214		3,214
Other	43,163		29,172
Total current liabilities	703,894		144,810
Long-term debt, net (Notes 1 and 2)	755,784		1,346,769
Asset retirement obligation (Note 10)	261,260		271,472
Fair value of derivatives (Notes 8 and 9)	12,114		1,075
Other long-term liabilities	641		643
Total liabilities	1,733,693		1,764,769
Commitments and contingencies (Note 7)
Stockholders' deficit / partners' deficit (Note 11):
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2017	$	—	$	55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2017	—		174,261
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2017	—		30,814
Limited partners' deficit - 72,594,620 units issued and outstanding at December 31, 2017	—		(531,794)
General partner's deficit (approximately 0.02%)	—		(160)
Common stock, $0.01 par value; 945,000,000 shares authorized, 106,113,000 shares outstanding at September 30, 2018	1,061		—
Additional paid-in capital	13,471		—
Accumulated deficit	(296,489)		—
Total stockholders' deficit	(281,957)		(271,687)
Total liabilities and stockholders' deficit / partners' deficit	$	1,451,736	$	1,493,082

See accompanying notes to condensed consolidated financial statements.

Page 7

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		2017		2018		2017
	(In thousands, except per share data)
Revenues:
Oil sales	$	98,779	$	59,060	$	291,989	$	154,298
Natural gas liquids (NGL) sales	7,771		6,720		20,902		16,691
Natural gas sales	38,657		41,035		109,076		128,220
Total revenues	$	145,207	$	106,815	$	421,967	$	299,209

Expenses:
Oil and natural gas production	$	51,304	$	42,079	$	148,702	$	138,098
Production and other taxes	7,721		5,475		22,705		13,779
General and administrative	17,778		10,023		64,364		29,156
Depletion, depreciation, amortization and accretion	39,588		33,715		114,274		90,200
Impairment of long-lived assets	18,994		14,665		54,375		24,548
(Gains) losses on disposal of assets	7,368		(2,034)		(14,172)		3,491
Total expenses	$	142,753	$	103,923	$	390,248	299,272

Operating income (loss)	$	2,454	$	2,892	$	31,719	$	(63)

Other income (expense):
Interest income	$	16	$	35	$	31	$	44
Interest expense (Notes 2, 8 and 9)	(29,383)		(23,621)		(85,340)		(64,368)
Gain on extinguishment of debt (Note 2)	12,107		—		63,800		—
Equity in income (loss) of equity method investees	(30)		—		(10)		12
Net gains (losses) on commodity derivatives (Notes 8 and 9)	(30,867)		(13,309)		(41,886)		35,876
Other	350		403		623		765
Loss before income taxes	$	(45,353)	$	(33,600)	$	(31,063)	$	(27,734)
Income tax expense	(2,499)		(266)		(3,116)		(837)
Net loss	$	(47,852)	$	(33,866)	$	(34,179)	$	(28,571)



Loss per share / unit - basic & diluted (Note 11)	$	(0.46)	$	(0.34)	$	(0.33)	$	(0.29)

Weighted average number of shares / units used in computing net loss per share / unit -
Basic	104,637		100,206		104,336		99,985
Diluted	104,637		100,206		104,336		99,985

See accompanying notes to condensed consolidated financial statements.

Page 8

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' DEFICIT / PARTNERS' DEFICIT

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(UNAUDITED)


	Series A Preferred Equity				Series B Preferred Equity					Incentive Distribution Equity					Partners' Deficit									Stockholders' Deficit
	Units	Amount		Units	Amount		Units	Amount		LP Units	Limited Partner Amount		General Partner Amount		Shares	Par Value		APIC		Acc. Deficit		Total Deficit
	(In thousands)
Balance, December 31, 2017	2,300	$	55,192	7,200	$	174,261	100	$	30,814	72,595	$	(531,794)	$	(160)	—	$	—	$	—	$	—	$	—
Units issued to Legacy Board of Directors for services	—	—		—	—		—	—		60	522		—		20	—		100		—		100

Unit-based compensation	—	—		—	—		—	—		—	3,934		—		—	—		—		—		—
Vesting of restricted and phantom units	—	—		—	—		—	—		339	—		—		1,550	—		—		—		—


Units issued in exchange for Standstill Agreement	—	—		—	—		—	—		3,800	5,928		—		—	—		—		—		—
Debt exchange	—	—		—	—		—	—		—	—		—		105	1		16,544		—		16,545
Corporate Reorganization	(2,300)	(55,192)		(7,200)	(174,261)		(100)	(30,814)		(76,794)	521,410		160		104,438	1,060		(3,173)		(262,310)		(264,423)
Net loss	—	—		—	—		—	—		—	—		—		—	—		—		(34,179)		(34,179)
Balance, September 30, 2018	—	$	—	—	$	—	—	$	—	—	$	—	$	—	106,113	$	1,061	$	13,471	$	(296,489)	$	(281,957)

See accompanying notes to condensed consolidated financial statements.

Page 9

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Nine Months Ended September 30,
	2018		2017
	(In thousands)
Cash flows from operating activities:
Net loss	$	(34,179)	$	(28,571)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	114,274		90,200
Amortization of debt discount and issuance costs	16,449		5,624
Gain on extinguishment of debt	(63,800)		—
Impairment of long-lived assets	54,375		24,548
(Gain) loss on derivatives	41,203		(36,790)
Equity in (income) loss of equity method investees	10		(12)

Unit-based compensation	16,430		4,345
(Gains) losses on disposal of assets	(14,172)		3,491
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, oil and natural gas	1,646		(3,503)
Decrease in accounts receivable, joint interest owners	12,904		3,957
Decrease in accounts receivable, other	—		2
Increase in other assets	2,666		(808)
Decrease in accounts payable	(5,255)		(3,481)
Increase (decrease) in accrued oil and natural gas liabilities	11,801		(642)
Decrease in other liabilities	4,862		14,501
Total adjustments	193,393		101,432
Net cash provided by operating activities	159,214		72,861
Cash flows from investing activities:
Investment in oil and natural gas properties	(185,302)		(254,505)

Proceeds associated with sale of assets	35,231		5,556
Investment in other equipment	(270)		(481)
Corporate Reorganization	(3,120)		—
Net cash settlements (paid) received on commodity derivatives	(3,992)		17,779
Net cash used in investing activities	(157,453)		(231,651)
Cash flows from financing activities:
Proceeds from long-term debt	524,626		437,000
Payments of long-term debt	(496,384)		(270,000)
Payments of debt issuance costs	(27,941)		(3,217)



Net cash provided by financing activities	301		163,783
Net increase in cash and cash equivalents	2,062		4,993
Cash, beginning of period (1)	4,454		5,758
Cash, end of period (1)	$	6,516	$	10,751
Non-cash investing and financing activities:
Asset retirement obligation costs and liabilities	$	45	$	—
Asset retirement obligations associated with properties sold	$	(18,251)	$	(8,404)
Asset retirement obligations associated with property acquisitions	$	157	$	62
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	$	(9,902)	$	45,498
Issuance of Convertible Notes in exchange for Senior Notes	$	16,544	$	—

See accompanying notes to condensed consolidated financial statements.

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

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LEGACY RESERVES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) Summary of Significant Accounting Policies

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

Unless the context requires otherwise or unless otherwise noted, all references to “Legacy Reserves,” “Legacy Inc.,” “Legacy,” the “Company,” “we,” “us,” “our” or like terms are to Legacy Reserves Inc. and its subsidiaries for the periods after September 20, 2018, the date the Corporate Reorganization was consummated (as defined below). For the periods prior to September 20, 2018, unless the context requires otherwise or unless otherwise noted, all references to “Legacy Reserves,” “Legacy LP,” “Legacy,” the “Company,” “we,” “us,” “our” or like terms are to Legacy Reserves LP and its subsidiaries.

Legacy is an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Its current operations are focused on the horizontal development of unconventional plays in the Permian Basin and the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions.

The accompanying condensed consolidated financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. These condensed consolidated financial statements as of September 30, 2018 and for the three and nine months ended September 30, 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, that 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 conjunction with the consolidated financial statements and notes thereto included in Legacy LP's Annual Report on Form 10-K for the year ended December 31, 2017.

(b) Corporate Reorganization and Recent Developments

On September 20, 2018, we completed the previously announced transactions contemplated by the Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”), dated July 9, 2018, by and among Legacy Inc., Legacy LP, Legacy Reserves GP, LLC (the “General Partner”) and Legacy Reserves Merger Sub LLC, a wholly owned subsidiary of Legacy Inc. (“Merger Sub”), and the GP Purchase Agreement, dated March 23, 2018, by and among Legacy Inc., the General Partner, Legacy LP, Lion GP Interests, LLC, Moriah Properties Limited, and Brothers Production Properties, Ltd., Brothers Production Company, Inc., Brothers Operating Company, Inc., J&W McGraw Properties, Ltd., DAB Resources, Ltd. and H2K Holdings, Ltd. (such transactions referred to herein collectively as the “Corporate Reorganization”). Upon the consummation of the Corporate Reorganization:

• Legacy Inc., which prior to the Corporate Reorganization, was a wholly owned subsidiary of the General Partner, acquired all of the issued and outstanding limited liability company interests in the General Partner and became the sole member of the General Partner with the General Partner becoming a subsidiary of Legacy Inc.; and

• Legacy LP merged with Merger Sub, with Legacy LP continuing as the surviving entity and as a subsidiary of Legacy Inc. (the “Merger”), the limited partner interests of Legacy LP, other than the incentive distribution units in Legacy LP, were exchanged for shares of Legacy Inc.’s common stock, par value $0.01 (“common stock”) and the general partner interest remained outstanding.

On September 20, 2018 Legacy LP and Legacy Reserves Finance Corporation exchanged (i) $21.004 million aggregate principal amount of 8% Senior Notes Due 2020 (the “2020 Senior Notes”) for $21.004 million aggregate principal amount of new 8% Convertible Senior Notes due 2023 (the “2023 Convertible Notes”) and 105,020 shares of common stock, par value $0.01 (“common stock”), of Legacy Inc., and (ii) $109 million aggregate principal amount of 6.625% Senior Notes due 2021 (the “2021 Notes”) for $109 million aggregate principal amount of 2023 Convertible Notes. See "—Footnote 2—Debt" for further discussion.

Page 11

Legacy LP's 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 maturity date and Legacy believes that the consummation of the Corporate Reorganization has improved 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 LP's existing Credit Agreement.

Below are the components of accrued oil and natural gas liabilities as of September 30, 2018 and December 31, 2017:


	September 30, 2018		December 31, 2017
	(In thousands)
Accrued capital expenditures	$	23,296	$	33,198
Accrued lease operating expense	21,787		18,179
Revenue payable to joint interest owners	22,741		18,510
Accrued ad valorem tax	9,748		5,807
Other	5,644		5,624
	$	83,216	$	81,318

(d) Restricted Cash

Restricted cash on our Consolidated Balance Sheet as of September 30, 2018 and December 31, 2017 is $3.2 million and is included 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 at commencement longer than twelve months. Legacy has engaged a third party consultant to assist with its implementation of ASU 2016-02. Leases will be classified as either finance or operating, with that 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. Legacy expects to adopt ASU 2016-02 retrospectively in the first quarter of 2019 (that is, the period of adoption) through a cumulative-effect adjustment to the opening balance of retained earnings.

Legacy commonly enters into lease agreements in support of its operations for assets such as office space, vehicles, drilling rigs, compressors and other well equipment. In its efforts to further determine the impact of ASU 2016-02, Legacy developed an implementation approach that 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 and performing a detailed review of material contracts identified through that analysis. Although its impact assessment is currently ongoing, Legacy believes it is likely that the new guidance will impact its consolidated balance sheet due to the recognition of right-of-use assets and lease liabilities that are not recognized under currently effective guidance (for example, operating leases). Legacy is further evaluating the impacts that ASU 2016-02 may have on its disclosures, existing accounting policies and internal controls, as well as financial lease accounting system solutions to facilitate compliance with ASU 2016-02.

Upon transition, Legacy plans to apply the package of practical expedients provided in ASU 2016-02 that allow companies, among other things, to not reassess contracts that commenced prior to adoption. In addition, Legacy expects to utilize the practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under currently effective lease accounting guidance.

(f) Income Taxes

Prior to consummation of the Corporate Reorganization on September 20, 2018, Legacy LP was treated as a partnership for federal and state income tax purposes, in which the taxable income or loss was passed through to its unitholders. Legacy LP was subject to Texas margin tax and certain of Legacy LP’s subsidiaries were c-corporations subject to federal and state income

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taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, Legacy LP did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for its operations.

