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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________

Form 10-K

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
☑		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2018
		For the fiscal year ended December 31, 2019
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
☐		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	~~For the transition period from to~~	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			(I.R.S. Employer
incorporation or organization)			Identification No.)

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

Registrant’s telephone number, including area code:

(432) 689-5200

Securities registered pursuant to Section 12(b) of the Act:

~~Common Stock, $0~~None.~~01 par value listed on the NASDAQ Stock Market LLC.~~

Securities registered pursuant to 12(g) of the Act:

None.

______________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o☐ No þ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o☑ No þ☐

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. Yes þ☐ No o☑

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes þ ☑ No o☐

Indicate by check mark ifwhether ~~disclosure~~the ofregistrant ~~delinquent~~is ~~filers~~a ~~pursuant~~large toaccelerated ~~Item~~filer, ~~405~~an ofaccelerated ~~Regulation~~filer, Sa non-Kaccelerated isfiler, ~~not~~a ~~contained~~smaller ~~herein,~~reporting ~~and~~company ~~will~~or ~~not~~an beemerging ~~contained,~~growth tocompany. See the ~~best~~definitions of ~~registrant’s~~“large ~~knowledge~~accelerated filer,” in“accelerated ~~definitive~~filer,” ~~proxy~~“smaller orreporting ~~information~~company” ~~statements~~and ~~incorporated~~"emerging bygrowth ~~reference~~company" in ~~Part~~Rule ~~III~~12b-2 of ~~this~~the ~~Form~~Exchange ~~10-K or any amendment to this Form 10-K~~Act. þ

Large accelerated filer o☐ Accelerated filer þ☐ 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). Yes o☐ No þ☑

The aggregate market value of ~~units~~voting ~~representing~~and ~~limited~~non-voting ~~partner~~stock ~~interests ("units") in Legacy Reserves LP (predecessor registrant to Legacy Reserves Inc.)~~ held by non-affiliates of the registrant ~~was~~as ~~approximately~~of ~~$452.5 million on~~ June 3028, ~~2018,~~2019 ~~based~~was onapproximately $62.901 million ~~per~~based ~~unit,~~upon the ~~last~~closing ~~reported~~price ~~sales~~as ~~price~~reported ofon the ~~units~~OTCPK onof the ~~NASDAQ~~registrant's ~~Global~~common ~~Select~~stock ~~Market~~ on ~~such~~that date.

~~114,810,671~~Indicate ~~shares~~by ofcheck ~~common~~mark ~~stock,~~whether ~~par~~the ~~value~~registrant ~~$0.01~~has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the ~~registrant~~Securities ~~were~~Exchange ~~outstanding~~Act asof 1934 subsequent to the distribution of ~~March 20,~~securities ~~2019~~under a plan confirmed by a court. Yes ☑ No ☐

~~DOCUMENTS~~61,062,850 ~~INCORPORATED~~shares BYof ~~REFERENCE~~common stock, par value $0.01, of the registrant were outstanding as of April 27, 2020.

~~Parts~~Table of ~~the definitive proxy statement for the registrant’s 2019 annual meeting of stockholders are incorporated by reference into Part III of this annual report on Form 10-K.~~Contents

LEGACY RESERVES INC.

Table of Contents

Glossary of Terms		ii			ii
PART I		1			1
ITEM 1.	~~BUSINESS~~	1	BUSINESS	1
ITEM 1A.	~~RISK FACTORS~~	10	RISK FACTORS	9
ITEM 1B.	~~UNRESOLVED STAFF COMMENTS~~	23	UNRESOLVED STAFF COMMENTS	9
ITEM 2.	~~PROPERTIES~~	24	PROPERTIES	10
ITEM 3.	~~LEGAL PROCEEDINGS~~	31	LEGAL PROCEEDINGS	19
ITEM 4.	~~MINE SAFETY DISCLOSURES~~	31	MINE SAFETY DISCLOSURES	19
PART II		32			20
ITEM 5.	~~MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES~~	32	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	20
ITEM 6.	~~SELECTED FINANCIAL DATA~~	33	SELECTED FINANCIAL DATA	21
ITEM 7.	~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~	35	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58
ITEM 8.			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	38
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	58
ITEM 9.			CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	39
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	59
ITEM 9A.			CONTROLS AND PROCEDURES	39
ITEM 9A.	CONTROLS AND PROCEDURES	59
ITEM 9B.			OTHER INFORMATION	41
ITEM 9B.	OTHER INFORMATION	62
PART III					42
PART III		62
ITEM 10.			DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	42
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	62
ITEM 11.			EXECUTIVE COMPENSATION	46
ITEM 11.	EXECUTIVE COMPENSATION	62
ITEM 12.			SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	49
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	62
ITEM 13.			CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	52
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	63
ITEM 14.			PRINCIPAL ACCOUNTING FEES AND SERVICES	52
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	63
PART IV					54
PART IV		63
ITEM 15.			EXHIBITS, FINANCIAL STATEMENT SCHEDULES	54
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	63
ITEM 16.			FORM 10-K SUMMARY	57
ITEM 16.	FORM 10-K SUMMARY	68

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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 development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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, NGLs 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.

NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

PV-10. PV-10 is a compilation of the standardized measure on a pre-tax basis.

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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 or PDNPs. Proved oil and natural gas reserves that are developed behind pipe or 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 natural 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.

iii

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

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 current costs and 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%. Texas margin taxes and the federal income taxes associated with a corporate subsidiary have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure. Standardized measure does not give effect to commodity derivative transactions.

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

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

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

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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:

•the ~~our~~amount ~~ability~~of tooil ~~pursue financial, transactional~~ and ~~other~~natural ~~strategic~~gas ~~alternatives~~we ~~to address our liquidity and capital structure~~produce;

• the ~~adequacy~~price ~~and~~at ~~availability~~which ofwe ~~capital~~are ~~resources,~~able ~~credit and liquidity, including, but not limited~~ to, ~~debt~~sell ~~refinancing or extensions, exchanges or repurchases of debt, issuances of debt or equity securities, access to additional borrowing capacity and~~ our ~~ability~~oil ~~to generate sufficient cash flow from operations to fund our capital expenditures~~ and ~~meeting~~natural ~~working~~gas ~~capital needs~~production;

• our ability to ~~comply~~identify, ~~with~~acquire, ~~renegotiate~~exploit orand ~~receive~~appropriately ~~waivers~~finance ofadditional ~~debt~~oil ~~covenants under our Credit Agreement (as defined below)~~ and ~~our~~natural ~~Term~~gas ~~Loan~~properties ~~Credit~~at ~~Agreement~~economically ~~(as~~attractive ~~defined below)~~prices;

• our ~~business~~ability ~~strategy~~to replace reserves;

•our ~~the~~drilling ~~amount~~locations ofand ~~oil~~our ~~and~~ability ~~natural~~to ~~gas~~continue weour ~~produce~~development activities at economically attractive costs;

• the ~~price~~level atof ~~which~~our welease ~~are~~operating ~~able~~expenses, togeneral ~~sell~~and ~~our~~administrative ~~oil~~costs and ~~natural~~finding ~~gas~~and ~~production~~development costs;

•the ~~our~~level ~~ability~~of toour ~~identify,~~capital ~~acquire, exploit and appropriately finance additional oil and natural gas properties at economically attractive prices~~expenditures;

• our ~~ability~~future tooperating ~~replace reserves and increase reserve value~~results;

•national ~~our drilling locations~~ and ~~our~~global ~~ability~~health tocrises, ~~continue~~including ~~our~~outbreaks, ~~development~~epidemics, ~~activities~~and atpandemics ~~economically~~such ~~attractive~~as ~~costs~~coronavirus ("COVID-19"); and

• ~~the level of~~ our ~~lease~~plans, ~~operating expenses~~objectives, ~~general~~expectations and ~~administrative costs and finding and development costs;~~intentions.

• the level of our capital expenditures;

• 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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PART I

ITEM 1. BUSINESS

References in this annual report on Form 10-K to “Legacy Reserves,” “Legacy,” “we,” “our,” “us,” or like terms refer to Legacy Reserves Inc. and its subsidiaries for the periods after September 19, 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 Reserves Inc.

Legacy Reserves Inc. is a Delaware corporation incorporated in 2018 in connection with the Corporate Reorganization, as defined below. We are an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Our 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, as well as horizontal development of unconventional plays in the Permian Basin, as market conditions allow.

Our oil and natural gas production and reserve data as of December 31, ~~2018~~2019 are as follows:

• we had proved reserves of approximately ~~164~~127.92 MMBoe, of which 6361% were natural gas, 3739% were oil and natural gas liquids (“NGLs”) and 96% were classified as proved developed producing; and

• our proved reserves to production ratio was approximately 98.53 years based on the annualized production volumes for the three months ended December 31, ~~2018~~2019.

We have built a diverse portfolio of oil and natural gas reserves primarily through the acquisition of producing oil and natural gas properties and the development of properties in established producing trends. These acquisitions, along with our ongoing development activities and operational improvements, have allowed us to achieve ~~significant~~ production and reserve growth over the last decade.

On September 20, 2018, we completed our transition to a corporation pursuant to the Amended and Restated Agreement and Plan of Merger, 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, 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; and

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

~~2018~~Emergence ~~and~~from ~~Current~~Voluntary ~~Highlights~~Reorganization under Chapter 11 Proceedings

•On ~~Deployed~~June ~~$229~~18, 2019, Legacy and certain of its subsidiaries (collectively with Legacy, the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).5 ~~million~~On June 19, 2019, the Bankruptcy Court granted a motion seeking joint administration of ~~development~~the ~~capital~~Chapter ~~expenditures~~11 Cases under the caption In re Legacy Reserves Inc., ~~primarily~~et ~~focused~~al. onOn August 2, 2019, the ~~drilling~~Debtors ~~and~~filed ~~completion~~the Joint Chapter 11 Plan of ~~our~~Reorganization ~~Permian~~for ~~Basin~~Legacy ~~horizontal~~Reserves ~~development~~Inc. ~~assets;~~and its Debtor Affiliates (as amended, modified or supplemented from time to time, the “Plan”) with the Bankruptcy Court.

• Increased revenue 27%, relative to 2017, to $554.9 million;

• Increased oil production 32% relative to 2017, to 18,162 Bbls/d;

• Completed our transition to a corporation and commenced trading as Legacy Reserves Inc.

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•On InNovember ~~March~~15, 2019, wethe ~~extended~~Bankruptcy Court entered an order (the ~~term~~“Confirmation onOrder”) ~~our~~confirming ~~Credit~~the ~~Agreement~~Plan, ~~through~~and ~~May~~on 31December 11, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.

Business Strategy

The key elements of our business strategy are to:

• Prudently deploy capital in development opportunities that maximize value;

• Identify, acquire and exploit additional opportunities to broaden our operational footprint and enrich our future growth potential;

• Utilize our extensive Permian portfolio of small-tract acreage to increase our drillable footprint;

• Maintain efficient operations to minimize production declines, improve lifting costs and well economics;

• Rationalize our asset base by regularly reviewing our asset portfolio and divesting non-core assets; and

• Maintain capital budget flexibility to preserve liquidity.

2019 Operating Focus

In 2019, we plan to focus on the development of our Permian Basin horizontal drilling inventory. Our development capital expenditures are expected to be approximately $135 million, subject to any limitations contained in the agreements governing our indebtedness, compared to approximately $229.6 million in 2018 and $176.8 million in 2017. We expect to fund our 2019 investments from cash flow from operations. Should projected commodity prices deviate from our current outlook, we may elect to make adjustments to our level of capital expenditures.

Operating Regions

Permian Basin. The Permian Basin, one of the largest and most prolific oil and natural gas producing basins in the United States, was discovered in 1921 and extends over 100,000 square miles in West Texas and southeast New Mexico. It is characterized by oil and natural gas fields with long production histories and multiple producing formations. These stacked formations have been further drilled and produced following the advent and refinement of horizontal drilling. Currently, the majority of the rigs running in the Permian Basin are drilling horizontal wells. The Permian Basin has historically been our largest operating region ~~and still contains the majority of our drilling locations and development projects~~. Our producing wells in the Permian Basin are generally characterized as oil wells that also produce high-Btu casinghead gas with significant NGL content.

East Texas. We entered the East Texas region through our July 2015 acquisitions in Anderson, Freestone, Houston, Leon, Limestone, Robertson and Shelby ~~counties~~Counties. The properties in East Texas consist of mature, low-decline natural gas wells. The East Texas properties are supported by over 600 miles of natural gas gathering system and a treating plant we acquired as part of those acquisitions.

Rocky Mountain. Our Rocky Mountain region was originally comprised by acquisitions in the Big Horn, Wind River and Powder River Basins in Wyoming largely consisting of mature oil wells with a natural water drive producing primarily from the Dinwoody-Phosphoria, Tensleep and Minnelusa formations. We expanded our footprint with our acquisition of oil properties in North Dakota and Montana in 2012 and our acquisition of non-operated natural gas properties in Colorado in 2014. The North Dakota properties produce primarily from the Madison and Bakken formations, while the Montana properties produce mostly from the Sawtooth and Bowes formations. The Colorado properties produce primarily from the Williams Fork formation.

Mid-Continent. Our properties in the Mid-Continent region are located in Oklahoma. These properties were acquired in 2007.

Our 2proved reserves by operating region as of December 31, 2019 are as follows:

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Proved Reserves by Operating Region as of December 31, 2019
Operating Regions	Oil (MBbls)	Natural Gas (MMcf)	NGLs (MBbls)	Total (MBoe)	% Liquids		% PDP		% Total
Permian Basin	36,407	90,078	825	52,245	71	%	91	%	41	%
East Texas	66	220,586	138	36,969	1	%	100	%	29	%
Rocky Mountain	5,167	153,118	5,177	35,864	29	%	100	%	28	%
Mid-Continent	625	4,309	802	2,145	67	%	91	%	2	%

Total	42,265	468,091	6,942	127,223	39	%			100	%

Our proved reserves by operating region as of December 31, 2018 are as follows:

Proved Reserves by Operating Region as of December 31, 2018
Operating Regions	Oil (MBbls)	Natural Gas (MMcf)	NGLs(MBbls)	Total (MBoe)	% Liquids		% PDP		% Total
Permian Basin	44,671	116,879	660	64,811	70	%	90	%	39	%
East Texas	103	292,249	211	49,022	1	%	100	%	30	%
Rocky Mountain	6,479	206,541	7,257	48,160	29	%	100	%	29	%
Mid-Continent	824	6,051	1,083	2,916	65	%	92	%	2	%
Total	52,077	621,720	9,211	164,909	37	%			100	%

Development Activities

Our development projects are primarily focused on drilling and completing new wells, but also include accessing additional productive or improving existing formations in existing well-bores, and artificial lift equipment enhancement, as well as secondary (waterflood) and tertiary recovery projects.

The table below details the activity in our PUD locations from December 31, ~~2017~~2018 to December 31, ~~2018~~2019:

	Gross Locations		Net Locations		Net Volume (MBoe)
Balance, December 31, 2017	40		20.1		7,963
PUDs converted to PDP by drilling	(19	)	(9.5	)	(5,807	)
PUDs removed due to performance (a)	(2	)	(0.3	)	(89	)
PUDs removed from future drilling schedule (b)	(3	)	(1.0	)	(570	)
Extensions and discoveries (a)	16		10.8		4,659
Other	—		0.3		40
Balance, December 31, 2018	32		20.4		6,196

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	Gross Locations	Net Locations	Net Volume (MBoe)
Balance, December 31, 2018	32	20.4	6,194
PUDs converted to PDP by drilling	(8)	(4.9)	(2,411)

PUDs removed from future drilling schedule (a)	(8)	(3.5)	(1,259)


Extensions and discoveries (b)	10	5.1	2,183
Other	—	(0.1)	(140)
Balance, December 31, 2019	26	17.0	4,568

________________

(a)These ~~PUDs~~PUD ~~removed~~locations ~~due~~were ~~to performance or added due to extensions and discoveries are those PUDs~~ removed orfrom ~~added,~~our asPUD ~~applicable,~~inventory ~~due~~because ~~to new or revised engineering, geologic and economic evaluations such as offset well production data, the drilling~~ of ~~offset~~non-consenting ~~wells,~~working ~~new~~interest ~~geologic data or changes in projected capital costs or product prices~~owners. ~~PUDs~~Due ~~are~~to ~~removed~~their orownership ~~added~~level, ~~depending~~their onconsent ~~whether the technical criteria for the proved undeveloped reserve classification~~ is ~~satisfied~~required ~~and,~~ in ~~the~~order ~~case of additions due~~ to ~~performance,~~develop ~~whether~~ the ~~well is scheduled to be drilled within five years after initial recognition as proved reserves~~PUD.

(b) PUDs removed due to performance or added due to extensions and discoveries are those PUDs removed or added, as applicable, due to new or revised engineering, geologic and economic evaluations such as offset well production data, the drilling of offset wells, new geologic data or changes in projected capital costs or product prices. PUDs are removed or added depending on whether the technical criteria for the proved undeveloped reserve classification is satisfied and, in the case of additions due to performance, whether the well is scheduled to be drilled within five years after initial recognition as proved reserves.

The increases in PUDs due to extensions and discoveries were driven by offset drilling in connection with our drilling program in the Permian Basin, which includes the horizontal Spraberry, horizontal Wolfcamp and horizontal Bone Spring wells.

~~The~~As ~~reduction in PUDs due to performance was due to the removal~~ of ~~PUDs~~December 31, as2019, ~~they~~we ~~became~~identified ~~uneconomic~~11 asgross of(9.5 ~~December 31,~~net) ~~2018~~recompletion ~~based~~and onfracture ~~offset~~stimulation ~~well performance~~projects.

~~(b)~~Excluding ~~These~~any ~~PUD~~potential ~~locations~~acquisitions, ~~were~~we ~~removed~~expect ~~from~~to ~~our~~make ~~PUD~~capital ~~inventory~~expenditures ~~because~~ of ~~non-consenting~~approximately ~~working~~$55 ~~interest~~million ~~owners.~~during ~~Due~~the toyear ~~their~~ending ~~ownership level~~December 31, ~~their consent is required in order to develop the PUD~~2020.

AsA significant portion of ~~December 31,~~our ~~2018~~horizontal operated development activity in the Permian Basin has been pursued through our development agreement (as amended, wethe ~~identified~~"Development 10Agreement") ~~gross~~entered into in 2015 with Jupiter JV, LP (6"Investor"), which was formed by certain of TPG Sixth Street Partners' investment funds.4 ~~net)~~Our ~~recompletion~~capital resources and ~~fracture~~liquidity ~~stimulation~~have ~~projects~~benefited from our interest in the development activity under the Development Agreement as described below.

Excluding any potential acquisitions, we expect to make capital expenditures of approximately $135 million during the year ending December 31, 2019 subject to any limitations contained in the agreements governing our indebtedness.

A significant portion of our horizontal operated development activity in the Permian Basin has been pursued through our development agreement (as amended, the "Development Agreement") entered into in 2015 with Jupiter JV, LP ("Investor"), which

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was formed by certain of TPG Sixth Street Partners' investment funds. Our capital resources and liquidity have benefitted from our interest in the development activity under the Development Agreement as described below.