Effective upon consummation of the Corporate Reorganization, Legacy Inc. became subject to federal and state income taxes as a c-corporation. As such, we account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income or loss in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2018, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

(2) Debt

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


	September 30,		December 31,
	2018		2017
	(In thousands)
Current debt
Credit Facility due 2019	$	529,000	$	—
Unamortized debt issuance costs	(1,609)		—
Total current debt, net	$	527,391	—

Long-term debt
Credit Facility due 2019	$	—	$	499,000
Second Lien Term Loans due 2020	338,626		205,000
8% Senior Notes due 2020	211,985		232,989
6.625% Senior Notes due 2021	136,579		432,656
8% Convertible Senior Notes due 2023	130,004		—
	$	817,194	$	1,369,645
Unamortized discount on Second Lien Term Loans and Notes	(39,125)		(13,101)
Unamortized debt issuance costs	(22,285)		(9,775)
Total long-term debt, net	$	755,784	$	1,346,769
Total debt, net	$	1,283,175	$	1,346,769

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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 “Credit Agreement”). Borrowings under the Credit Agreement mature on April 1, 2019. Legacy's obligations under the 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 and Legacy's ownership interests in the General Partner. Concurrently with the Corporate Reorganization, the General Partner and Legacy Inc. provided guarantees of Legacy LP's obligations under the Credit Agreement. 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 fall 2018 redetermination. The borrowing base is subject to semi-annual redeterminations on or about April 1 and October 1 of each year, but no redeterminations are scheduled between now and maturity on April 1, 2019. 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 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 Credit Agreement so long as it does not increase the borrowing base then in effect.

Prior to the Corporate Reorganization, the Credit Agreement contained a covenant that prohibited 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 were available was greater than 4.00 to 1.00 or (ii) Legacy had unused lender commitments of less than or equal to 15% of the total lender commitments then in effect. Following the consummation of the Corporate Reorganization, the Credit Agreement contains a covenant that prohibits Legacy from paying dividends to its stockholders, 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 3.00 to 1.00 or (ii) Legacy has unused lender commitments of less than or equal to 20% of the total lender commitments then in effect.

The 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;

• 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

• 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 commodity derivative 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.

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On September 14, 2018 and September 20, 2018, Legacy entered into the Tenth Amendment and Eleventh Amendment, respectively, to the Credit Agreement (the “Credit Agreement Amendments”). The Credit Agreement Amendments amend certain provisions set forth in the Credit Agreement to, among other items:

• permit the issuance of the 2023 Convertible Notes;

• provide that the 2023 Convertible Notes constitute debt that is permitted refinancing debt;

• allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common stock; and

• permit the redemption of certain senior notes or permitted refinancing debt of such senior notes with any combination of the following: (i) proceeds of certain permitted refinancing debt; (ii) net cash proceeds of any sale of equity interests (other than disqualified capital stock) of Legacy Inc.; and/or (iii) in exchange for equity interests (other than disqualified capital stock) of Legacy Inc.

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

As of September 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 Credit Agreement. On October 31, 2018, Legacy received a waiver with respect to compliance with such covenant for the fiscal quarter ended September 30, 2018. Except with respect to compliance with the financial covenant that has been waived, as of September 30, 2018, Legacy was in compliance with all financial and other covenants of the Credit Agreement. Depending on future oil and natural gas prices, Legacy could breach certain financial covenants under its Credit Agreement, which would constitute a default under its 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 Credit Agreement and potential foreclosure on its oil and natural gas properties. If the lenders under Legacy's Credit Agreement were to accelerate the indebtedness under its 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"), its 6.625% Senior Notes due 2021 (the "2021 Senior Notes") and its 8% Convertible Senior Notes due 2023 (the "2023 Convertible Notes" and, together with the 2020 Senior Notes and the 2021 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.

As of September 30, 2018, Legacy had approximately $529 million drawn under the Credit Agreement at a weighted-average interest rate of 5.15%, leaving approximately $45.2 million of availability under the Credit Agreement. For the nine-month period ended September 30, 2018, Legacy paid in cash $19.2 million of interest expense on the Credit Agreement.

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Second Lien Term Loan Credit Agreement

On October 25, 2016, Legacy entered into a Second Lien Term Loan Credit Agreement (as amended, the "Term Loan Credit Agreement") among Legacy, as borrower, Cortland Capital Market Services LLC ("Cortland"), 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 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 L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The 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 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 Credit Agreement. In addition, upon consummation of the Corporate Reorganization, the General Partner and Legacy Inc. became guarantors. As of September 30, 2018, Legacy had approximately $338.6 million drawn under the Term Loan Credit Agreement. On December 31, 2017, Legacy entered into the Third Amendment to the Term Loan Credit Agreement (the "Third Amendment") among Legacy, as borrower, Cortland, 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 September 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.

Prior to the Corporate Reorganization, the Term Loan Credit Agreement contained a covenant that prohibited 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 were available was greater than 4.00 to 1.00 or (ii) Legacy had unused lender commitments of less than or equal to 15% of the total lender commitments then in effect. Following consummation of the Corporate Reorganization, the Term Loan Credit Agreement contains a covenant that prohibits Legacy from paying dividends to the stockholders, 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 3.00 to 1.00 or (ii) Legacy has unused lender commitments of less than or equal to 20% of the total lender commitments then in effect.

The 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 commodity derivative 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 September 14, 2018 and September 20, 2018, Legacy entered into the Fifth Amendment and Sixth Amendment, respectively, to the Term Loan Credit Agreement (the “Term Loan Amendments”). The Term Loan Amendments amend certain provisions set forth in the Term Loan Credit Agreement to, among other items:

• permit the issuance of the 2023 Convertible Notes;

• provide that the 2023 Convertible Notes constitute debt that is permitted refinancing debt;

• allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common stock; and

Page 16

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

As of September 30, 2018, Legacy was in compliance with all financial and other covenants of the 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 (together, the "Issuers") 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. The Issuer's obligations under the 2020 Senior Notes are guaranteed by Legacy Inc., the General Partner, and Legacy LP's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services LLC, Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC (collectively, the "Guarantors"). 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 14—Guarantors" for further details on Legacy's guarantors.

The indenture governing the 2020 Senior Notes (as supplemented, the "2020 Notes Indenture") limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions or dividends 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 securities; (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 2020 Notes Indenture also includes customary events of default. Legacy is in compliance with all financial and other covenants of the 2020 Senior Notes. However, if the lenders under Legacy's Credit Agreement were to accelerate the indebtedness under Legacy's 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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In connection with the exchange of approximately $21.0 million aggregate principal amount of 2020 Senior Notes for the same aggregate principal of the 2023 Convertible Notes and the issuance of 105,020 shares of Common Stock in September 2018, Legacy recognized a $1.4 million gain on extinguishment of debt, which consisted of the difference between (1) the face amount of the exchanged 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the new 2023 Convertible Notes.

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

As of September 30, 2018, there was $212.0 million of 2020 Senior Notes outstanding.

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

On May 28, 2013, the Issuers 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, the Issuers 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 the 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

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. Legacy 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, Legacy entered into the Second Supplemental Indenture (the “2021 Notes Supplemental Indenture”) to the initial indenture governing the 2021 Notes (the "2021 Notes Indenture").

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

On December 31, 2017, Legacy entered into a definitive agreement with certain funds managed by Fir Tree Partners 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.

In connection with the exchange of approximately $109.0 million aggregate principal amount of 2021 Senior Notes for the same aggregate principal of the 2023 Convertible Notes, Legacy recognized a $10.7 million gain on extinguishment of debt, which consisted of the difference between (1) the face amount of the exchanged 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the new 2023 Convertible Notes.

As of September 30, 2018, there was $136.6 million of 2021 Senior Notes outstanding.

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8% Convertible Senior Notes Due 2023 ("2023 Convertible Notes")

On September 20, 2018, the Issuers, completed private exchanges with certain holders of senior notes, pursuant to which the Issuers exchanged (i) $21.004 million aggregate principal amount of 2020 Senior Notes for $21.004 million aggregate principal amount of 2023 Convertible Notes and 105,020 shares of common stock and (ii) $109.000 million aggregate principal amount of 2021 Senior Notes for $109.000 million aggregate principal amount of 2023 Convertible Notes. The 2023 Convertible Notes were issued pursuant to an Indenture, dated as of September 20, 2018 (the “2023 Convertible Note Indenture”)

Upon issuance, the Company separately accounted for the liability and equity components in accordance with Accounting Standards Codification 470-20. The initial fair value of the 2023 Convertible Notes in its entirety (inclusive of the equity component related to the conversion option) was estimated using observable inputs such as trades that occurred on the day of the transaction. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the aggregate principal amount of the 2023 Convertible Notes and the fair value of the liability component was recorded as a debt discount and is being amortized to interest expense over the term of the notes using the effective interest method. The fair value of the liability component of the 2023 Convertible Notes was estimated at $101 million, resulting in a debt discount of $29 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial fair value of the 2023 Convertible Notes. The equity component was recorded in additional paid-in capital within stockholders’ equity and will not be remeasured as long as it continues to meet the conditions for equity classification.

The 2023 Convertible Notes mature on September 20, 2023, unless earlier repurchased or redeemed by the Issuers or converted. On or before December 1, 2018, the 2023 Convertible Notes are subject to redemption for cash, in whole or in part, at the Issuers’ option, at a redemption price equal to 102% of the principal amount of the 2023 Convertible Notes to be redeemed, plus any accrued and unpaid interest. Thereafter, the 2023 Convertible Notes are subject to redemption for cash, in whole or in part, at the Issuers’ option at a redemption price equal to 100% of the 2023 Convertible Notes to be redeemed, plus any accrued and unpaid interest. In addition, the Issuers are required to make an offer to holders of the 2023 Convertible Notes upon a change of control at a price equal to 101%, plus any accrued and unpaid interest, and an offer to holders of the 2023 Convertible Notes upon consummation by the Issuers or any restricted subsidiaries of certain asset sales at a price equal to 100%, plus any accrued and unpaid interest.

The 2023 Convertible Notes are convertible into shares of common stock at an initial conversion rate of 166.6667 shares per $1,000 principal amount of 2023 Convertible Notes, which is equal to an initial conversion price of $6.00 per share of common stock (the "Conversion Price").

The 2023 Convertible Notes are convertible, at the option of the holders, into shares of common stock at any time from the date of issuance up until the close of business on the earlier of (i) the business day prior to the date of a mandatory conversion notice, (ii) with respect to a 2023 Convertible Note called for redemption, the business day immediately preceding the redemption date or (iii) the business day immediately preceding the maturity date. In addition, if a holder exercises its right to convert on or prior to September 19, 2019, such holder will receive an early conversion payment, in cash, per $1,000 principal amount as follows:


Early Conversion Date						Early Conversion Payment
September 20, 2018 through November 30, 2018						$80.00
December 1, 2018 through May 31, 2019						$64.22
June 1, 2019 through September 19, 2019						$24.22

Subject to compliance with certain conditions, the Issuers have the right to mandatorily convert all of the 2023 Convertible Notes if the volume weighted average price of the common stock equals or exceeds the conversion price for at least 20 trading days (whether or not consecutive) during any period of 30 consecutive trading days commencing on or after the initial issuance date.

The 2023 Convertible Notes are guaranteed by Legacy Inc., the General Partner, Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services LLC, Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC.

The terms of the 2023 Convertible Notes, including the Guarantors, are substantially identical to the terms of the 2020 Senior Notes and 2021 Senior Notes with the exception of the interest rate, conversion and redemption provisions noted above.

Page 19

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

As of September 30, 2018, there was $130.0 million of 2023 Convertible Notes outstanding.

(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.

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


	Three Months Ended 9/30/2018										Nine Months Ended 9/30/2018
	Under ASC 606		Under ASC 605		Change		Under ASC 606		Under ASC 605		Change
	(In thousands)
Revenues:
Oil Sales	$	98,779	$	98,799	$	(20)	$	291,989	$	292,178	$	(189)
Natural gas liquids (NGL) sales	7,771		7,892		(121)		20,902		21,335		(433)
Natural gas sales	38,657		40,251		(1,594)		109,076		113,836		(4,760)
	$	145,207	$	146,942	$	(1,735)	$	421,967	$	427,349	$	(5,382)
Costs and expenses:
Oil and natural gas production	$	51,304	$	53,039	$	(1,735)	$	148,702	$	154,084	$	(5,382)

Net income (loss)	$	(47,852)	$	(47,852)	$	—	$	(34,179)	$	(34,179)	$	—

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.

(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 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.

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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.

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		Nine Months Ended
	September 30,
	2018		2018
	(In thousands)
Revenues:
Oil sales	$	98,779	$	291,989
Natural gas liquids (NGL) sales	7,771		20,902
Natural gas sales	38,657		109,076
Total revenues	$	145,207	$	421,967

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

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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.

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 September 30, 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 the nine months ended September 30, 2018, Legacy divested certain individually immaterial oil and natural gas assets for net cash proceeds of $35.2 million. These dispositions were treated as asset sales and resulted in a gain on disposition of assets of $14.2 million during the period.

(6) Related Party 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, a director of Legacy, and Dale A. Brown, a prior director of the General Partner, are principals. Legacy has contracted with Blue Quail to provide water transfer services and paid $137,397 and $9,758 in the nine month periods ended September 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.

On September 20, 2018, we completed the previously announced transactions contemplated by the Merger Agreement, and the GP Purchase Agreement, dated March 23, 2018, by and among Legacy Inc., the General Partner, Legacy LP, Lion GP Interests, LLC, Moriah Properties Limited, and Brothers Production Properties, Ltd., Brothers Production Company, Inc., Brothers Operating Company, Inc., J&W McGraw Properties, Ltd., DAB Resources, Ltd. and H2K Holdings, Ltd. Upon the consummation of the Corporate Reorganization:

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• Legacy LP merged with Merger Sub, with Legacy LP continuing as the surviving entity and as a subsidiary of Legacy Inc., the limited partner interests of Legacy LP, other than the incentive distribution units in Legacy LP, were exchanged for shares of Legacy Inc.’s common stock and the general partner interest remained outstanding.

(7) Commitments and Contingencies

On March 28, 2018, a purported holder of Legacy LP’s Preferred Units filed a putative class action challenging the Merger against Legacy LP, the General Partner and Legacy Inc. (the “Doppelt Action”). The Doppelt Action contained two causes of action challenging the Merger, including breach of the Fifth Amended and Restated Agreement of Limited Partnership of Legacy LP (the “Partnership Agreement”) and breach of the implied covenant of good faith and fair dealing. The plaintiff in the Doppelt Action sought 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 Legacy LP 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 Legacy LP, the General Partner and Legacy Inc. (the “Chammah Ventures Action”). The Chammah Ventures Action contained the same causes of action and that plaintiff sought 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 occurred on June 4, 2018. A third putative class action lawsuit challenging the Merger was filed against Legacy LP, the General Partner, Legacy Inc. and Merger Sub on April 27, 2018, by Patrick Irish in the District Court in Midland County, Texas (the “Irish Action”). The Irish Action contained the same general causes of action as the initial complaint filed in the Consolidated Action and sought the same relief.

On June 22, 2018, Legacy LP, Legacy Inc., 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. On September 12, 2018, the Court held a settlement fairness hearing, during which it considered (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. Following the hearing, the Court entered an order and final judgment (the “Final Order”) approving the Settlement Agreement in full. The Final Order granted holders of Series A Preferred Units and Series B Preferred Units approximately 10,730,000 shares of common stock in Legacy Inc. 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) agreed to release Legacy LP, the General Partner and Legacy Inc., 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 was also dismissed with prejudice. Each of the administrative agent for the Credit Agreement and the majority lenders under the Term Loan Credit Agreement consented to the terms of the Settlement Agreement, as required pursuant to the terms of the Credit Agreement and the Term Loan Credit Agreement, respectively. The deadline for any appeal of the Final Order to be filed expired on October 12, 2018. Additionally, on September 20, 2018, the plaintiff in the Irish Action voluntarily dismissed his action with prejudice as a result of the entry of the Final Order.

Legacy is also, from time to time, involved in litigation and claims arising out of its operations in the normal course of business, including regulatory and environmental matters, none of which are expected to be material. 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.

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

Legacy has employment agreements with its officers. 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.

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(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.

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Fair Value on a Recurring Basis

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 September 30, 2018 and December 31, 2017. Legacy nets the fair value of derivative instruments by counterparty in its consolidated balance sheets.


	September 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	$	—	$	13,398	$	16,711	$	30,109	$	(13,681)	$	16,428
Interest rate derivatives	—		2,800		—		2,800		—		2,800
Noncurrent
Commodity derivatives	—		3,790		409		4,199		(1,016)		3,183
Interest rate derivatives	—		—		—		—		—		—

Liabilities:
Current
Commodity derivatives	—		(52,697)		(56)		(52,753)		13,681		(39,072)

LTIP liability(a)	—		(13,820)		—		(13,820)		—		(13,820)
Noncurrent
Commodity derivatives	—		(12,123)		(1,007)		(13,130)		1,016		(12,114)


Net fair value instruments	$	—	$	(58,652)	$	16,057	$	(42,595)	$	—	$	(42,595)

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	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(a)	—		(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 share-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 commodity derivatives 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 Legacy’s derivative contracts. The risk of nonperformance by Legacy’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 Legacy’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.

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


	Significant Unobservable Inputs
	(Level 3)
	Three Months Ended September 30,						Nine Months Ended September 30,

	2018		2017		2018		2017
	(In thousands)
Beginning balance	$	31,616	$	630	$	(5,088)	$	8
Total gains (losses)	(3,720)		(2,159)		36,696		(1,667)
Settlements, net	(11,839)		(166)		(15,551)		(36)
Ending balance	$	16,057	$	(1,695)	$	16,057	$	(1,695)
Gains (losses) included in earnings relating to derivatives still held as of September 30, 2018 and 2017	$	(5,630)	$	(1,676)	$	17,680	$	(1,921)

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 Legacy'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 10.

Nonrecurring fair value measurements of proved oil and natural gas properties during the nine-month period ended September 30, 2018 consist of:

Fair Value Measurements During the Nine Months Ended September 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)

—

39,307

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a. Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the nine-month period ended September 30, 2018, Legacy incurred impairment charges of $54.4 million as oil and natural gas properties with a net cost basis of $93.7 million were written down to their fair value of $39.3 million. Of these amounts, impairment charges of $18.2 million were incurred as oil and natural gas properties held-for-sale at September 30, 2018 with a net cost basis of $30.7 million were written down to their fair value of $12.5 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 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 $529 million as of September 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 September 30, 2018, the fair values of the 2020 Senior Notes, the 2021 Senior Notes and the 2023 Convertible Notes were $186.5 million, $115.6 million and $117.0 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.

In September 2018, Legacy issued convertible notes that contained debt holder conversion options which Legacy determined were not clearly and closely related to the debt host contracts, and Legacy therefore separated these embedded features and reflected them at fair value in the consolidated financial statements. Prior to their settlements, the fair values of these embedded derivatives was determined using the fair value of the liability component and the fair value of the 2023 Convertible Notes based on public trades. The fair value of these embedded derivatives was determined to be $16.1 million. As of September 30, 2018, there was $130.0 million of 2023 Convertible Notes outstanding.

(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.

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The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the three and nine months ended September 30, 2018 and 2017:


	Three Months Ended September 30,						Nine Months Ended September 30,

	2018		2017		2018		2017
	(In thousands)
Beginning fair value of commodity derivatives	$	508	$	51,076	$	6,318	$	12,698
Total gain (loss) - oil derivatives	(31,325)		(11,403)		(39,149)		11,373
Total gain (loss) - natural gas derivatives	458		(1,906)		(2,737)		24,503
Crude oil derivative cash settlements paid (received)	1,702		(3,102)		12,905		(9,800)
Natural gas derivative cash settlements received	(2,919)		(3,870)		(8,913)		(7,979)
Ending fair value of commodity derivatives	$	(31,576)	$	30,795	$	(31,576)	$	30,795

As of September 30, 2018, Legacy had the following NYMEX West Texas Intermediate ("WTI") crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:


		Average	Price
Time Period	Volumes (Bbls)	Price per Bbl	Range per Bbl
October-December 2018	763,600	$54.76	$51.20	-	$63.68
2019	3,285,000	$61.33	$57.15	-	$67.65

As of September 30, 2018, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:


		Average	Price
Time Period	Volumes (Bbls)	Price per Bbl	Range per Bbl
October-December 2018	1,012,000	$(1.13)	$(1.25)	-	$(0.80)
2019	1,460,000	$(3.18)	$(5.20)	-	$(1.15)

As of September 30, 2018, Legacy had the following Midland-to-Cushing crude oil differential enhanced swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:


		Average Short	Average Swap
Time Period	Volumes (Bbls)	Call Price per Bbl	Price per Bbl

2019	1,460,000	$70.00	$(2.91)

As of September 30, 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

Time Period

Volumes (Bbls)

Put Price per Bbl

Call Price per Bbl

October-December 2018

391,000

$47.06

$60.29

As of September 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:

Average Long

Average Short

Average

Time Period

Volumes (Bbls)

Put Price per Bbl

Swap Price per Bbl

October-December 2018

32,200

$57.00

$82.00

$90.50

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As of September 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:


		Average	Price
Time Period	Volumes (MMBtu)	Price per MMBtu	Range per MMBtu
October-December 2018	9,080,000	$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 September 30,						Nine Months Ended September 30,

	2018		2017		2018		2017
	(In thousands)
Beginning fair value of interest rate swaps	$	3,084	$	940	$	2,117	$	183
Total gain on interest rate swaps	144		132		1,459		222
Cash settlements (received) paid	(428)		25		(776)		692
Ending fair value of interest rate swaps	$	2,800	$	1,097	$	2,800	$	1,097

The table below summarizes the interest rate swap position as of September 30, 2018:

Weighted Average

Estimated Fair Value at

Notional Amount

Fixed Rate

Effective Date

Maturity Date

September 30, 2018

(Dollars in thousands)

235,000

1.363

9/1/2015

9/1/2019

2,800

(10) 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.

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The following table reflects the changes in the ARO during the nine months ended September 30, 2018 and year ended December 31, 2017:


	September 30, 2018		December 31, 2017
	(In thousands)
Asset retirement obligation - beginning of period	$	274,686	$	272,148
Liabilities incurred with properties acquired	157		62
Liabilities incurred with properties drilled	45		39
Liabilities settled during the period	(1,603)		(1,891)
Liabilities associated with properties sold	(18,251)		(8,464)
Current period accretion	9,440		12,792

Asset retirement obligation - end of period	$	264,474	$	274,686

(11) Stockholders' Deficit / Partners' Deficit

Preferred Units

On September 20, 2018, in connection with the Corporate Reorganization, all of Legacy LP's 8% Series A Fixed-to-Floating Cumulative Redeemable Perpetual Preferred Units and 8.000% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding were converted into shares of common stock.

Incentive Distribution Units

On September 20, 2018, all of Legacy LP's Incentive Distribution Units outstanding were cancelled in connection with the Corporate Reorganization.

Loss per share / unit

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		2017		2018		2017
	(In thousands)
Net loss	$	(47,852)	$	(33,866)	$	(34,179)	$	(28,571)

Weighted average number of shares / units outstanding - basic	104,637		100,206		104,336		99,985
Effect of dilutive securities:
Restricted shares	—		—		—		—
Weighted average number of shares / units outstanding - diluted	104,637		100,206		104,336		99,985
Basic & diluted loss per share / units	$	(0.46)	$	(0.34)	$	(0.33)	$	(0.29)

For the three months ended September 30, 2018, 4,687,324 restricted stock units were excluded from the calculation of diluted loss per share due to their anti-dilutive effect. For the nine months ended September 30, 2018, 4,687,324 restricted stock units were excluded from the calculation of diluted loss per share due to their anti-dilutive effect. For the three and nine months ended September 30, 2017, 260,830 restricted units and 1,389,773 phantom units were excluded from the calculation of diluted loss per share due to their anti-dilutive effect.

(12) Stock-Based Compensation

Legacy LP Long-Term Incentive Plan

On June 12, 2015, the unitholders of Legacy LP 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 September 20, 2018, grants of awards

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net of forfeitures and, in the case of phantom units, historical exercises covering 3,459,197 units had been made, comprised of 266,014 unit option awards, 988,207 restricted unit awards, 1,424,114 phantom unit awards and 780,862 unit awards. Pursuant to the terms of the Corporate Reorganization, the Legacy LP long-term incentive plan ("Legacy LP LTIP") was terminated.

Unit Appreciation Rights

A unit appreciation right ("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 were settled in cash, Legacy accounted for the UARs by utilizing the liability method.