On August 1, 2017, we, along with Investor, entered into the First Amended and Restated Development Agreement (the “Restated Agreement”), which amended and restated the Development Agreement pursuant to which we and Investor agreed to participate in the funding, exploration, development and operation of certain of our undeveloped oil and gas properties in the Permian Basin. Under the Restated Agreement and through subsequent elections, the parties committed to develop a tranche of 26 wells plus 9 wells in the Restated Agreement's area of mutual interest (the “Second Tranche”). Investor’s share of its development costs was limited to $80 million.

In connection with the Restated Agreement in 2017, we made a payment of $141 million (the “Acceleration Payment”) to cause the reversion of Investor's working interest from 80% to 15% of the parties' combined interests in the 48 wells contained in the first tranche such that our working interest reverted from 20% to 85% of the parties' combined working interests in all such wells, and all undeveloped assets subject to the terms of the Restated Agreement reverted back to us. The reversion of interests as a result of the Acceleration Payment was accounted for as an asset acquisition. Pursuant to the Restated Agreement, Investor funded 40% of the costs to the parties' combined interests to develop the wells in the Second Tranche in exchange for an undivided 33.7% working interest of our original working interest in the wells, subject to a reversionary interest of 6.3% of our original working interest in the wells upon the occurrence of Investor achieving a 15% internal rate of return in the aggregate with respect to such tranche of wells. No additional development is expected to occur pursuant to the Restated Agreement.

The Acceleration Payment was funded by a $145 million draw under our Term Loan Credit Agreement dated as of October 25, 2016, among Legacy Reserves LP, as borrower, the guarantors party thereto, Cortland Capital Market Services LLC, as administrative agent, and the lenders party thereto (the "Term Loan Credit Agreement").

During 2018, we completed several individually immaterial divestitures totaling $55.0 million net of costs subject to customary post-closing obligations. These divestitures consisted of dispositions of unproved leasehold acreage and low-volume, high-cost producing properties and resulted in a gain on disposal of assets of $23.8 million for the year ended December 31, 2018.3

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Oil and Natural Gas Derivative Activities

~~Our~~In ~~business~~order ~~strategy includes entering into oil and natural gas derivative contracts which are designed~~ to mitigate price risk for a portion of our oil and natural gas production, ~~NGL~~we enter into oil and natural gas ~~production~~derivative contracts from time to time. At December 31, ~~2018~~2019, we had in place oil and natural gas derivatives covering portions of our estimated future oil and natural gas production. Our derivative contracts are in the form of fixed price swaps ~~and enhanced swaps~~ for NYMEX WTI oil; fixed price swaps for NYMEX Henry Hub; ~~and~~ fixed price swaps for the Midland-to-Cushing oil ~~differential~~differentials; fixed price swaps for WAHA basis differentials; and fixed price swaps for CIG-Rockies basis differentials.

Marketing and Major Purchasers

For the ~~year~~period ~~ended~~ December 3111, ~~2018~~2019 ~~and~~to ~~2017~~December 31, ~~Legacy~~2019 ~~sold oil~~(Successor), ~~NGL~~the ~~and~~period ~~natural gas production representing 10% or more~~ of ~~total~~January ~~revenues~~1, to2019 ~~the~~through ~~purchasers~~December as10, ~~detailed~~2019 in(Predecessor), ~~the~~and ~~table below. For~~ the ~~year~~years ended December 31, ~~2016~~2018, ~~Legacy~~and ~~did~~2017 ~~not~~(Predecessor), ~~sell~~Legacy sold oil, NGL orand natural gas production representing 10% or more of total ~~revenue~~revenues to ~~any~~the ~~one~~purchasers ~~customer~~as detailed in the table below.

	2018	2017	2016
		Successor		Predecessor
Plains Marketing, LP	20%	10%	6%
		Period from		Period from
Rio Energy International Inc	13%	9%	3%
		December 11, 2019		January 1, 2019
		to December 31,		to December 10,	Year Ended December 31,
		2019		2019	2018	2017
Plains Marketing, LP		15%		19%	20%	10%
Trafigura		21%		19%	9%	1%
Rio Energy International Inc (1)		—%		2%	13%	9%

(1) Less than 1% for the period ended December 11, 2019 to December 31, 2019 (Successor).

Our oil sales prices are based on formula pricing and calculated either using a discount to NYMEX WTI oil or using the appropriate buyer’s posted price less a regional differential and transportation fee.

Although we believe we could identify a substitute purchaser if we were to lose any of our oil or natural gas purchasers, the loss could temporarily cause a loss or deferral of production and sale of our oil and natural gas in that particular purchaser’s service area. However, if one or more of our larger purchasers ceased purchasing oil or natural gas altogether, the loss of any such purchaser could have a detrimental impact on our short-term production volumes and our ability to find substitute purchasers for our production volumes in a timely manner, though we do not believe this would have a long-term material adverse effect on our operations.

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Competition

We operate in a highly competitive environment for acquiring leases and properties, securing and retaining trained personnel and service providers and marketing oil and natural gas. Our competitors may be able to pay more for leases, productive oil and natural gas properties and development projects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Seasonal Nature of Business

The demand for oil and natural gas can be seasonal based on motor vehicle driving patterns and heating and cooling demands related to weather. Our Rockies' oil prices suffer relative to WTI in the winter due to reduced demand for asphaltic crude. Refinery turnarounds in the Permian typically occur in the first quarter, and, historically, we have experienced wider oil differentials during this time.

Environmental Matters and Regulation

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

• require the acquisition of various permits before drilling commences;

~~• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;~~4

•Table ~~limit~~of ~~or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and~~Contents

•restrict ~~require~~the ~~remedial~~types, ~~measures~~quantities toand ~~mitigate~~concentration ~~pollution~~of ~~from~~various ~~former~~substances ~~and~~that ~~ongoing~~can ~~operations,~~be ~~such~~released asinto ~~requirements~~the toenvironment ~~close~~in ~~pits~~connection with oil and ~~plug~~natural ~~abandoned~~gas ~~wells.~~drilling and production activities;

•limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

•require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, may impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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We currently own, lease, or operate numerous properties that have been used for oil and natural gas development and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, most of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed of substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990, as amended or OPA, which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that cause a release of oil into waters of the United States. In addition, owners and operators of facilities that store oil above threshold amounts must develop and implement spill response plans.

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Safe Drinking Water Act. Our injection well facilities may be regulated under the Underground Injection Control, or UIC, program established under the Safe Drinking Water Act, or SDWA. The state and federal regulations implementing that program require mechanical integrity testing and financial assurance for wells covered under the program. The federal Energy Policy Act of 2005 amended the UIC provisions of the federal SDWA to exclude hydraulic fracturing from the definition of underground injection. From time to time, Congress has considered bills to repeal this exemption. The EPA conducted a study of hydraulic fracturing and issued a final report in December 2016. This study and other studies that may be undertaken by EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other statutory and/or regulatory mechanisms.

Endangered Species Act. Additionally, environmental laws such as the Endangered Species Act, or ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. Though the rule listing the Lesser Prairie Chicken was vacated, portions of our properties in New Mexico and west Texas are enrolled in Habitat Conservation Plans and as a result we are subject to certain practices and restrictions designed to protect the habitat of the Lesser Prairie Chicken. We believe that we are in substantial compliance with the ESA and the practices and restrictions related to the Lesser Prairie Chicken should not result in material costs or constraints to our operations. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Air Emissions. The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the ~~ESA~~Federal Clean Air Act and ~~the~~associated ~~practices~~state laws and ~~restrictions~~regulations. ~~related~~In toaddition, ~~the~~more ~~Lesser~~stringent ~~Prairie~~federal, ~~Chicken~~state ~~should~~and ~~not~~local regulations could result in ~~material~~increased costs orand ~~constraints~~the toneed ~~our~~for ~~operations~~operational changes. ~~However~~ Finally, the ~~designation~~EPA ofissued ~~previously~~rules ~~unidentified~~in ~~endangered~~May or2016 ~~threatened~~covering ~~species~~methane ~~could~~emissions ~~cause~~from usnew tooil ~~incur~~and natural gas industry operations which could result in additional costs orand ~~become~~restrictions ~~subject~~on our operations. In September 2019, the EPA issued proposed amendments to ~~operating~~the ~~restrictions~~2016 orrule ~~bans~~that inwould rescind methane emissions standards for the ~~affected~~oil ~~areas~~and gas industry.

Air Emissions. The Federal Clean Air Act, and comparable state laws, regulates emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources including pursuing the energy extraction sector under a National Compliance Initiative. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. In addition, more stringent federal, state and local regulations, such as the EPA rules issued in May 2016 regarding the aggregation of exploration and production equipment as a single source could result in increased costs and the need for operational changes. Finally, the EPA issued rules in May 2016 covering methane emissions from new oil and natural gas industry operations which could result in additional costs and restrictions on our operations.

OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.

In 2009, the EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources, including the oil and natural gas production industry. In May 2016, the EPA finalized regulations that establish new controls for emissions of methane and volatile organic compounds from oil and natural gas operations. In September 2019, EPA released proposed amendments to the new source performance standards (“NSPS”) for the oil and gas industry, which would remove all sources in the transmission and storage segments of the industry from regulation under the NSPS and would rescind the methane requirements in the 2016 NSPS that apply to sources in the production and processing segments of the industry. Additional regional, federal or state requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our products. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2019. Additionally, as of the date of this document, we are not aware of any environmental issues or claims that require material capital expenditures during 2020. However, we cannot assure investors that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.

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In 2009, the EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources, including the oil and natural gas production industry. In May 2016, the EPA finalized regulations that establish new controls for emissions of methane and volatile organic compounds from oil and natural gas operations. Additional regional, federal or state requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our products. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2018. Additionally, as of the date of this document, we are not aware of any environmental issues or claims that require material capital expenditures during 2019. However, we cannot assure investors that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.

National Environmental Policy Act and Activities on Federal Lands. Oil and natural gas exploitation and production activities on federal lands are subject to NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Our current production activities, as well as proposed development plans, on federal lands require governmental permits or similar authorizations that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Federal, State or Native American Leases. Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, or BLM, and other agencies. For example, in September 2018, the BLM finalized regulations which update standards to reduce venting and flaring from oil and gas production on public lands.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

•the surface use and restoration of properties upon which wells are drilled;

•the plugging and abandoning of wells; and

•notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally regulate and seek to restrict the venting or flaring of natural gas and impose requirements regarding the ratability of production. As of April 2020, some states, including Texas and Oklahoma, have considered proration of oil production in response to market conditions. These laws and regulations, and any future laws or regulations, may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

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•conditions and rates for interstate transportation, storage and various other matters, primarily by the ~~surface~~Federal ~~use~~Energy Regulatory Commission, or the FERC. Federal and ~~restoration~~state ofregulations ~~properties~~govern ~~upon~~the ~~which~~price ~~wells~~and ~~are~~terms ~~drilled;~~for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or pro-ration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally regulate and seek to restrict the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural gas regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or the FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State regulation. The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. New Mexico currently imposes a 3.75% severance tax on both oil and natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

As of December 31, ~~2018~~2019, we had ~~337~~317 employees, none of whom are subject to collective bargaining agreements. We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed. We believe that we have a favorable relationship with our employees.

Offices

Our principal offices are located in Midland, Texas at 303 W. Wall Street. In addition to our principal offices, we have regional offices located in Cody, Wyoming, and in The Woodlands, Texas.

Available Information

Additional information can be found on our website, www.legacyreserves.com. The information on our website is not, and shall not be deemed to be, a part of this annual report on Form 10-K or incorporated into any of our other filings with the U.S. Securities Exchange Commission ("SEC"). On January 2, 2020, we provided certification and notice of termination of the registration of our common stock under Section 12(g) of the Securities Exchange Act of 1934 (the “Exchange Act”), and therefore, do not have an ongoing obligation to file certain reports pursuant to Section 13 or 15(d) of the Exchange Act.

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~~Available~~ITEM ~~Information~~1A.RISK FACTORS

~~We make available free of charge on our website, www~~None.legacyreserves.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such information with, or furnish it to, the Securities and Exchange Commission ("SEC"). The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

~~The~~ITEM ~~information~~1B.UNRESOLVED onSTAFF ~~our website is not, and shall not be deemed to be, a part of this annual report on Form 10-K or incorporated into any of our other filings with the SEC.~~COMMENTS

None.

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ITEM 1A2. ~~RISK FACTORS~~PROPERTIES

~~Risks~~As ~~Related~~of December 31, 2019, we owned interests in producing oil and natural gas properties in 530 fields in the Permian Basin, East Texas, Piceance Basin of Colorado, Wyoming, North Dakota, Montana, Oklahoma and several other states, from 8,952 gross productive wells of which 2,770 are operated and 6,182 are non-operated. The following table sets forth information about our proved oil and natural gas reserves as of December 31, 2019. The PV-10 amounts shown in the table are not intended to represent the current market value of our ~~Business~~estimated oil and natural gas reserves. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. For a definition of “standardized measure,” please see the glossary of terms at the beginning of this annual report on Form 10-K.

We have determined, and our independent registered public accounting firm has concurred, that there is substantial doubt about our ability to continue as a going concern.


	As of December 31, 2019
	Proved Reserves								PV-10 (b)
Field or Region	MMBoe	R/P (a)	% Oil and NGLs		Amount		% of Total
					($ in Millions)
Spraberry Field (c)	24.2	7.4	70	%	$	308.8	38	%
Lea Field	7.7	5.3	71		111.1		14
East Texas (d)	36.7	9.8	—		92.4		12
Piceance Basin (e)	30.8	10.4	18		50.2		6
Total — Top 4	99.4	8.7	28	%	$	562.6	70	%
All others	27.8	7.0	76		243.6		30
Total	127.2	8.3	39	%	$	806.2	100	%

We have significant obligations and commitments coming due in the near term. On March 21, 2019, we entered into an amendment to the Credit Agreement pursuant to which the lenders agreed to extend the maturity date from April 1, 2019 to May 31, 2019. Without additional sources of capital or a significant restructuring of our balance sheet, the maturity of our Credit Agreement raises substantial doubt about our ability to continue as a going concern, which means that we may be unable to continue operations for the foreseeable future or realize assets and discharge liabilities in the ordinary course of operations. As a result, our independent registered public accounting firm included an explanatory paragraph with respect to this uncertainty in its report that is included with our financial statements in this annual report on Form 10-K. Such explanatory paragraph may materially and adversely affect the price per share of our common stock and may otherwise limit our ability to raise additional funds through the issuance of debt or equity securities or otherwise. Further, the perception that we may be unable to continue as a going concern may impede our ability to raise additional funds or operate our business due to concerns with respect to our ability to discharge our contractual obligations.__________________

~~We have prepared our financial statements on~~ (a)Reserves ~~going~~as ~~concern basis, which contemplates that we will be able to realize our assets and discharge our liabilities and commitments in the ordinary course~~ of business. Our financial statements included in this annual report on Form 10-K do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty. Without additional capital or a significant restructuring of our balance sheetDecember 31, ~~however,~~2019 wedivided ~~may~~by beannualized ~~unable~~fourth toquarter ~~continue~~production ~~as a viable entity, in which case our stockholders may lose all or some of their investment in us~~volumes.

We(b)PV-10 ~~have~~is ~~engaged~~derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. We believe that the presentation of PV-10 is relevant and ~~legal~~useful ~~advisors~~to investors because it presents the discounted future net cash flows attributable to ~~assist~~our usestimated ~~in,~~proved ~~among~~reserves ~~other~~prior ~~things~~to taking into account future corporate income taxes, and it is a useful measure for evaluating ~~financial~~the relative monetary significance of our oil and natural gas assets. Further, ~~transactional~~investors may utilize the measure as a basis for comparison of the relative size and ~~other~~value ~~strategic~~of ~~alternatives~~our reserves to ~~address~~other companies. We use this measure when assessing the potential return on investment related to our ~~liquidity~~oil and ~~capital~~natural ~~structure~~gas ~~that~~assets. ~~may~~PV-10, behowever, ~~time~~is ~~consuming,~~not ~~disruptive~~a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and ~~costly~~the standardized measure of discounted future net cash flows do not purport to present the fair value of our ~~business~~oil and natural gas reserves. The below table provides a reconciliation of the GAAP standardized measure to PV-10 (non-GAAP) at December 31, 2019.

As a result of extremely challenging current market conditions and our upcoming debt maturities, on March 13, 2019, we announced that we engaged financial and legal advisors to assist in evaluating financial, transactional and other strategic alternatives to address our liquidity and capital structure. The process of exploring strategic alternatives may be time consuming and disruptive to our business operations and may impair our ability to retain and motivate key personnel. We may incur substantial expenses associated with identifying, evaluating and preparing for any such strategic alternatives. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets. There can be no assurance that sufficient liquidity can be raised from any one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations or at all.


	December 31,
	2019
	(In millions)
Standardized measure of discounted net cash flows	$	716,734
Present value of future income taxes discounted at 10%	89,460
PV-10	806,194

We(c)As ~~may need to seek relief under~~ the U.Spraberry S.Field ~~Bankruptcy~~contains ~~Code~~24,212 ~~even if we are successful in effecting a financial~~MBoe, ~~transactional~~ or ~~other strategic alternative~~19.0% ~~Any~~of ~~bankruptcy~~total ~~proceeding~~proved ~~may~~reserves ~~result~~of in127,223 ~~holders~~MBoe, ofthe ~~our~~following ~~equity~~table ~~securities~~presents ~~and~~the ~~our~~production, ~~other~~by ~~stakeholders~~product, ~~receiving~~for ~~little~~the orSpraberry ~~no consideration~~Field.

It may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code. Such a proceeding could be commenced in the near term and requires our conducting of preparatory work. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.

If we are unable to refinance or repay our indebtedness under our Credit Agreement when it comes due or otherwise fail to comply with certain restrictions and financial covenants in our Credit Agreement and Term Loan Credit Agreement, we could be in default under our Credit Agreement or Term Loan Credit Agreement which may result in acceleration or repayment of all of our outstanding indebtedness.

We could default on the payment of our indebtedness under our Credit Agreement when it comes due which may result in acceleration of all amounts outstanding under our Credit Agreement or foreclosure on our oil and natural gas properties. Additionally, our Credit Agreement and our Term Loan Credit Agreement restrict, among other things, our ability to incur debt and requires us

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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. 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. On March 21, 2019, we received a waiver of certain covenants under our Credit Agreement and Term Loan Credit Agreement. The waiver received under our Term Loan Credit Agreement is temporary such that we will be in default for the failure to have delivered audited financial statements without a “going concern” or like qualification or exception as of May 31, 2019, the same day as the scheduled maturity of our Credit Agreement. Further, upon delivery of our financial statements for the quarter ended March 31, 2019, we expect to be in violation of the current ratio covenant under our Credit Agreement, which would constitute a default under the Credit Agreement. Although we have received waivers from our lenders under the Credit Agreement and the Term Loan Credit Agreement in the past, there can be no assurances that we will receive any waivers in the future. If the lenders under our Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under our Credit Agreement or Term Loan Credit Agreement as a result of any such 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.