Legacy LP did not issue UARs to employees during the year ended December 31, 2017 or the nine-month period ended September 30, 2018. All outstanding UARs were exercised or forfeited in connection with the Corporate Reorganization.

For the nine-month periods ended September 30, 2018 and 2017, Legacy recorded $(0.2) million and $(0.1) million, 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 September 30, 2018 and 2017 fair value of these UARs (see Note 7). All outstanding UARs vested on September 20, 2018 in connection with the Corporate Reorganization and were subsequently exercised or forfeited.

The cost of employee services in exchange for an award of equity instruments was measured based on a grant-date fair value of the award (with limited exceptions), and that cost was generally 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 were settled in cash, Legacy accounted 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 was recognized based on the change in the liability between periods.

A summary of UAR activity for the nine months ended September 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	$	—

Exercised	(90,844)	4.69

Expired & Forfeited	(631,177)	22.35
Outstanding at September 30, 2018	—	$	—	—	$	—

UARs exercisable at September 30, 2018	—	$	—	—	$	—

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	(124,832)	5.99
Forfeited	(4,667)	5.25
Non-vested at September 30, 2018	—	$	—

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Phantom Units

Legacy LP previously issued phantom units under the Legacy LP 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 accounted for the phantom units settled in Partnership units by utilizing the equity method. Legacy accounted for the phantom units settled in cash by utilizing the liability method. 391,674 Phantom units that settle in cash and 1,032,440 phantom units that settle in units vested on September 20, 2018 in connection with the Corporate Reorganization.

Compensation expense related to the phantom units was $30.7 million and $3.1 million for the nine months ended September 30, 2018 and 2017, respectively. All phantom units vested on September 20, 2018 in connection with the Corporate Reorganization

Restricted Units

Legacy LP previously issued restricted units to certain employees and members of management. All restricted units vested on September 20, 2018 in connection with the Corporate Reorganization.

Compensation expense related to restricted units was $0.8 million and $1.3 million for the nine months ended September 30, 2018 and 2017, respectively.

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 the General Partner'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 units to four non-employee directors who serve on the Board of Directors of Legacy and 6,010 units to two non-employee directors of Legacy LP who do not serve on the Board of Directors of Legacy Inc. The value of each unit was $8.69 at the time of issuance.

Legacy Reserves Inc. 2018 Omnibus Incentive Plan

On September 19, 2018, the Legacy Inc. 2018 Omnibus Incentive Plan (the "Legacy Inc. LTIP") was approved by the former unitholders of Legacy LP in connection with the Corporate Reorganization for it and its affiliates' employees, consultants and directors. The Legacy Inc. LTIP provides for up to 10,500,000 shares (the "Share Reserve") to be used for awards, and that the Share Reserve will increase proportionately by 10% of all shares of common stock issued by Legacy Inc. after the effective date of the Legacy Inc. LTIP and before the first anniversary of the effective date. The awards under the Legacy Inc. LTIP may include stock grants, restricted stock, restricted stock units and stock options. As of September 30, 2018, grants of awards net of forfeitures covering 4,707,444 shares had been made, compromised of 4,687,324 restricted stock units and 20,120 stock awards.

Restricted Stock Units

During the nine months ended September 30, 2018, Legacy issued an aggregate 4,687,324 restricted stock units ("RSUs") to executive employees. The RSUs vest over a three-year period. Compensation expense related to the RSUs was $0.2 million for the nine months ended September 30, 2018. RSUs are accounted for under the equity method

As of September 30, 2018, there was a total of $24.7 million of unrecognized compensation expense related to the unvested portion of these RSUs. At September 30, 2018, this cost was expected to be recognized over a weighted-average period of 3.4 years. Pursuant to the provisions of ASC 718, Legacy’s issued shares, as reflected in the accompanying consolidated balance sheet at September 30, 2018, do not include 4,687,324 shares related to unvested RSUs.

Board Shares

On September 25, 2018, Legacy granted and issued 5,030 shares to four non-employee directors who serve on the Board of Directors of Legacy in accordance with Legacy's director compensation policy. The value of each share was $4.97 at the time of issuance.

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(13) Income Taxes

Effective September 20, 2018, pursuant to the Merger Agreement, Legacy Inc. became subject to federal and state income taxes. Prior to consummation of the Corporate Reorganization, Legacy LP was treated as a partnership for federal and state income tax purposes, in which the taxable income or loss was passed through to its unitholders. Legacy LP was subject to Texas margin tax. In addition, certain of Legacy LP’s subsidiaries were c-corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, Legacy LP did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for its operations.

On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) was enacted into law. The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate income tax rate from 35% to 21%, (2) temporary bonus depreciation that will allow for full expensing of certain qualified property acquired after September 27, 2017, (3) limitations on the maximum deduction for net operating loss (NOL) carryforwards generated in tax years beginning after December 31, 2017, to 80 percent of a taxpayer’s taxable income and (4) limitations on the maximum deduction for net business interest expense in tax years beginning after December 31, 2017, to 30% of the taxpayer’s adjusted taxable income. We have previously reported preliminary amounts for the income effects of the Tax Act for Legacy as of December 31, 2017.

The effective combined U.S. federal and state income tax rates were negative 10.03% and negative 3.02% for the nine months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018, our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax, Texas margins tax, and the valuation allowance. For the nine months ended September 30, 2017, our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax and Texas margins tax. During the nine months ended September 30, 2018, the Legacy Inc. has recorded a full valuation allowance against its deferred tax position. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets will be realized.

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(14) Guarantors

Legacy LP'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. Legacy LP'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. Legacy LP's 2023 Convertible Notes were issued in exchange for portions of the 2020 Senior Notes and 2021 Senior Notes on September 20, 2018. The 2020 Senior Notes, the 2021 Senior Notes and the 2023 Convertible Notes are guaranteed by Legacy LP's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services LLC, 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, 2021 Senior Notes and the 2023 Convertible Notes, the “Subsidiaries”) as well as Legacy Inc. and the General Partner, as parent guarantors (the "Parent Guarantors"). 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.” Legacy LP is 100% owned, directly or indirectly, by the Parent Guarantors and the guarantees by the Parent Guarantors are full and unconditional, except for customary release provisions described in “—Footnote 2—Debt.” Legacy LP 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 and Parent Guarantors.

(15) Subsequent Events

On October 30, 2018 Legacy's borrowing base was reaffirmed at $575.0 million.

On October 31, 2018, the lenders for the Credit Agreement agreed to waive the Partnership’s compliance with the ratio of consolidated current assets to consolidated current liabilities covenant contained in the Credit Agreement for the fiscal quarter ended September 30, 2018. In addition, on October 31, 2018 the Credit Agreement was amended to further tighten certain restrictions relating to cash payments with respect to awards granted in 2018 and prior years under the Legacy LP LTIP and Legacy Inc. LTIP.

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

Cautionary Statement Regarding Forward-Looking Information

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

• our business strategy;

• the amount of oil and natural gas we produce;

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

• our ability to 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;

• the level of our capital expenditures;

• our ability to comply with, renegotiate or receive waivers of debt covenants under our Credit Agreement (as defined below) 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 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 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.

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Recent Developments

On September 20, 2018, we completed the previously announced transactions contemplated by the Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”), dated July 9, 2018, by and among Legacy Inc., Legacy LP, Legacy Reserves GP, LLC (the “General Partner”) and Legacy Reserves Merger Sub LLC (“Merger Sub”), and the GP Purchase Agreement, dated March 23, 2018, by and among Legacy Inc., the General Partner, Legacy LP, Lion GP Interests, LLC, Moriah Properties Limited, and Brothers Production Properties, Ltd., Brothers Production Company, Inc., Brothers Operating Company, Inc., J&W McGraw Properties, Ltd., DAB Resources, Ltd. and H2K Holdings, Ltd. (such transactions referred to herein collectively as the “Corporate Reorganization”). Upon the consummation of the Corporate Reorganization:

On September 20, 2018 Legacy LP and Legacy Reserves Finance Corporation exchanged (i) $21.004 million aggregate principal amount of 8.000% Senior Notes Due 2020 (the “2020 Senior Notes”) for $21.004 million aggregate principal amount of new 8% Convertible Senior Notes due 2023 (the “2023 Convertible Notes”) and 105,020 shares of common stock, par value $0.01 (“common stock”), of Legacy Inc., and (ii) $109.000 million aggregate principal amount of 6.625% Senior Notes due 2021 (the “2021 Notes”) for $109.000 million aggregate principal amount of 2023 Convertible Notes. See "—Footnote 2—Debt" for further discussion.

Our Credit Agreement 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 maturity date and we believe that the consummation of the Corporate Reorganization has improved 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 Credit Agreement.

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 continue to 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 September 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 increase by approximately 0.1% to 180.2 MMBoe from the reported 180.0 MMBoe, which is calculated as required by the SEC.

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We may breach certain financial covenants under Legacy LP's $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 Eleventh Amendment thereto (as amended, the “Credit Agreement”) and Legacy LP's second lien term loan credit agreement (as amended, our “Term Loan Credit Agreement”), which would constitute a default under our 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 Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas properties. Certain payment defaults or acceleration under our 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 Item 1A.

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 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.

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Operating Data

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


	Three Months Ended September 30,						Nine Months Ended September 30,

	2018		2017		2018		2017
	(In thousands, except per unit data)
Revenues:
Oil sales	$	98,779	$	59,060	$	291,989	$	154,298
Natural gas liquids (NGL) sales	7,771		6,720		20,902		16,691
Natural gas sales	38,657		41,035		109,076		128,220
Total revenue	$	145,207	$	106,815	$	421,967	$	299,209
Expenses:
Oil and natural gas production, excluding ad valorem taxes	$	49,431	$	39,515	$	141,898	$	131,005
Ad valorem taxes	1,873		2,564		6,804		7,093
Total oil and natural gas production	$	51,304	$	42,079	$	148,702	$	138,098
Production and other taxes	$	7,721	$	5,475	$	22,705	$	13,779
General and administrative, excluding transaction costs and LTIP	$	9,852	$	8,418	$	27,357	$	24,087
Transaction costs	1,451		54		4,840		138
LTIP expense	6,475		1,551		32,167		4,931
Total general and administrative	$	17,778	$	10,023	$	64,364	$	29,156
Depletion, depreciation, amortization and accretion	$	39,588	$	33,715	$	114,274	$	90,200
Commodity derivative cash settlements:
Oil derivative cash settlements (paid) received	$	(1,702)	$	3,102	$	(12,905)	$	9,800
Natural gas derivative cash settlements received	$	2,919	$	3,870	$	8,913	$	7,979
Production:
Oil (MBbls)	1,739		1,323		4,915		3,404
Natural gas liquids (MGal)	11,427		11,375		32,003		27,542
Natural gas (MMcf)	15,026		15,771		43,861		46,967
Total (MBoe)	4,515		4,222		12,987		11,888
Average daily production (Boe/d)	49,076		45,891		47,571		43,542
Average sales price per unit (excluding derivative cash settlements):
Oil price (per Bbl)	$	56.80	$	44.64	$	59.41	$	45.33
Natural gas liquids price (per Gal)	$	0.68	$	0.59	$	0.65	$	0.61
Natural gas price (per Mcf)	$	2.57	$	2.60	$	2.49	$	2.73
Combined (per Boe)	$	32.16	$	25.30	$	32.49	$	25.17
Average sales price per unit (including derivative cash settlements):
Oil price (per Bbl)	$	55.82	$	46.99	$	56.78	$	48.21
Natural gas liquids price (per Gal)	$	0.68	$	0.59	$	0.65	$	0.61
Natural gas price (per Mcf)	$	2.77	$	2.85	$	2.69	$	2.90
Combined (per Boe)	$	32.43	$	26.95	$	32.18	$	26.67
Average WTI oil spot price (per Bbl)	$	69.69	$	48.18	$	66.93	$	49.30
Average Henry Hub natural gas spot price (per MMbtu)	$	2.93	$	2.95	$	2.95	$	3.01
Average unit costs per Boe:
Oil and natural gas production, excluding ad valorem taxes	$	10.95	$	9.36	$	10.93	$	11.02
Ad valorem taxes	$	0.41	$	0.61	$	0.52	$	0.60
Production and other taxes	$	1.71	$	1.30	$	1.75	$	1.16
General and administrative excluding transaction costs and LTIP	$	2.18	$	1.99	$	2.11	$	2.03
Total general and administrative	$	3.94	$	2.37	$	4.96	$	2.45
Depletion, depreciation, amortization and accretion	$	8.77	$	7.98	$	8.80	$	7.59

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Results of Operations

Three-Month Period Ended September 30, 2018 Compared to Three-Month Period Ended September 30, 2017

Our revenues from the sale of oil were $98.8 million and $59.1 million for the three-month periods ended September 30, 2018 and 2017, respectively. Our revenues from the sale of NGLs were $7.8 million and $6.7 million for the three-month periods ended September 30, 2018 and 2017, respectively. Our revenues from the sale of natural gas were $38.7 million and $41.0 million for the three-month periods ended September 30, 2018 and 2017, respectively. The $39.7 million increase in oil revenues reflects an increase in production of 416 MBbls (31%) and an increase in the average realized price of $12.16 per Bbl (27%). 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"). The increase in oil revenues also reflects the increase in average realized price due to an increase in the average West Texas Intermediate (“WTI”) crude oil price of $21.51 per Bbl partially offset by widening regional differentials. The $1.1 million increase in NGL sales reflects increased ethane recoveries in our Piceance Basin properties and an increase in the realized NGL price of approximately $0.09 per Gal (15%). The $2.4 million decrease in natural gas revenues reflects a decrease in production and lower realized natural gas prices. Our natural gas production decreased by approximately 745 MMcf (5%) primarily due to natural production declines and individually immaterial divestitures partially offset by increased associated natural gas production from our Permian horizontal drilling program and increased working interests under our Amended and Restated Development Agreement. Average realized natural gas prices decreased by $0.03 per Mcf (1%) during the three months ended September 30, 2018 compared to the same period in 2017. Realized prices decreased due to lower NYMEX Henry Hub prices, widening regional differentials 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. The decrease in realized price was partially offset by an increase in Permian natural gas production which is sold inclusive of NGL content and therefore increases realized pricing for those volumes.