	Successor	Predecessor
	Period from	Period from
	December 11, 2019	January 1, 2019
	to December 31,	to December 10,	Year Ended December 31,
(In thousands, except daily production)	2019	2019	2018	2017

Oil (MBbls)	186	1,908	2,230	1,167
Natural gas liquids (Mgal)	26	414	150	271
Natural gas (MMcf)	268	4,040	3,973	2,130
Total (Mboe)	231	2,591	2,896	1,528
Average daily production (Boe per day)	11,014	7,533	7,934	4,186

~~Our~~(d)As ~~substantial~~East ~~indebtedness~~Texas contains 36,713 ~~liquidity~~MBoe, ~~issues~~or ~~and~~28.9% ~~the~~of ~~potential~~total ~~for~~proved ~~strategic~~reserves ~~alternatives~~of or127,223 ~~restructuring~~MBoe, ~~transactions~~the ~~may~~following ~~impact~~table ~~our~~presents ~~business~~the production, ~~financial~~by ~~condition~~product, ~~and~~for ~~operations~~East Texas.

Due to our substantial indebtedness, liquidity issues and the potential for strategic alternatives or restructuring transactions, there is risk that, among other things:


	Successor	Predecessor
	Period from	Period from
	December 11, 2019	January 1, 2019
	to December 31,	to December 10,	Year Ended December 31,
(In thousands, except daily production)	2019	2019	2018	2017

Oil (MBbls)	1	10	10	15
Natural gas liquids (Mgal)	53	910	986	1,139
Natural gas (MMcf)	1,302	21,718	24,517	27,737
Total (Mboe)	219	3,651	4,120	4,665
Average daily production (Boe per day)	10,441	10,614	11,288	12,781

•(e)As ~~third~~the ~~parties’~~Piceance ~~confidence~~Basin incontains ~~our~~30,819 ~~ability~~MBoe, toor ~~develop~~24.2% ~~oil~~of ~~and~~total ~~natural~~proved ~~gas~~reserves ~~properties~~of ~~could~~127,223 ~~erode~~MBoe, ~~which~~the ~~could~~following ~~impact~~table ~~our~~presents ~~ability~~the toproduction, ~~execute~~by onproduct, ~~our~~for ~~business~~the ~~strategy;~~Piceance Basin.

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


	Successor	Predecessor
	Period from	Period from
	December 11, 2019	January 1, 2019
	to December 31,	to December 10,	Year Ended December 31,
(In thousands, except daily production)	2019	2019	2018	2017

Oil (MBbls)	2	31	38	48
Natural gas liquids (Mgal)	1,364	22,131	31,237	22,110
Natural gas (MMcf)	737	16,658	19,387	22,065
Total (Mboe)	157	3,334	4,013	4,252
Average daily production (Boe per day)	7,491	9,693	10,995	11,649

•Summary ~~employees could be distracted from performance~~ of ~~their~~Oil ~~duties~~and orNatural ~~more~~Gas ~~easily~~Properties ~~attracted~~and ~~to other career opportunities;~~Projects

•Our wemost ~~could~~significant ~~lose~~fields ~~some~~and orregions aare ~~significant~~Spraberry, ~~portion~~East ~~of our liquidity~~Texas, ~~either~~Lea ~~due~~and toPiceance ~~stricter~~Basin. ~~credit~~As ~~terms~~of ~~from vendors~~December 31, or2019, inthese ~~the~~four ~~event~~areas weaccounted ~~undertake~~for aapproximately ~~Chapter~~70% 11of ~~proceeding~~our ~~and conclude that we need to procure debtor~~PV-~~in-possession~~10 ~~financing,~~and an78% ~~inability to obtain any needed debtor-in-possession financing or to provide adequate protection to certain secured lenders to permit us to access some or all~~ of our ~~cash;~~total ~~and~~estimated proved reserves.

• 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.

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

Lower oil and natural gas prices will 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;

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•Spraberry ~~technological~~Field. ~~advances~~The ~~affecting~~Spraberry ~~energy~~field ~~production~~is located in Andrews, Howard, Midland, Martin, Reagan and ~~consumption;~~Upton Counties, Texas. This Spraberry field summary includes wells in the War San field which produce from the same formations and in the same area as our Spraberry field wells. This field produces from Spraberry and Wolfcamp age formations from 5,000 to 11,000 feet. We operate 163 active wells (158 producing, 5 injecting) in this field with working interests ranging from 12.9% to 100% and net revenue interests ranging from 9.6% to 90.8%. We also own another 283 non-operated wells (279 producing, 4 injecting). As of December 31, 2019, our properties in the Spraberry field contained 24,212 MBoe (70.1% liquids) of net proved reserves with a PV-10 of $308.8 million. The average net daily production from this field was 8,952 Boe/d for the fourth quarter of 2019. The estimated reserve life (R/P) for this field is 7.4 years based on the annualized fourth quarter production rate.

•11 ~~domestic~~wells ~~and~~were ~~foreign~~drilled ~~governmental~~on ~~regulations~~our ~~and~~properties ~~taxes;~~in the Spraberry field in 2019. We have identified 13 more proved undeveloped projects, all of which are horizontal Wolfcamp or horizontal Spraberry locations. We have also identified numerous unproved drilling locations in this field.

•Lea Field. The Lea field is located in Lea County, New Mexico. Our Lea field properties consist primarily of interests in the ~~proximity~~Lea Unit. The majority of the production from these properties is from the Bone Spring formation at depths of 9,500 ~~cost~~feet to 11,500 ~~availability~~feet. ~~and~~These ~~capacity~~properties ofalso ~~oil~~produce from the Morrow, Devonian, Delaware and ~~natural~~Pennsylvania ~~gas~~formations ~~pipelines~~at depths ranging from 6,500 feet to 14,500 feet. We operate 54 wells (54 producing, 0 injecting) in the Lea field with working interests ranging from 28.0% to 93.2% and ~~other~~net ~~transportation~~revenue ~~facilities;~~interests ranging from 29.2% to 78.0%. As of December 31, 2019, our properties in the Lea field contained 7,676 MBoe (71% liquids) of net proved reserves with a PV-10 of $111.1 million. The average net daily production from this field was 4,000 Boe/d for the fourth quarter of 2019. The estimated reserve life (R/P) of the field is 5.3 years based on the annualized fourth quarter production rate.

•3 ~~the~~wells ~~impact~~were ofdrilled on our properties in the ULea field in 2019.S Our engineers have identified two behind-pipe or proved developed non-producing recompletion projects in this field. ~~dollar~~We ~~exchange~~have ~~rates~~also onidentified ~~oil~~numerous ~~and~~unproved ~~natural~~horizontal ~~gas~~drilling ~~prices;~~locations ~~and~~in this field.

•East Texas. Legacy's wells in the ~~price~~East Texas Basin are primarily located in Freestone, Leon and ~~availability~~Robertson Counties, Texas. The wells in our East Texas fields are produced from multiple fields and formations which primarily include the Bossier and Cotton Valley formations at depths of ~~alternative~~approximately ~~fuels~~12,000 to 14,000 feet. Legacy owns approximately 20,000 net undeveloped acres in the Shelby Trough and approximately 17,000 net undeveloped acres in the Freestone Cotton Valley. Legacy operates 879 active wells (874 producing, 5 injecting) in East Texas with working interests ranging from 20.0% to 100% and net revenue interests ranging from 3.2% to 100.0%. We also own another 529 non-operated wells (512 producing, 17 injecting). As of December 31, 2019, our properties in East Texas contained 36,713 MBoe of net proved reserves with a PV-10 of $92.4 million. The average net daily production from this field was 10,222 Boe/d for the fourth quarter of 2019. The estimated reserve life (R/P) for this field is 9.8 years based on the annualized fourth quarter production rate.

~~Historically,~~Piceance ~~oil~~Basin. ~~and~~Legacy's ~~natural~~wells ~~gas~~in ~~prices~~the ~~have~~Piceance ~~been~~Basin ~~extremely~~are ~~volatile.~~located ~~For~~in ~~example~~Garfield County, ~~for~~Colorado in the ~~five~~Grand ~~years~~Valley, ~~ended~~Parachute ~~December~~and ~~31,~~Rulison ~~2018,~~fields. ~~the~~Most ~~NYMEX-WTI~~of ~~oil~~the ~~price~~wells ~~ranged~~in ~~from~~these afields ~~high~~produce offrom ~~$107.95~~the ~~per~~Williams ~~Bbl~~Fork toformation aat ~~low~~depths of ~~$26.19~~approximately ~~per~~7,000 ~~Bbl~~to 9,000 ~~while~~feet ~~the~~and ~~NYMEX-Henry~~some ~~Hub~~wells ~~natural~~produce ~~gas~~from ~~price~~the ~~ranged~~Wasatch ~~from~~formation aat ~~high~~depths of $81,600 to 4,000 feet.15 ~~per~~Legacy's ~~MMBtu~~ownership toin athis ~~low~~basin is comprised of ~~$1.49~~non-operated ~~per~~interests ~~MMBtu~~in 2,676 active wells acquired in 2014. As of ~~February 28~~December 31, 2019, ~~the~~our ~~NYMEX~~properties ~~WTI~~in ~~oil~~the ~~spot~~Piceance ~~price~~Basin ~~was~~contained ~~$57.21~~30,819 ~~per~~MBoe ~~Bbl~~(18% ~~and~~liquids) ~~the~~of ~~NYMEX-Henry~~net ~~Hub~~proved ~~natural~~reserves ~~gas~~with ~~spot~~a ~~price~~PV-10 ~~was~~of $250.892 ~~per MMBtu~~million. If ~~oil~~The ~~and~~average ~~natural~~net ~~gas~~daily ~~prices~~production ~~decline~~ from ~~current~~this ~~levels~~field was 8,122 itBoe/d ~~may~~for ~~have~~the afourth ~~material~~quarter ~~adverse~~of ~~effect~~2019. The estimated reserve life (R/P) for this field is 10.4 years based on ~~our~~the ~~operations~~annualized ~~and~~fourth ~~financial~~quarter ~~condition~~production rate.

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. Historically, we have also acquired additional oil and natural gas reserves through acreage trades with other producers and we may not be able to identify or execute attractive acreage trades in the future. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties, including through acreage trades, 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.

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

As of December 31, 2018, we had total 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.

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.

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

Our development and acquisition activities require substantial capital expenditures. 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.

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, materials, 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;

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• blowouts, craterings and explosions;

• interference from new well stimulation;

• offset operations causing irregularities or interruptions in production; and

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

Furthermore, our drilling and producing operations produce significant amounts of water and inadequate access to or availability of water disposal infrastructure could adversely affect our production volumes or significantly increase the costs of our operations.

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 2019. This environment could cause the prices for oil to fall to lower levels.

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, 2018, we incurred impairment charges of $68.0 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.

Increases in the cost 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.

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.

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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, 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 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.

Decreases 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 May 31, 2019, limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. As of March 13, 2019, our borrowing base was $575.0 million and we had approximately $2.9 million available for borrowing. Under the terms of our Credit Agreement, our borrowing base reduces to $570.0 million on May 22, 2019. 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 drawn $338.6 million.

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Our Credit Agreement provides for the mandatory termination of our derivative contracts three days prior to the maturity date of our Credit Agreement. Such terminations would result in a reduction of the borrowing base under our Credit Agreement.

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.

Any decrease of our borrowing base 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.”

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:

• 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 lack of capital could cause the development of any acquisitions to be slower than forecasted;

• 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

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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.

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 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 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 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.

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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. Compliance with these requirements could increase our costs of development and production, which costs may be significant.

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. Further, if the lenders under our Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness as a result of a default under the Credit Agreement or Term Loan Credit Agreement, such acceleration could cause a cross-default of all our other outstanding indebtedness, including the Senior Notes, and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. 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

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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 trailing 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, 2018, we recalculated the value of our proved reserves as of December 31, 2018 using the five-year average forward price as of February 25, 2019 for both WTI oil and NYMEX natural gas. While this 5-year NYMEX forward strip price is not necessarily indicative of our overall outlook on future commodity prices, this commonly used methodology may help provide investors with an understanding of the impact of a volatile commodity price environment. Under such assumptions, we estimate the cumulative projected production from our year-end proved reserves would decrease by approximately 8.0% to 151.7 MMBoe from our previously reported 164.9 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 our Credit Agreement is at variable interest rates, we have significant exposure to increases in interest rates. As a result, our business, results of operations, cash flows from operations and financial condition 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.

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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.

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, including acreage trades, 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,

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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.

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, swaps 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 our 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 revolving 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 revolving credit facility. 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.

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Our ability to use our net operating loss carryforwards and certain other tax attributes may be limited.

We have incurred net losses since our Corporate Reorganization and may continue to incur net losses in the future. Generally, losses incurred will carry forward until such losses are used to offset future taxable income, if any. Under Sections 382 and 383 of the Internal Revenue Code, if a corporation undergoes an “ownership change,” generally defined as a greater than 50 percentage point change (by value) in its equity ownership by certain stockholders over a three year period, the corporation’s ability to use its pre-change net operating loss, or NOL, carryforwards and other pre-change tax attributes (such as tax credits) to offset its post-change income or taxes may be limited. We may experience ownership changes in the future as a result of shifts in our stock ownership (some of which shifts are outside our control). If we were to experience an ownership change, we could potentially have, in the future, higher U.S. federal income tax liabilities than we would otherwise have had and it may also result in certain other adverse consequences to us. Similar provisions of state tax law may also apply to limit our use of state tax attributes.

Risks Related to the Common Stock

We may pursue financial, transactional and other strategic alternatives which could adversely affect the holders of our common stock through dilution or loss in value.

Any financial, transactional or other strategic alternative may include the issuance of additional debt and/or equity securities in exchange for outstanding indebtedness. Any debt securities or preferred stock that might be issued could have liquidation rights, preferences and privileges senior to those of our outstanding common stock. The issuance of additional equity and other securities could also be dilutive to existing stockholders and we cannot predict the extent of this dilution. Additionally, any restructuring could result in the holders of our common stock retaining only a limited portion of the equity of the company or even receiving no value for their holdings.

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, sales of our common stock by significant stockholders, 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 our performance may also affect our stock price.

We may not be able to maintain our listing on the NASDAQ Global Select Market.

NASDAQ has established certain standards for the continued listing of a security on the NASDAQ Global Select Market. The standards for continued listing include, among other things, that the minimum bid price for the listed securities not fall below $1.00 per share for a period of 30 consecutive trading days. Although we are currently in compliance with the minimum bid price requirement, as of the filing of this annual report on Form 10-K, our minimum bid price was below $1.00 since March 14, 2019. If we do not satisfy any of the NASDAQ’s continued listing standards, our common stock could be delisted. Any such delisting could adversely affect the market liquidity of our common stock and the market price of our common stock could decrease. A delisting could adversely affect our ability to obtain financing for our operations or result in a loss of confidence by investors, customers, suppliers or employees.

Our amended and restated certificate of incorporation and second amended and restated bylaws contain provisions 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.

There are provisions in our amended and restated certificate of incorporation and second 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 our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors 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 second 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 our Board of Directors.

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We do not expect to pay dividends on our 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 pay down outstanding indebtedness, including principal, interest and fees due under our Credit Agreement, term loan credit agreement and senior notes, to fund our drilling program 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

As of December 31, 2018, we owned interests in producing oil and natural gas properties in 555 fields in the Permian Basin, East Texas, Piceance Basin of Colorado, Wyoming, North Dakota, Montana, Oklahoma and several other states, from 9,263 gross productive wells of which 2,943 are operated and 6,320 are non-operated. The following table sets forth information about our proved oil and natural gas reserves as of December 31, 2018. The PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. For a definition of “standardized measure,” please see the glossary of terms at the beginning of this annual report on Form 10-K.

	As of December 31, 2018
	Proved Reserves				PV-10 (b)
Field or Region	MMBoe	R/P (a)	% Oil and NGLs		Amount		% of Total
					($ in Millions)
Spraberry Field (c)	25.6	8.4	72	%	$	445.5	33	%
Lea Field	9.4	5.0	74		187.5		14
East Texas (d)	48.5	12.1	—		175.9		13
Piceance Basin (e)	41.9	10.6	18		108.8		8
Total — Top 4	125.4	9.7	27	%	$	917.7	68	%
All others	39.5	8.9	71		432.3		32
Total	164.9	9.5	37	%	$	1,350.0	100	%

__________________

(a) Reserves as of December 31, 2018 divided by annualized fourth quarter production volumes.

(b) PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. The below table provides a reconciliation of the GAAP standardized measure to PV-10 (non-GAAP) at December 31, 2018. As Legacy was a pass-through entity not subject to income taxes in 2017 and 2016, no income taxes were included in the computation of standardized measure for those years.

	December 31,
	2018
	(In millions)
Standardized measure of discounted net cash flows	$	1,197,613
Present value of future income taxes discounted at 10%	152,361
PV-10	1,349,974

(c) As the Spraberry Field contains 25,585 MBoe, or 15.5% of total proved reserves of 164,895 MBoe, the following table presents the production, by product, for the Spraberry Field for 2018, 2017 and 2016.

	Year Ended December 31,
	2018	2017	2016
	(In thousands, except daily production)
Oil (MBbls)	2,230	1,167	429
Natural gas liquids (Mgal)	150	271	448
Natural gas (MMcf)	3,973	2,130	1,400
Total (Mboe)	2,896	1,528	673
Average daily production (Boe per day)	7,934	4,186	1,839

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(d) As East Texas contains 48,490 MBoe, or 29.4% of total proved reserves of 164,895 MBoe, the following table presents the production, by product, for East Texas for 2018, 2017 and 2016.

	Year Ended December 31,
	2018	2017	2016
	(In thousands, except daily production)
Oil (MBbls)	10	15	17
Natural gas liquids (Mgal)	986	1,139	1,117
Natural gas (MMcf)	24,517	27,737	30,315
Total (Mboe)	4,120	4,665	5,097
Average daily production (Boe per day)	11,288	12,781	13,926

(e) As the Piceance Basin contains 41,886 MBoe, or 25.4% of total proved reserves of 164,895 MBoe, the following table presents the production, by product, for the Piceance Basin for 2018, 2017 and 2016.

	Year Ended December 31,
	2018	2017	2016
	(In thousands, except daily production)
Oil (MBbls)	38	48	52
Natural gas liquids (Mgal)	31,237	22,110	22,288
Natural gas (MMcf)	19,387	22,065	24,206
Total (Mboe)	4,013	4,252	4,617
Average daily production (Boe per day)	10,995	11,649	12,615

Summary of Oil and Natural Gas Properties and Projects

Our most significant fields and regions are Spraberry, East Texas, Lea and Piceance Basin. As of December 31, 2018, these four areas accounted for approximately 68% of our PV-10 and 76% of our total estimated proved reserves.

Spraberry Field. The Spraberry field is located in Andrews, Howard, Midland, Martin, Reagan and Upton Counties, Texas. This Spraberry field summary includes wells in the War San field which produce from the same formations and in the same area as our Spraberry field wells. This field produces from Spraberry and Wolfcamp age formations from 5,000 to 11,000 feet. We operate 167 active wells (162 producing, 5 injecting) in this field with working interests ranging from 12.9% to 100% and net revenue interests ranging from 9.6% to 90.8%. We also own another 230 non-operated wells (225 producing, 5 injecting). As of December 31, 2018, our properties in the Spraberry field contained 25,585 MBoe (72.4% liquids) of net proved reserves with a PV-10 of $445.5 million. The average net daily production from this field was 8,326 Boe/d for the fourth quarter of 2018. The estimated reserve life (R/P) for this field is 8.4 years based on the annualized fourth quarter production rate.