For the three-month period ended September 30, 2018, we recorded $30.9 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the three-month period ended September 30, 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 September 30, 2017, we recorded $13.3 million of net losses on oil and natural gas derivatives. Settlements of such contracts resulted in net cash receipts of $1.2 million and $7.0 million during the three months ended September 30, 2018 and 2017, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, increased to $49.4 million ($10.95 per Boe) for the three-month period ended September 30, 2018 from $39.5 million ($9.36 per Boe) for the three-month period ended September 30, 2017. This increase is primarily attributable to increased well count due to our Permian horizontal drilling program, increased working interests under our Amended and Restated Development Agreement and general cost inflation. Our ad valorem tax expense decreased to $1.9 million for the three-month period ended September 30, 2018 compared to $2.6 million or the three-month period ended September 30, 2017. This decrease is due to a reduction in ad valorem tax expenses on certain non-operated properties.

Our production and other taxes were $7.7 million and $5.5 million for the three-month periods ended September 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 $17.8 million and $10.0 million for the three-month periods ended September 30, 2018 and 2017, respectively. General and administrative expenses increased due to a $4.9 million increase in LTIP expense related to the recent increase in our unit price prior to the Corporate Reorganization and accelerated vesting in connection with the Corporate Reorganization, a $1.4 million increase in transaction costs and general cost increases.

We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $39.6 million and $33.7 million for the three-month periods ended September 30, 2018 and 2017, respectively. DD&A increased $5.9 million due primarily to increased horizontal Permian production.

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In the three-month period ended September 30, 2018, we recognized impairment expense of $19.0 million on 13 separate producing fields primarily related to the write-down of assets held-for-sale to their fair market value. In the three-month period ended September 30, 2017, we recognized impairment expense of $14.7 million on 12 separate producing fields primarily related to increased operating expenses.

We recorded (gains) losses on disposal of assets of $7.4 million and $(2.0) million for the three-month periods ended September 30, 2018 and 2017, respectively. The losses in 2018 were primarily related to the disposition of marginal oil and natural gas assets. The gains in 2017 were primarily related to the disposition of marginal oil and natural gas assets partially offset by costs associated with disposal.

We recorded interest expense of $29.4 million and $23.6 million for the three-month periods ended September 30, 2018 and 2017, respectively. Interest expense increased period over period due to additional 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.

We recorded gain on extinguishment of debt of $12.1 million due to the exchange of 2020 Senior Notes and 2021 Senior Notes for 2023 Convertible Notes.

We recorded income tax expense of $2.5 million primarily due to a non-recurring write-down of deferred tax assets for a taxable subsidiary that became a disregarded entity for tax purposes following the Corporate Reorganization.

As a result of the items described above, Legacy recorded net losses of $47.9 million and $33.9 million for the three-month periods ended September 30, 2018 and 2017, respectively.

Nine-Month Period Ended September 30, 2018 Compared to Nine-Month Period Ended September 30, 2017

Our revenues from the sale of oil were $292.0 million and $154.3 million for the nine-month periods ended September 30, 2018 and 2017, respectively. Our revenues from the sale of NGLs were $20.9 million and $16.7 million for the nine-month periods ended September 30, 2018 and 2017, respectively. Our revenues from the sale of natural gas were $109.1 million and $128.2 million for the nine-month periods ended September 30, 2018 and 2017, respectively. The $137.7 million increase in oil revenues reflects an increase in oil production of 1,511 MBbls (44%) 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 $14.08 per Bbl (31%) due to an increase in average WTI crude oil prices of $17.63 per Bbl partially offset by widening regional differentials. The $4.2 million increase in NGL sales reflects increased ethane recoveries in our Piceance Basin properties and an increase in the realized NGL price of approximately $0.04 per Gal (7%) due to higher commodity prices. The $19.1 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 $0.24 per Mcf (9%) during the nine months ended September 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 $0.06 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 3,106 MMcf (7%) due to natural production declines and individually immaterial divestitures partially offset by increased working interests under our Amended and Restated Development Agreement.

For the nine-month period ended September 30, 2018, we recorded $41.9 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the nine-month period ended September 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 nine-month period ended September 30, 2017, we recorded $35.9 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash (payments) receipts of $(4.0) million and $17.8 million during the nine months ended September 30, 2018 and 2017, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, increased to $141.9 million for the nine-month period ended September 30, 2018 from $131.0 million for the nine-month period ended September 30, 2017. This increase is primarily attributable to increased well count due to our Permian horizontal drilling program, increased working interests under our Amended and Restated Development Agreement and general cost inflation. Our ad valorem tax expense decreased to $6.8 million ($0.52 per Boe) for the nine-month period ended September 30, 2018 compared to $7.1 million ($0.60 per Boe) for the

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nine-month period ended September 30, 2017. This decrease is due to a reduction in ad valorem tax expenses on certain non-operated properties.

Our production and other taxes were $22.7 million and $13.8 million for the nine-month periods ended September 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 $64.4 million and $29.2 million for the nine-month periods ended September 30, 2018 and 2017, respectively. General and administrative expenses increased due to a $27.2 million increase in LTIP expense related to the recent increase in our unit price prior to the Corporate Reorganization and accelerated vesting in connection with the Corporate Reorganization, a $4.7 million increase in transaction costs, and general cost increases.

We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $114.3 million and $90.2 million for the nine-month periods ended September 30, 2018 and 2017, respectively. DD&A increased $24.1 million due primarily to increased horizontal Permian production.

Impairment expense was $54.4 million and $24.5 million for the nine-month periods ended September 30, 2018 and 2017, respectively. In the nine-month period ended September 30, 2018, we recognized $54.4 million of impairment expense on 20 separate producing fields primarily related to the decline in natural gas futures prices during the period since December 31, 2017 and the write-down of assets held-for-sale to their fair market value. Impairment expense for the nine-month period ended September 30, 2017 was recognized on 23 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 $(14.2) million and $3.5 million for the nine-month periods ended September 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 partially offset by gain on disposal of other immaterial assets.

We recorded interest expense of $85.3 million and $64.4 million for the nine-month periods ended September 30, 2018 and 2017, respectively. Interest expense increased approximately $21.0 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.

We recorded gain on extinguishment of debt of $63.8 million due to the repurchase of 2021 Senior Notes and the exchange of Senior Notes for Convertible Senior Notes.

We recorded income tax expense of $3.1 million primarily due to a non-recurring write-down of deferred tax assets for a taxable subsidiary that became a disregarded entity for tax purposes following the Corporate Reorganization.

As a result of the items described above, Legacy recorded a net loss of $34.2 million and $28.6 million for the nine-month periods ended September 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 Legacy from period to period and to compare it with the performance of other peers 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;

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• Depletion, depreciation, amortization and accretion;

• Impairment of long-lived assets;

• (Gain) loss on disposal of assets;

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

• Share-based compensation expense related to LTIP 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 costs.

The following table presents a reconciliation of our consolidated net income to Adjusted EBITDA for the three and nine months ended September 30, 2018 and 2017, respectively.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		2017		2018		2017
	(In thousands)
Net income (loss)	$	(47,852)	$	(33,866)	$	(34,179)	$	(28,571)
Plus:
Interest expense	$	29,383	23,621		85,340		64,368
Gain on extinguishment of debt	(12,107)		—		(63,800)		—
Income tax expense	2,499		266		3,116		837
Depletion, depreciation, amortization and accretion	39,588		33,715		114,274		90,200
Impairment of long-lived assets	18,994		14,665		54,375		24,548
(Gain) loss on disposal of assets	7,368		(2,034)		(14,172)		3,491
Equity in (income) loss of equity method investees	30		—		10		(12)
Share-based compensation expense	6,475		1,551		32,167		4,931
Minimum payments earned in excess of overriding royalty interest(a)	516		512		1,373		1,427
Net (gains) losses on commodity derivatives	30,867		13,309		41,886		(35,876)
Net cash settlements (paid) received on commodity derivatives	1,217		6,972		(3,992)		17,779
Transaction costs	1,451		54		4,840		138
Adjusted EBITDA	$	78,429	$	58,765	$	221,238	$	143,260

____________________

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 September 30, 2018 and 2017, respectively, Adjusted EBITDA increased 33% to $78.4 million from $58.8 million. For the nine months ended September 30, 2018 and 2017, Adjusted EBITDA increased 54% to $221.2 million from $143.3 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. All outstanding employee retention bonus agreements vested in connection with the Corporate Reorganization. Had the Corporate Reorganization not occurred on September 20, 2018, EBITDA would have increased to $80.4 million and $223.2 million for the three and nine month periods ending September 30, 2018, respectively.

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 equity securities, 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 Credit Agreement and Term Loan Credit Agreement will provide us sufficient liquidity to fund our operations in 2018. However, we could breach certain financial

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covenants under our Credit Agreement or our Term Loan Credit Agreement, which would constitute a default under our 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 Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas properties. Certain payment defaults or acceleration under our 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. 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.”

Our Credit Agreement 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 has improved 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 Credit Agreement.

The amounts available for borrowing under our Credit Agreement are subject to a borrowing base, which is currently set at $575 million following our fall 2018 redetermination. As of October 29, 2018, we had $47.9 million available for borrowing under our Credit Agreement. Our lenders redetermine the borrowing base semi-annually, subject to the parties' rights to have additional redeterminations between scheduled redeterminations.

As of October 29, 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 $4.0 million of unfavorable settlements in the nine months ended September 30, 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 $159.2 million and $72.9 million for the nine-month periods ended September 30, 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.

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Cash Flow from Investing Activities

We invested $185.3 million of capital for the nine-month period ended September 30, 2018, which consisted of $181.6 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 $35.2 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 $254.5 million of capital for the nine-month period ended September 30, 2017, which consisted of $96.0 million for development projects, exclusive of accrued capital expenditures, $141.4 million related to the acceleration payment under our resulting in the reversion of working interests in properties under our joint development agreement, $17.1 million of individually immaterial acquisitions of oil and natural gas properties and prospective acreage as well as adjustments to prior period acquisitions. We received $5.6 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.

Our annual capital expenditure budget for 2018, which predominantly consists of drilling, recompletion and well stimulation projects, is set at $225 million. During the nine months ended September 30, 2018, we incurred $171.6 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 $47.9 million as of October 29, 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 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 nine-month periods ended September 30, 2018 and 2017, we received (paid) settlements of $(4.0) million and $17.8 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 October 29, 2018, covering the period from October 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 applicable commodity index price.