25 wells were drilled on our properties in the Spraberry field in 2018. We have identified 13 more proved undeveloped projects, all of which are horizontal Wolfcamp or horizontal Spraberry locations. We have also identified numerous unproved drilling locations in this field.

Lea Field. The Lea field is located in Lea County, New Mexico. Our Lea field properties consist primarily of interests in the Lea Unit. The majority of the production from these properties is from the Bone Spring formation at depths of 9,500 feet to 11,500 feet. These properties also produce from the Morrow, Devonian, Delaware and Pennsylvania formations at depths ranging from 6,500 feet to 14,500 feet. We operate 46 wells (45 producing, 1 injecting) in the Lea Field with working interests ranging from 19.8% to 91.3% and net revenue interests ranging from 5.1% to 76.6%. As of December 31, 2018, our properties in the Lea Field contained 9,444 MBoe (74% liquids) of net proved reserves with a PV-10 of $187.5 million. The average net daily production from this field was 5,233 Boe/d for the fourth quarter of 2018. The estimated reserve life (R/P) of the field is 5.0 years based on the annualized fourth quarter production rate.

13 wells were drilled on our properties in the Lea field in 2018. Our engineers have identified one additional proved undeveloped horizontal Bone Spring drilling location and two behind-pipe or proved developed non-producing recompletion projects in this field. We have also identified numerous unproved horizontal drilling locations in this field.

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East Texas. Legacy's wells in the East Texas basin are primarily located in Freestone, Leon and Robertson Counties, Texas. The wells in our East Texas fields are produced from multiple fields and formations which primarily include the Bossier and Cotton Valley formations at depths of approximately 12,000 to 14,000 feet. Legacy owns approximately 20,000 net undeveloped acres in the Shelby Trough and approximately 17,000 net undeveloped acres in the Freestone Cotton Valley. Legacy operates 882 active wells (876 producing, 6 injecting) in East Texas with working interests ranging from 19.2% to 100% and net revenue interests ranging from 3.2% to 87.5%. We also own another 529 non-operated wells (512 producing, 17 injecting). As of December 31, 2018, our properties in East Texas contained 48,490 MBoe of net proved reserves with a PV-10 of $175.9 million. The average net daily production from this field was 10,944 Boe/d for the fourth quarter of 2018. The estimated reserve life (R/P) for this field is 12.1 years based on the annualized fourth quarter production rate.

Piceance Basin. Legacy's wells in the Piceance Basin are located in Garfield County, Colorado in the Grand Valley, Parachute and Rulison fields. Most of the wells in these fields produce from the Williams Fork formation at depths of approximately 7,000 to 9,000 feet and some wells produce from the Wasatch formation at depths of 1,600 to 4,000 feet. Legacy's ownership in this basin is comprised of non-operated interests in 2,676 active wells acquired in 2014 (the "Piceance Acquisition"). As of December 31, 2018, our properties in the Piceance Basin contained 41,886 MBoe (18% liquids) of net proved reserves with a PV-10 of $108.8 million. The average net daily production from this field was 10,838 Boe/d for the fourth quarter of 2018. The estimated reserve life (R/P) for this field is 10.6 years based on the annualized fourth quarter production rate.

Proved Reserves

The following table sets forth a summary of information related to our estimated net proved reserves as of the dates indicated based on reserve reports prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”). The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency. Standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

The following information represents estimates of our proved reserves as of December 31, ~~2018~~2019, ~~2017~~2018 and ~~2016~~2017. These reserve estimates have been prepared in compliance with the SEC rules and accounting standards using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price for each month in the years ended December 31, ~~2018~~2019, ~~2017~~2018 and ~~2016~~2017. As a result of this methodology, we used an average WTI posted price of $6555.5669 per Bbl for oil and an average Platts' Henry Hub natural gas price of $32.1058 per MMBtu to calculate our estimate of proved reserves as of December 31, ~~2018~~2019. Please see the table below.

	As of December 31,
	2018			2017			2016
Reserve Data:
Estimated net proved reserves:
Oil (MMBbls)	52.1			51.1			32.5
Natural Gas Liquids (MMBbls)	9.2			9.5			7.8
Natural Gas (Bcf)	621.7			716.1			627.0
Total (MMBoe)	164.9			180.0			144.8
Proved developed reserves (MMBoe)	158.7			172.0			139.2
Proved undeveloped reserves (MMBoe)	6.2			8.0			5.6
Proved developed reserves as a percentage of total proved reserves	96		%	96		%	96		%
PV-10 (in millions) (a)	$	1,350.0		$	1,172.1		$	575.6
Oil and Natural Gas Prices(b)
Oil - WTI per Bbl	$	65.56		$	47.79		$	39.25
Natural gas - Henry Hub per MMBtu	$	3.10		$	2.98		$	2.48

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Oil and natural gas prices as of each date are based on the unweighted arithmetic average of the first-day-of-the-month price for each month as posted by Plains Marketing L.P. and Platts Gas Daily for oil and natural gas, respectively, with these representative prices adjusted by property to arrive at the appropriate net sales price, which is held constant over the economic life of the property.


	As of December 31,
	2019			2018			2017
Reserve Data:
Estimated net proved reserves:
Oil (MMBbls)	42.3			52.1			51.1
Natural Gas Liquids (MMBbls)	6.9			9.2			9.5
Natural Gas (Bcf)	468.1			621.7			716.1
Total (MMBoe)	127.2			164.9			180.0
Proved developed reserves (MMBoe)	122.7			158.7			172.0
Proved undeveloped reserves (MMBoe)	4.6			6.2			8.0
Proved developed reserves as a percentage of total proved reserves	96		%	96		%	96		%
PV-10 (in millions) (a)	$	806.2		$	1,350.0		$	1,172.1
Oil and Natural Gas Prices(b)
Oil - WTI per Bbl	$	55.69		$	65.56		$	47.79
Natural gas - Henry Hub per MMBtu	$	2.58		$	3.10		$	2.98

____________________

(a)PV-10 is 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 ("FASB") and the SEC (using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price) without giving effect to non-property related expenses such as general administrative expenses and debt service or to depletion, depreciation and amortization or future income taxes and discounted using an annual discount rate of 10%. For the purpose of calculating the PV-10, the costs and prices are unescalated. PV-10 does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Investing Activities.” Oil and natural gas prices as of each date are based on the unweighted arithmetic average of the first-day-of-the-month price for each month as posted by Plains Marketing L.P. and Platts Gas Daily for oil and natural gas, respectively, with these representative prices adjusted by property to arrive at the appropriate net sales price, which is held constant over the economic life of the property.

(b) Oil and natural gas prices as of each date are based on the unweighted arithmetic average of the first day of the month price for each month as posted by Plains Marketing L.P. and Platts Gas Daily for oil and natural gas, respectively, with these representative prices adjusted by property to arrive at the appropriate net sales price, which is held constant over the economic life of the property.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required for recompletion.

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Please read “Risk Factors—Risks Related to our Business—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.” Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. PV-10 amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate PV-10, which is required by FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage LaRoche to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither LaRoche nor any of its employees have any interest in those properties, and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties.

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Internal Control Over Reserve Estimations

Legacy's proved reserves are estimated at the well or unit level and compiled for reporting purposes by Legacy's reservoir engineering staff, none of whom are members of Legacy's operating teams nor are they managed by members of Legacy's operating teams. Legacy maintains internal evaluations of its reserves in a secure engineering database. Legacy's reservoir engineering staff meets with LaRoche periodically throughout the year to discuss assumptions and methods used in the reserve estimation process. Legacy provides LaRoche information on all properties acquired during the year for addition to Legacy’s reserve report. LaRoche updates production data from public sources and then modifies production forecasts for all properties as necessary. Legacy provides to LaRoche lease operating statement data at the property level from Legacy’s accounting system for estimation of each property’s operating expenses, price differentials, gas shrinkage and NGL yield. Legacy's reserve engineering staff provides all changes to Legacy’s ownership interests in the properties to LaRoche for input into the reserve report. Legacy provides information on all capital projects completed during the year as well as changes in the expected timing of future capital projects. Legacy provides updated capital project cost estimates and abandonment cost and salvage value estimates. Legacy's internal engineering staff coordinates with Legacy's accounting and other departments and works closely with LaRoche to ensure the integrity, accuracy and timeliness of data that is furnished to LaRoche for its reserve estimation process. All of the reserve information in Legacy's secure reserve engineering data base is provided to LaRoche. After evaluating and inputting all information provided by Legacy, LaRoche, as independent third-party petroleum engineers, provides Legacy with a preliminary reserve report which Legacy's engineering staff and its Chief Financial Officer review for accuracy and completeness with an emphasis on ownership interest, capital spending and timing, expense estimates and production curves. After considering comments provided by Legacy, LaRoche completes and publishes the final reserve report. Legacy's engineering staff, in coordination with Legacy's accounting department and its Chief Financial Officer, ensure that the information derived from LaRoche's reports is properly disclosed in our filings.

Legacy’s Vice President - Corporate Reserves and Planning is the reservoir engineer primarily responsible for overseeing the preparation of reserve estimates by the third-party engineering firm, LaRoche. He has held a wide variety of technical and supervisory positions during a 4124-year career with ~~four~~three publicly traded oil and natural gas producing companies, including Legacy. He has over 3110 years of SEC & SPE reserve report preparation experience infor ~~addition~~domestic toand ~~continuing~~international ~~education~~companies. For ~~courses~~the onprofessional ~~reserve~~qualifications ~~estimation~~of ~~and~~the ~~reporting,~~primary ~~including~~person ~~one~~responsible infor ~~2009~~the ~~covering~~third-party ~~the~~reserve ~~effect~~evaluation, ofplease see the ~~SEC’s~~last ~~Final~~paragraph ~~Rule,~~of ~~Modernization~~Exhibit of99.1 ~~Oil~~- ~~and~~Summary ~~Gas~~Reserve ~~Reporting.~~Report ~~For~~from LaRoche Petroleum Consultants, Ltd.