Oil Swaps:


Time Period	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
October-December 2018	763,600	$54.76	$51.20	-	$63.68
2019	3,285,000	$61.33	$57.15	-	$67.65

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Natural Gas Swaps:


Time Period	Volumes (MMBtu)	Average Price per MMBtu	Price Range per MMBtu
October-December 2018	9,080,000	$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 October 29, 2018, covering the period from October 1, 2018 through December 31, 2019:


		Average
Time Period	Volumes (Bbls)	Price per Bbl	Price Range per Bbl
October-December 2018	1,012,000	$(1.13)	$(1.25)	-	$(0.80)
2019	2,193,000	$(3.62)	$(5.60)	-	$(1.15)

We have entered into regional crude oil differential enhanced 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 combined with a short call option to enhance the price of the differential swap. The following table summarizes the oil differential contracts currently in place as of October 29, 2018, covering the period from January 1, 2019 through December 31, 2019:


		Average Short	Average Swap
Time Period	Volumes (Bbls)	Call Price per Bbl	Price per Bbl
2019	1,460,000	$70.00	$(2.91)

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 October 29, 2018, covering the period from October 1, 2018 through December 31, 2018:

Average Long

Average Short

Time Period

Volumes (Bbls)

Put Price per Bbl

Call Price per Bbl

October-December 2018

391,000

$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 October 29, 2018, covering the period from October 1, 2018 to December 31, 2018:

Average Long

Average Short

Average

Time Period

Volumes (Bbls)

Put Price per Bbl

Swap Price per Bbl

October-December 2018

32,200

$57.00

$82.00

$90.50

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Cash Flow from Financing Activities

Our net cash used in financing activities was $0.3 million for the nine months ended September 30, 2018, compared to cash provided by financing activities of $163.8 million for the nine months ended September 30, 2017. During the nine months ended September 30, 2018, total net borrowings under our revolving credit facility were $30.0 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 nine months ended September 30, 2017, total net borrowings under our revolving credit facility were $15.0 million.

Credit Facility

On April 1, 2014, Legacy LP entered into our Credit Agreement. Borrowings under the Credit Agreement mature on April 1, 2019. Our obligations under the 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 our operating subsidiaries and Legacy's ownership interest in the General Partner, and we are unconditionally guaranteed on a joint and several basis by Legacy LP's wholly owned direct and indirect subsidiaries. Concurrently with the Corporate Reorganization, the General Partner and Legacy Inc. provided guarantees of Legacy LP's obligations under the Credit Agreement. 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 September 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 Credit Agreement. On October 31, 2018, we received a waiver with respect to compliance with such covenant for the fiscal quarter ended September 30, 2018. Except with respect to compliance with the financial covenant that has been waived, as of September 30, 2018, we were in compliance with all covenants of the Credit Agreement. Depending on future oil and natural gas prices, we could breach certain financial covenants under our Credit Agreement, which would constitute a default under our 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 Credit Agreement and potential foreclosure on our oil and natural gas properties. As previously noted, if the lenders under our Credit Agreement were to accelerate, subject to certain limitations, the indebtedness under our 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 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 Credit Agreement, may be unable to make distributions to our shareholders and our financial condition and liquidity would be adversely affected. For further information related to our Credit Agreement, please refer to "—Footnote 2—Debt" in the Notes to Condensed Consolidated Financial Statements.

As of September 30, 2018, we had approximately $529.0 million drawn under the Credit Agreement at a weighted average interest rate of 5.15%, leaving approximately $45.2 million of availability under the Credit Agreement. For the nine-month period ended September 30, 2018, we paid in cash $19.2 million of interest expense on the Credit Agreement.

As part of our routine fall redetermination, our borrowing base was reaffirmed at $575.0 million, leaving approximately $47.9 million of availability under the Credit Agreement as of October 29, 2018.

We periodically enter into interest rate swap transactions to mitigate the volatility of interest rates. As of September 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.

• permit the issuance of the 2023 Convertible Notes;

• provide that the 2023 Convertible Notes constitute debt that is permitted refinancing debt;

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• allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common shares; and

• permit the redemption of certain senior notes or permitted refinancing debt of such senior notes with any combination of the following: (i) proceeds of certain permitted refinancing debt: (ii) net cash proceeds of any sale of equity interests (other than disqualified capital stock) of Legacy Inc.; and/or (iii) in exchange for equity interests (other than disqualified capital stock) of Legacy Inc.

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 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 Credit Agreement. In addition, following the consummation of the Corporate Reorganization, the General Partner and Legacy Inc. became guarantors. As of September 30, 2018, we were in compliance with all covenants of the Term Loan Credit Agreement. The Term Loan Credit Agreement matures on August 31, 2020. For further information related to our Term Loan Credit Agreement, please refer to "—Footnote 2—Debt" in the Notes to Condensed Consolidated Financial Statements.

As of October 29, 2018, we had approximately $338.6 million drawn under the Second Lien Term Loan Credit Agreement.

On December 31, 2017, we 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 ($61.4 million as of October 29, 2018) to October 25, 2019, relaxed the asset coverage ratio financial covenant from 1.0x to 0.85x during 2018 and required Legacy LP to mortgage certain additional properties located in the Permian Basin.

On September 14, 2018 and September 20, 2018, Legacy entered into the Fifth Amendment and Sixth Amendment, respectively to the Term Loan Credit Agreement (the "Term Loan Amendments"). The Term Loan Amendments amend certain provisions set forth in the Term Loan Credit Agreement to, among other items:

• permit the issuance of the 2023 Convertible Notes;

• provide that the 2023 Convertible Notes constitute debt that is permitted refinancing of debt;

• allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common shares; and

8% Senior Notes Due 2020

On December 4, 2012, Legacy LP and Legacy Reserves Finance Corporation (together, the "Issuers") 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.

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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. On September 20, 2018, the Issuers exchanged $21.0 million aggregate principal amount of 2020 Senior Notes for $21.0 million aggregate principal amount of 2023 Convertible Notes.

As of September 30, 2018, we were in compliance with all financial and other covenants of the 2020 Senior Notes. As previously noted, if the lenders under our Credit Agreement were to accelerate the indebtedness under our 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—Debt" in the Notes to Condensed Consolidated Financial Statements.

6.625% Senior Notes Due 2021

On May 28, 2013, the Issuers 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, the Issuers completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of our 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 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 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.

On September 20, 2018, the Issuers exchanged $109.0 million aggregate principal amount of 2021 Senior Notes for $109.0 million aggregate principal amount of 2023 Convertible Notes

As of September 30, 2018, we were in compliance with all financial and other covenants of the 2021 Senior Notes. As previously noted, if the lenders under our Credit Agreement were to accelerate the indebtedness under our 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—Debt" in the Notes to Condensed Consolidated Financial Statements.

2023 Convertible Senior Notes due 2023

On September 20, 2018, the Issuers, completed private exchanges with certain holders of senior notes, pursuant to which the Issuers exchanged (i) $21.004 million aggregate principal amount of 2020 Senior Notes for $21.004 million aggregate principal amount of 2023 Convertible Notes and 105,020 shares of common stock and (ii) $109 million aggregate principal amount of 2021 Notes for $109 million aggregate principal amount of 2023 Convertible Notes.

As of September 30, 2018, we were in compliance with all financial and other covenants of the 2023 Convertible Notes. As previously noted, if the lenders under our Credit Agreement were to accelerate the indebtedness under our 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 2023 Convertible Notes, please refer to “—Footnote 2—Debt” in the Notes to Condensed Consolidated Financial Statements.

Off-Balance Sheet Arrangements

None.

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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 September 30, 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 and the change in tax status as discussed in "—Footnote 13—Income Taxes" 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.

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 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 at commencement longer than twelve months. We have engaged a third party consultant to assist with our implementation of ASU 2016-02. Leases will be classified as either finance or operating, with that 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. We expect to adopt ASU 2016-02 retrospectively in the first quarter of 2019 (that is, the period of adoption) through a cumulative-effect adjustment to the opening balance of retained earnings.

We commonly enter into lease agreements in support of our operations for assets such as office space, vehicles, drilling rigs, compressors and other well equipment. In our efforts to further determine the impact of ASU 2016-02, We developed an implementation approach that 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 and performing a detailed review of material contracts identified through that analysis. Although its impact assessment is currently ongoing, we believe it is likely that the new guidance will impact our consolidated balance sheet due to the recognition of right-of-use assets and lease liabilities that are not recognized under currently effective guidance (for example, operating leases). We are further evaluating the impacts that ASU 2016-02 may have on our disclosures, existing accounting policies and internal controls, as well as financial lease accounting system solutions to facilitate compliance with ASU 2016-02.

Upon transition, we plan to apply the package of practical expedients provided in ASU 2016-02 that allow companies, among other things, to not reassess contracts that commenced prior to adoption. In addition, we expect to utilize the practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under currently effective lease accounting guidance.

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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 9—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 September 30, 2018, the fair value of our commodity derivative positions was a net liability of $31.6 million based on NYMEX futures prices from October 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 October 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 September 30, 2018, we had debt outstanding under our Credit Agreement of $529.0 million, which incurred interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred by us under our Credit Agreement for the nine-month period ended September 30, 2018 was 5.02%. A 1% increase in LIBOR on our outstanding debt under our revolving credit facility as of September 30, 2018 would result in an estimated $2.9 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 chief executive officer and chief financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2018. Based upon that evaluation and subject to the foregoing, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

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

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 September 30, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

Legacy is also, from time to time, involved in litigation and claims arising out of its operations in the normal course of business including regulatory and environmental matters, none of which are expected to be material. 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.

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Item 1A. Risk Factors.

Risks Related to the Business

If oil and natural gas prices decline, our cash flow from operations will decline.

Lower oil and natural gas prices may decrease our revenues and thus cash flow from operations. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the domestic and foreign supply of and demand for oil and natural gas;

• market expectations about future prices of oil and natural gas;

• the price and quantity of imports of crude oil and natural gas;

• overall domestic and global economic conditions;

• political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

• the willingness and ability of members of the Organization of Petroleum Exporting Countries and other petroleum producing countries to agree to and maintain oil price and production controls;

• trading in oil and natural gas derivative contracts;

• the level of consumer product demand;

• weather conditions and natural disasters;

• technological advances affecting energy production and consumption;

• domestic and foreign governmental regulations and taxes;

• the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;

• the impact of the U.S. dollar exchange rates on oil and natural gas prices; and

• the price and availability of alternative fuels.

Historically, oil and natural gas prices have been extremely volatile. For example, for the five years ended December 31, 2017, the NYMEX-WTI oil price ranged from a high of $110.62 per Bbl to a low of $26.19 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $8.15 per MMBtu to a low of $1.49 per MMBtu. As of September 30, 2018, the NYMEX WTI oil spot price was $73.16 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.01 per MMBtu. If oil and natural gas prices decline from current levels, it may have a material adverse effect on our operations and financial condition.

Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Our development and acquisition activities require substantial capital expenditures. We expect to fund our capital expenditures through cash flows from operations. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil and natural gas and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to development of our oil and natural gas properties, which in turn could lead to a decline in our oil and natural gas production or reserves, and in some areas a loss of properties.

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Failure to replace reserves may negatively affect our business, results of operations and financial condition.

The growth of our business depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. Further, the rate of estimated decline of our oil and natural gas reserves may increase if our wells do not produce as expected. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs. If oil and natural gas prices increase, our costs for additional reserves would also increase; conversely if natural gas or oil prices decrease, it could make it more difficult to fund the replacement of our reserves.

Increases in the cost of or failure of costs to adjust downward for drilling rigs, service rigs, pumping services and other costs in drilling and completing wells could reduce the viability of certain of our development projects.

The costs of rigs and oil field services necessary to implement our development projects decreased when oil and natural gas prices decreased in 2015. As oil and natural gas prices have increased, we are seeing service costs rise and availability diminish. Increased capital requirements for our projects will result in higher reserve replacement costs and could cause certain of our projects to become uneconomic even with increased commodity prices and therefore not to be implemented, reducing our production and cash flow. Decreased availability of drilling equipment and services could significantly impact the planned execution of our development program.

Our substantial indebtedness and liquidity issues may impact our business, financial condition and operations.

Due to our substantial indebtedness and liquidity issues, there is risk that, among other things:

• third parties’ confidence in our ability to develop oil and natural gas properties could erode, which could impact our ability to execute on our business strategy;

• it may become more difficult to retain, attract or replace key employees;

• employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and

• our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.

The occurrence of certain of these events may increase our operating costs and may have a material adverse effect on our business, results of operations and financial condition.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

As of September 30, 2018, we had total net debt of approximately $1.3 billion. Our existing and future indebtedness could have important consequences to us, including:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;

• covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

• our access to the capital markets may be limited;

• we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and

• our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results and cash flows are not sufficient to service our current or future indebtedness, we will be forced to take actions such as further reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Our Credit Agreement matures on April 1, 2019, our Term Loan Credit Agreement matures on August 31, 2021 (or August 31, 2020 if we have $15 million or more of outstanding Senior Notes), our 2020 Senior Notes mature on December 1, 2020 and our 2021 Senior Notes mature on December 1, 2021; if we are unable to refinance or otherwise repay such indebtedness there would be a material and adverse effect on our business continuity and our financial condition.

As maturity dates for our outstanding indebtedness approach, particularly that of our Credit Agreement, we are evaluating, and will continue to evaluate and will opportunistically pursue, our options to refinance or repay such indebtedness, including alternatives in the debt and equity capital markets or discussions with lenders under our Credit Agreement and our second lien term loan credit agreement (the “Term Loan Credit Agreement”).

If we do not have the capital necessary to repay our outstanding indebtedness when it matures, it will be necessary for us to take significant actions, such as revising or delaying our strategic plans, reducing or delaying planned capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. We may be unable to effect any of these remedial steps on a satisfactory basis, or at all. If we are unable to refinance or otherwise repay our debt upon the maturity of our indebtedness, we would be in default, which would result in material adverse consequences for us.

In addition, if we are unable to refinance indebtedness before that debt’s maturity becomes current, there could be substantial doubt about our ability to continue as a going concern. If we are unable, or there is substantial doubt about our ability, to continue as a going concern, it would have a material adverse effect on the value of an investment in us.

Our development projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil and natural gas reserves. We intend to finance our future capital expenditures with cash flow from operations and, subject to availability, borrowings under our Credit Agreement and our Term Loan Credit Agreement. Our cash flow from operations and access to capital are subject to a number of variables, including:

• our proved reserves;

• the level of oil and natural gas we are able to produce from existing wells;

• capital and lending market conditions;

• the prices at which our oil and natural gas are sold; and

• our ability to identify, acquire and exploit new reserves.

If our revenues or the borrowing base under our Credit Agreement decrease as a result of lower oil and/or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our Credit Agreement and our Term Loan Credit Agreement restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing due to such restrictions, market conditions or otherwise. If cash generated by operations or available under our Credit Agreement and our Term Loan Credit Agreement is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas production and reserves, and could adversely affect our business, results of operations and financial condition.

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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, results of operations and financial condition.

Our drilling activities are subject to many risks, including the risk that we will not encounter commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.

In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

• the high cost, shortages or delivery delays of equipment and services;

• unexpected operational events;

• adverse weather conditions or events;

• facility or equipment malfunctions;

• title disputes;

• regulatory changes and approvals;

• pipeline ruptures or spills;

• collapses of wellbore, casing or other tubulars;

• unusual or unexpected geological formations;

• loss of drilling fluid circulation;

• formations with abnormal pressures;

• fires;

• blowouts, craterings and explosions; and

• uncontrollable flows of oil, natural gas or well fluids.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, results of operations and financial condition.

If commodity prices decline, a significant portion of our development projects may become uneconomic and cause write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition.

Lower oil and natural gas prices may not only decrease our revenues, but also may render many of our development and production projects uneconomic and result in a downward adjustment of our reserve estimates, which would negatively impact our borrowing base under our Credit Agreement and ability to fund operations.

A reduction in commodity prices may be caused by many factors, including substantial increases in U.S. production and reserves from unconventional (shale) reservoirs, without a corresponding increase in demand. The International Energy Agency forecasts continued U.S. oil production growth in 2018. This environment could cause the prices for oil to fall to lower levels.

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Furthermore, a decrease in oil and natural gas prices may render a significant portion of our development projects uneconomic. In addition, if oil and natural gas prices decline, our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. For example, in the year ended December 31, 2017, we incurred impairment charges of $37.3 million, a portion of which was driven by commodity price changes. We may incur further impairment charges in the future related to depressed commodity prices, which could have a material adverse effect on our results of operations in the period taken.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management team has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected time frame or will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations and financial condition.

Fluctuations in price and demand for our production may force us to shut in a significant number of our producing wells, which may adversely impact our revenues.

We are subject to great fluctuations in the prices we are paid for our production due to a number of factors. Drilling in shale resources has developed large amounts of new oil and natural gas supplies, both from natural gas wells and associated natural gas from oil wells, that have depressed the prices paid for our production, and we expect the shale resources to continue to be drilled and developed by our competitors. We also face the potential risk of shut-in production due to high levels of oil, natural gas and NGL inventory in storage, weak demand due to mild weather and the effects of any economic downturns on industrial demand. Lack of NGL storage in Mont Belvieu, where our West Texas and New Mexico NGLs are shipped for processing, could cause the processors of our natural gas to curtail or shut-in our natural gas wells and potentially force us to shut-in oil wells that produce associated natural gas, which may adversely impact our revenues. For example, following past hurricanes, certain Permian Basin natural gas processors were forced to shut down their plants due to the shutdown of the Texas Gulf Coast NGL fractionators, requiring us to vent or flare the associated natural gas from our oil wells. There is no certainty we will be able to vent or flare natural gas again due to potential changes in regulations. Furthermore, we may encounter problems in restarting production of previously shut-in wells.

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

The prices that we receive for our oil production sometimes reflect a discount to the relevant benchmark prices, such as WTI, that are used for calculating derivative positions. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark prices for oil and the wellhead price we receive could adversely affect our operating results and financial condition. While this differential remained largely unchanged from 2015 through the first quarter of 2018, as crude oil prices have strengthened through 2018, crude oil and associated natural gas production growth has strained existing takeaway capacity and caused widening basis differentials in the Permian Basin, which could adversely affect our operating results and financial condition.

Due to regional fluctuations in the actual prices received for our natural gas production, the derivative contracts we enter into may not provide us with sufficient protection against price volatility since they are based on indexes related to different and remote regional markets.

We sell our natural gas into local markets, the majority of which is produced in East Texas, Colorado, West Texas, Southeast New Mexico, Central Oklahoma and Wyoming and shipped to the Midwest, West Coast and Texas Gulf Coast. These regions account for over 90% of our natural gas sales. In the past, we have used swaps on Northwest Pipeline, California SoCal NGI and San Juan Basin natural gas prices and we may do so again in the future. While we are paid a local price indexed to or

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closely related to these indexes, these indexes are heavily influenced by prices received in remote regional consumer markets less transportation costs and thus may not be effective in protecting us against local price volatility.

The substantial restrictions and financial covenants of both our Credit Agreement and our Term Loan Credit Agreement, any negative redetermination of our borrowing base under our Credit Agreement by our lenders and any potential disruptions of the financial markets could adversely affect our business, results of operations and financial condition.

We depend on our Credit Agreement and our Term Loan Credit Agreement for future capital needs. Our Credit Agreement, which matures on April 1, 2019, limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. As of October 29, 2018, our borrowing base was $575.0 million and we had approximately $47.9 million available for borrowing. Our Term Loan Credit Agreement for second lien term loans maturing on August 31, 2020 provides for up to an aggregate principal amount of $400.0 million, of which we have used $338.6 million.

Our Credit Agreement and our Term Loan Credit Agreement restrict, among other things, our ability to incur debt and requires us to comply with certain financial covenants and ratios. We may not be able to comply with these restrictions and covenants in the future and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, such as any potential disruptions in the financial markets. Our failure to comply with any of the restrictions and covenants under our Credit Agreement or our Term Loan Credit Agreement could result in a default under our Credit Agreement or our Term Loan Credit Agreement. A default under our Credit Agreement or our Term Loan Credit Agreement could cause all of our existing indebtedness, including our second lien term loans and our Senior Notes, to be immediately due and payable.

Outstanding borrowings in excess of the borrowing base must be repaid within four months, and, if mortgaged properties represent less than 95% of total value of oil and natural gas properties used to determine the borrowing base, we must pledge other oil and natural gas properties as additional collateral. We may not have the financial resources in the future to make any mandatory principal prepayments required under our Credit Agreement.

The occurrence of an event of default or a negative redetermination of our borrowing base, such as a result of lower commodity prices or a deterioration in the condition of the financial markets, could adversely affect our business, results of operations and financial condition.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financing Activities.”

Low commodity prices may impact our ability to comply with debt covenants.

Should oil and natural gas prices decline dramatically in 2018, we could breach certain financial covenants under our Credit Agreement or our Term Loan Credit Agreement, which would constitute a default under our Credit Agreement or our Term Loan Credit Agreement. Such default 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 Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas properties. If the lenders under our Credit Agreement were to accelerate the indebtedness under our Credit Agreement as a result of such defaults, 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. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. 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, the saleable value of our assets may not be sufficient to repay all of our outstanding indebtedness.

Any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations.

We may not achieve the expected results of any acquisition we complete, and any adverse conditions or developments related to any such acquisition may have a negative impact on our operations and financial condition.

Further, even if we complete any acquisitions, which we would expect to increase our cash flow, actual results may differ from our expectations and the impact of these acquisitions may actually result in a decrease in cash flow. Any acquisition involves potential risks, including, among other things:

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• the validity of our assumptions about recoverable reserves, development potential, future production, revenues, capital expenditures, future oil and natural gas prices, operating costs and potential environmental and other liabilities;

• an inability to successfully integrate the assets and businesses we acquire;

• a decrease in our liquidity by using a portion of our available cash or borrowing capacity under our Credit Agreement and our Term Loan Credit Agreement to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

• the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

• the diversion of management’s attention from other business concerns;

• the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges; and

• the loss of key purchasers.

Our decision to acquire a property depends in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, seismic data and other information, the results of which are often inconclusive and subject to various interpretations. Our estimates of future reserves and estimates of future development and production for our acquisitions and related forecasts of anticipated cash flow therefrom are initially based on detailed information furnished by the sellers and are subject to review, analysis and adjustment by our internal staff, typically without consulting with outside petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain and our proved reserves estimates and cash flow forecasts therefrom may exceed actual acquired proved reserves or the estimates of future cash flows therefrom. In connection with our assessments, we perform a review of the acquired properties included in our acquisitions that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems.

Also, our reviews of newly acquired properties are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities including the Bureau of Land Management. We may incur substantial costs in order to maintain compliance with these existing laws and regulations and could experience substantial disruptions to our operations if we do not timely receive permits required to drill new wells, especially on federal lands. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. All such costs or disruptions may have a negative effect on our business, results of operations and financial condition.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

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Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to oil and natural gas exploration, production and restoration activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by environmental and other impacts of our operations.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our financial condition could be adversely affected.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale formations, as well as tight conventional formations including many of those that New Legacy completes and produces. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate hydrocarbon production. Some states have adopted and others, including Colorado, are considering legislation to restrict or additionally regulate hydraulic fracturing. For example, several states including Texas, Colorado and Wyoming have adopted or are considering legislation requiring the disclosure of hydraulic fracturing chemicals. From time to time, Congress has also considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Public disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In addition, state and federal agencies recently have focused on a possible connection between the operation of injection wells used for oil and natural gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address seismic activity. For example, the Railroad Commission of Texas has adopted regulations which place additional restrictions on the permitting of disposal well operations in areas of historical or future seismic activity. Any additional level of regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the Environmental Protection Agency (“EPA”) approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. In addition, in May 2016, the EPA issued rules covering methane emissions from new oil and natural gas industry operations. In July 2017, the EPA proposed a two-year stay of certain requirements of this rule pending reconsideration of the rule. In September 2018, the EPA proposed amendments to the rule as part of its reconsideration process. Compliance with any final requirements could increase our costs of development and production, which costs may be significant.

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Restrictive covenants under the indentures governing our 2020 Senior Notes, 2021 Senior Notes and 2023 Convertible Notes may adversely affect our operations.

The indentures governing the Senior Notes contains, and any future indebtedness we incur may contain, a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

• sell assets, including equity interests in our restricted subsidiaries;

• pay distributions on, redeem or purchase our equity or redeem or purchase our subordinated debt;

• make investments;

• incur or guarantee additional indebtedness or issue preferred units;

• create or incur certain liens;

• enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

• consolidate, merge or transfer all or substantially all of our assets;

• engage in transactions with affiliates;

• create unrestricted subsidiaries; and

• engage in certain business activities.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

A failure to comply with the covenants in the indentures governing the Senior Notes or any future indebtedness could result in an event of default under the indentures governing the Senior Notes, our Credit Agreement, our Term Loan Credit Agreement, or any future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions.

Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations and financial condition.

Further, the present value of future net cash flows from our proved reserves may not be the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. To illustrate the price impact of commodity prices on our proved reserves subsequent to December 31, 2017, we recalculated the value of our proved reserves as of December 31, 2017 using the five-year average forward price as of September 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 increase by

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approximately 0.1% to 180.2 MMBoe from our previously reported 180.0 MMBoe, which is calculated as required by the SEC. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas we produce.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, oversupply of oil due to nearby refinery outages, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations and financial condition.

We do not control all of our operations and development projects and failure of an operator of wells in which we own partial interests to adequately perform could adversely affect our business, results of operations and financial condition.

Many of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells.

If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The success and timing of our development projects on properties operated by others is outside of our control.

The failure of an operator of wells in which we own partial interests to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues and could adversely affect our business, results of operations and financial condition.

Increases in interest rates could adversely affect our business, results of operations, cash flows from operations and financial condition.

Since all of the indebtedness outstanding under the Credit Agreement is at variable interest rates, we have significant exposure to increases in interest rates. As a result, our business, results of operations and cash flows may be adversely affected by significant increases in interest rates.

The inability of one or more of our customers to meet their obligations may adversely affect our financial condition and results of operations.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry who are also subject to the effects of the current oil and natural gas commodity price environment. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic, industry and other conditions. In addition, our oil, natural gas and interest rate derivative transactions expose us to credit risk in the event of nonperformance by counterparties.

We depend on a limited number of key personnel who would be difficult to replace.

Our operations are dependent on the continued efforts of our executive officers, senior management and key employees. The loss of any executive officer, member of our senior management or other key employees could negatively impact our ability to execute our strategy.

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Our business may be affected by shortages of skilled employees and labor cost inflation.

Competition for skilled employees in the oil and gas industry in Midland, Texas is strong, and labor costs have increased moderately since 2015. We expect that the demand and, hence, costs for skilled employees will increase as prices for oil and natural gas rise. Continual high demand for skilled employees and continued increases in labor costs could have a material adverse effect on our business, financial condition, results of operations and prospects.

We may be unable to compete effectively, which could have an adverse effect on our business, results of operations and financial condition.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.

These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration and development activities during periods of low oil and natural gas market prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with these companies could have an adverse effect on our business, results of operations and financial condition.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential investors could lose confidence in our financial reporting, which would harm our business and the trading price of our securities.

Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our securities.

A failure in our operational systems or cyber security attacks on any of our facilities or those of third parties may have a material adverse effect on our business, results of operations and financial condition.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Our operations are also subject to the risk of cyber security attacks. Any cyber security attacks that affect our facilities, our customers or our financial data could have a material adverse effect on our business. In addition, cyber security attacks on our customer and employee data may result in financial loss or potential liability and may negatively impact our reputation. Third-party systems on which we rely could also suffer system failures, which could negatively impact our business, results of operations and financial condition.

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Our sales of oil, natural gas, NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.

The Federal Trade Commission, the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission (the “CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas, NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales and trading may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

The swaps-related provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”) and the rules the CFTC has adopted regulate the markets in certain derivative transactions, broadly referred to as “swaps” and which include hedging and non-hedging oil and gas and interest rate transactions, and market participants. Swaps falling within classes designated or to be designated by the CFTC are or will be subject to clearing on a derivatives clearing organization, and, if accepted for clearing, are subject to execution on an exchange or a swap execution facility if made available for trading on such facility. To date, the CFTC has designated only certain classes of interest rate and index credit default swaps for mandatory clearing. The Act provides an exception from application of the Act’s clearing and trade execution requirements that qualifying commercial end-users may elect for swaps they use to hedge or mitigate commercial risks (“End-User Exception”). Although we believe we will be able to qualify for, and have elected, the End-User Exception with respect to most, if not all, of the swaps we enter that otherwise would have to be cleared, if we cannot do so with respect to many of the swaps we enter into, our ability to execute our hedging program efficiently will be adversely affected. In addition, the CFTC and federal banking regulators have adopted rules (which are being phased in) requiring certain regulated persons to collect margin as to any uncleared swap from their counterparty to such swap if that counterparty is not a non-financial end user (as defined in such rules) Although we believe we qualify as a non-financial end user under such rules, if we do not do so and must provide margin regarding uncleared swaps to which we are a party, our results of operations and financial condition could be adversely affected.

The European Market Infrastructure Regulation (“EMIR”) includes regulations related to the trading, reporting and clearing of derivatives subject to EMIR. We have counterparties that are located in a jurisdiction subject to EMIR. Such counterparties are required to comply with EMIR and accordingly will require us to transact with them in a manner that will ensure their compliance with EMIR. In broad terms, EMIR’s effect on the derivatives markets and their participants, creates similar risks and could have similar adverse impacts as those under the swap regulatory provisions of the Act and the CFTC’s swap rules. Finally, the Act included provisions, including related to position limits and reporting, that reflect that volatility in oil and natural gas prices is attributed by some legislators and regulators to speculative trading in derivatives and commodity instruments related to oil and natural gas. The CFTC and Congress periodically focus on such concerns, particularly at times of price rises in the market. Our revenues could be adversely affected if a consequence of that focus is legislative or regulatory actions that lead to lower commodity prices.

Current and proposed derivatives legislation and rulemaking as well as restrictions on hedging activities in the Credit Agreement could have a material adverse effect on our business.

If we or our derivatives counterparties are subject to additional requirements imposed as a result of the Act or any new (or newly implemented) regulations or international legislation, such changes may increase our transaction costs or make it more difficult for us to enter into hedging transactions on favorable terms. Any such regulations could also subject our hedge counterparties to limits on commodity positions and thereby have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. Further, our Credit Agreement restricts the types of counterparties that we can enter into hedging transactions with and the security that we are able to provide counterparties that are not lenders under our Credit Agreement. Our inability to enter into hedging transactions on favorable terms, or at all, could increase our operating expenses and put us at increased exposure to risks of adverse changes in oil and natural gas prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations and cash flows.

Risks Related to the Common Stock

The price of our common stock may experience volatility.

The price of our common stock may be volatile. Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community,

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sales of our common stock by significant stockholders, a turnover of the investor base as a result of the corporate reorganization whereby Legacy LP became a subsidiary of Legacy Inc. that became effective on September 20, 2018 (the “Corporate Reorganization”), short-selling of our common stock by investors, issuance of a significant number of shares for equity-based compensation or to raise additional capital to fund our operations, changes in market valuations of similar companies and speculation in the press or investment community about our financial condition or results of operations, as well as any doubt about its ability to continue as a going concern. General market conditions and U.S. or international economic factors and political events unrelated to the performance of Legacy Inc. may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of Legacy LP’s units to predict the future price of our common stock or our future financial results.

Our amended and restated certificate of incorporation and amended and restated bylaws contain provisions that may make it more difficult for a third party to acquire control of it, even if a change in control would result in the purchase of your shares of common stock at a premium to the market price or would otherwise be beneficial to you.

There are provisions in our amended and restated certificate of incorporation and amended and restated bylaws that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of your shares of common stock at a premium to the market price or would otherwise be beneficial to you. For example, our amended and restated certificate of incorporation authorizes the Board of Directors of Legacy (the “Legacy Board”) to issue preferred stock without stockholder approval. If the Legacy Board elects to issue preferred stock, it could be more difficult for a third party to acquire us.

In addition, provisions of our amended and restated certificate of incorporation and amended and restated bylaws, including limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of us. Certain provisions of the DGCL may also discourage takeover attempts that have not been approved by the Legacy Board.

Legacy Inc. does not expect to pay dividends on its common stock for the foreseeable future.

We do not expect to pay dividends for the foreseeable future. In addition, our Credit Agreement and term loan credit agreement may prohibit us from paying any dividends without the consent of the lenders under the Credit Agreement and term loan credit agreement, other than dividends payable solely in equity interests of Legacy Inc.

The value of your shares may be diluted by future equity issuances, and shares eligible for future sale may have adverse effects on our share price.

We cannot predict the effect of future sales of shares or the availability of shares for future sales, on the market price of or the liquidity of the market for the shares. Sales of substantial amounts of shares, or the perception that such sales could occur, could adversely affect the prevailing market price of the shares. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Our authorized capital stock consists of 945,000,000 shares of common stock and 105,000,000 shares of preferred stock, a significant portion of which is unissued. We may need to raise a significant amount of capital to fund our drilling program and pay down outstanding indebtedness, including principal, interest and fees due under our Credit Agreement, term loan credit agreement and senior notes, and may raise such capital through the issuance of newly issued common stock or preferred stock. Such issuance and sale of equity could be dilutive to the interests of existing stockholders.

Additionally, the conversion of some or all of our convertible senior notes will dilute the ownership interests of existing stockholders. Any sales in the public market of the common stock issuable upon such conversion could adversely affect the prevailing market price of the shares.

Furthermore, as of October 1, 2018, certain founders of Legacy LP (the “Founding Investors”) and their affiliates, including members of Legacy LP’s management, own 10.62% of our outstanding shares. Legacy LP granted the Founding Investors certain registration rights to have their units registered under the Securities Act (the “Founders Registration Rights Agreement”). The Founding Investors have registration rights with respect to the shares they received pursuant to the Corporate Reorganization. Upon registration, these shares will be eligible for sale into the market without volume limitations. Because of the substantial size of the Founding Investors’ holdings, the sale of a significant portion of these shares, or a perception in the market that such a sale is likely, could have a significant impact on the market price of such shares.

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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

September 20, 2018

8,835(1)

$4.69

—

(1) These units were purchased by the Partnership in satisfaction of certain employee tax withholding obligations at a price of $4.69 per unit, the closing price of Legacy's units on the NASDAQ Global Market on September 20, 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 July 9, 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 July 12, 2018, Exhibit 2.1)
3.1			Amended and Restated Certificate of Incorporation of Legacy Reserves Inc. (filed as Exhibit 3.1 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
3.2			Second Amended and Restated Bylaws of Legacy Reserves Inc. (filed as Exhibit 3.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference).
4.1			Indenture dated September 20, 2018, between Legacy Reserves LP, Legacy Reserves Finance Corporation, the guarantors party thereto and Wilmington Trust, National Association (filed as Exhibit 4.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
10.1			Stipulation and Agreement of Settlement, dated July 6, 2018, by and among Legacy Reserves Inc., Legacy Reserves LP, Legacy Reserves GP, LLC, the other released parties thereto, plaintiff Jeffrey Doppelt, the members of the Settlement Class (as defined therein), and the other releasing parties thereto (filed as Exhibit 10.1 on Legacy Reserves LP's Current Report on Form 8-K (File No. 001-33249) on July 12, 2018, and incorporated herein by reference).
10.2			Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of September 14, 2018, by and among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 333-224182) on September 14, 2018, and incorporated herein by reference).
10.3			Fifth Amendment to Term Loan Credit Agreement, dated as of September 14, 2018, by and among Legacy Reserves LP, Cortland Capital Market Services LLC and the lenders party thereto (filed as Exhibit 10.2 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 333-224182) on September 14, 2018, and incorporated herein by reference).
10.4			Eleventh Amendment dated September 20, 2018 to the Third Amended and Restated Credit Agreement, dated as of April 1, 2014 among Legacy Reserves Inc., the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent and the lenders signatory thereto (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
10.5			Sixth Amendment dated September 20, 2018 to the Term Loan Credit Agreement, dated as of October 30, 2017, among Legacy Reserves Inc., the guarantors named therein, Cortland Capital Market Services LLC, as administrative agent, and the lenders party thereto (filed as Exhibit 10.2 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
10.6			Form of Amendment to Grant of Phantom Units Agreement (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 333-224182) on September 18, 2018, and incorporated herein by reference).
10.7			Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Paul T. Horne (filed as Exhibit 10.1 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
1 0.8			Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and James Daniel Westcott (filed as Exhibit 10.2 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
10.9			Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Kyle M. Hammond (filed as Exhibit 10.3 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).

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10.1			Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Kyle A. McGraw (filed as Exhibit 10.4 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
1 0.11			Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Dan G. LeRoy (filed as Exhibit 10.5 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
1 0.12			Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Micah C. Foster (filed as Exhibit 10.6 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
10.13			Legacy Reserves Inc. 2018 Omnibus Incentive Plan (filed as Exhibit 10.7 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
10.14			Limited Waiver and Letter Agreement, dated October 31, 2018, by and among Legacy Reserves LP, Wells Fargo Bank, National Association and the other parties thereto (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference).





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

* 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 INC.

October 31, 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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Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Legacy Reserves 10-Q2018 Q3 Quarterly report

Content analysis