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the professional qualifications of the primary person responsible for the third-party reserve evaluation, please see the last paragraph of Exhibit 99.1 - Summary Reserve Report from LaRoche Petroleum Consultants, Ltd.

Production and Price History

The following table sets forth a summary of unaudited information with respect to our production and sales of oil and natural gas for the period December 11 to December 31, 2019 (Successor), period January 1, to December 10, 2019 (Predecessor), and the years ended December 31, 2018, ~~2017~~ and ~~2016~~2017 (Predecessor):

	Year Ended December 31,
				Successor				Predecessor
	2018		2017(a)			2016
				Period from				Period from
Production:
				December 11, 2019				January 1, 2019
Oil (MBbls)	6,629		5,032			4,019
				to December 31,				to December 10,		Year Ended December 31,
Natural gas liquids (MGal)	41,549		38,159			36,757
				2019				2019		2018		2017(a)
Gas (MMcf)	58,457		62,833			66,824
Production:
Total (MBoe)	17,361		16,413			16,032
Oil (MBbls)				398				5,695		6,629		5,032
Average daily production (Boe per day)	47,564		44,967			43,803
Natural gas liquids (MGal)				1,944				32,683		41,549		38,159
Average sales price per unit (excluding commodity derivative cash settlements):
Gas (MMcf)				2,893				51,754		58,457		62,833
Oil (per Bbl)	$	56.64	$	47.59		$	37.95
Total (MBoe)				926				15,099		17,361		16,413
NGL (per Gal)	$	0.67	$	0.65		$	0.42
Average daily production (Boe per day)				44,095				43,892		47,564		44,967
Gas (per Mcf)	$	2.59	$	2.74		$	2.19
Average sales price per unit (excluding commodity derivative cash settlements):
Combined (per Boe)	$	31.96	$	26.58		$	19.61
Oil (per Bbl)				$	58.32			$	52.84	$	56.64	$	47.59
Average sales price per unit (including commodity derivative cash settlements):
NGL (per Gal)				$	0.47			$	0.43	$	0.67	$	0.65
Oil (per Bbl)	$	54.10	$	49.94		$	47.27
Gas (per Mcf)				$	2.08			$	1.96	$	2.59	$	2.74
NGL (per Gal)	$	0.67	$	0.65		$	0.42
Combined (per Boe)				$	32.55			$	27.58	$	31.96	$	26.58
Gas (per Mcf)	$	2.68	$	2.93		$	2.60
Average sales price per unit (including commodity derivative cash settlements):
Combined (per Boe)	$	31.29	$	28.05		$	23.63
Oil (per Bbl)				$	58.49			$	54.38	$	54.10	$	49.94
Average unit costs per Boe:
NGL (per Gal)				$	0.47			$	0.43	$	0.67	$	0.65
Production costs, excluding production and other taxes	$	11.02	$	10.58		$	10.59
Gas (per Mcf)				$	2.08			$	2.25	$	2.68	$	2.93
Ad valorem taxes	$	0.51	$	0.59		$	0.60
Combined (per Boe)				$	32.63			$	29.15	$	31.29	$	28.05
Production and other taxes	$	1.70	$	1.21		$	0.89
Average unit costs per Boe:
General and administrative, excluding transaction costs and LTIP	$	2.25	$	2.07		$	1.95
Production costs, excl'd production and other taxes				$	10.45			$	10.87	$	11.02	$	10.58
Total general and administrative	$	4.21	$	3.01		$	2.72
Ad valorem taxes				$	0.10			$	0.60	$	0.51	$	0.59
Depletion, depreciation and amortization	$	9.22	$	7.73		$	9.38
Production and other taxes				$	1.69			$	1.48	$	1.70	$	1.21
General and administrative, excl'd transaction costs and LTIP				$	1.59			$	2.76	$	2.25	$	2.07
Total general and administrative				$	1.59			$	5.12	$	4.21	$	3.01
Depletion, depreciation and amortization				$	6.75			$	10.39	$	9.22	$	7.73

____________________

(a) Includes the production and operating results of the properties acquired as a part of our asset acquisition in conjunction with the Acceleration Payment from the closing date on August 1, 2017 through December 31, 2017.

Productive Wells

The following table sets forth information at December 31, ~~2018~~2019 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the product of our fractional working interests owned in gross wells.

	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Operated	1,808	1,308	1,135	1,006	2,943	2,314
Non-operated	2,467	249	3,853	1,168	6,320	1,417
Total	4,275	1,557	4,988	2,174	9,263	3,731

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	Oil			Natural Gas			Total
	Gross	Net	Gross	Net	Gross	Net
Operated	1,659	1,185	1,111	994	2,770	2,179
Non-operated	2,316	233	3,866	1,164	6,182	1,397
Total	3,975	1,418	4,977	2,158	8,952	3,576

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, ~~2018~~2019 relating to our leasehold acreage.

~~DevelopedAcreage(a)~~

DevelopedAcreage(a)

~~UndevelopedAcreage(b)~~

~~TotalAcreage~~

UndevelopedAcreage(b)

TotalAcreage

~~Gross(c)~~

~~Net~~Gross(dc)

~~Gross(c)~~

~~Net(d)~~

~~Gross~~Net(cd)

~~Net(d)~~

Gross(c)

Net(d)

Gross(c)

Net(d)

Total

~~868,589~~

~~437~~852,~~140~~851

~~204,453~~

~~63,265~~

1431,~~073,042~~767

~~500,405~~

197,268

60,752

1,050,119

492,519

____________________

(a) Developed acres are acres spaced or assigned to productive wells or wells capable of production.

(b) Undeveloped acres include acres held by production but not currently allocated or assigned to producing wells or wells capable of production and acres not held by production and subject to the primary term of the leases, regardless of whether such acreage contains proved reserves. The majority of our proved undeveloped locations are located on acreage currently held by production. As the economic viability of any potential oil and natural gas development related to the acres not held by production is remote, we have assigned minimal value to our acreage not held by production and thus the minimum remaining term of those leases is immaterial to us.

(c) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(d) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the product of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

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Drilling Activity

The following table sets forth information with respect to wells completed by Legacy during the years ended December 31, ~~2018~~2019, ~~2017~~2018 and ~~2016~~2017. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the numbers of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil and natural gas, regardless of whether they produce a reasonable rate of return.

	~~Year EndedDecember 31,~~	Year EndedDecember 31,
	2018		2017	2016
		2019			2018	2017
Gross:
Development
Productive	54	29	42	12	54	42
Dry	—	—	—	—	—	—
Total	54	29	42	12	54	42
Exploratory
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	—	—	—	—	—	—
Net:
Development
Productive	~~27.6~~	12.4	~~27.4~~	~~2.2~~	27.6	27.4
Dry	—	—	—	—	—	—
Total	~~27.6~~	12.4	~~27.4~~	~~2.2~~	27.6	27.4
Exploratory
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	—	—	—	—	—	—

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Summary of Development Projects

For the year ended December 31, ~~2018~~2019, we invested approximately $~~229~~102.51 million in implementing our development strategy, including $~~176~~69.93 million related to the drilling and completion of 5429 gross (2712.64 net) development wells. The remaining $5232.68 million was comprised of the development of proved undeveloped reserves still in process, recompletions, fracture stimulation projects and various infrastructure capital. We estimate that our capital expenditures for the year ending December 31, ~~2019~~2020 will be approximately $~~135~~55.0 million, ~~subject to any limitations contained in the agreements governing our indebtedness,~~ for development drilling, recompletions and fracture stimulation and other development-related projects to implement this strategy. Over 90% of this capital is expected to be deployed in the Permian Basin. We will consider adjustments to this capital program based on our assessment of ~~additional~~market ~~development~~conditions ~~opportunities~~for ~~that~~oil ~~are identified during the year~~ and ~~the~~natural ~~cash available to invest in our development projects~~gas.

Present Activities

As of December 31, ~~2018~~2019, we were not in the process of drilling or completing 9any ~~gross (8.0 net)~~ wells~~, all of which were development wells~~. ~~Further, 5 wells were classified as PUD within our year-end reserve report while 4 wells were classified as unproved and therefore not included in our year-end reserve report.~~

Operations

General

We operate approximately 66% of our total net daily production of oil and natural gas. Excluding our assets in the Piceance Basin, we operate approximately 87% of our net daily production of oil and natural gas. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own drilling rigs or any material oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ drilling, production and reservoir engineers, geologists and other specialists who have worked and will work to improve production rates, increase reserves, and lower the cost of operating our oil and natural gas properties. We also employ field operating personnel including production superintendents, production foremen, production technicians and lease operators. We charge the non-operating partners an operating fee for operating the wells, typically on a fee per well-operated basis proportionate to each owner's working interest. Our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. In our areas of operation, this amount generally ranges from 12.5% to 33.7%, resulting in an 87.5% to 66.3% net revenue interest to the working interest owners, including us. Most of our leases are held by production and do not require lease rental payments.

Derivative Activity

We enter into derivative transactions with unaffiliated third parties with respect to oil and natural gas prices to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. We have entered into derivative contracts in the form of fixed price swaps for NYMEX WTI oil, NYMEX Henry Hub natural gas as well as Midland-to-Cushing crude oil, WAHA and CIG-Rockies basis differentials. We also enter into derivative transactions with respect to London Interbank Offered Rate ("LIBOR") interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in LIBOR interest rates. All of ~~our interest rate derivative transactions are LIBOR interest rate swaps. Our derivatives swap floating LIBOR rates for fixed rates. All of~~ these commodity ~~and interest rate~~ contracts were executed in a costless manner, requiring no payment of premiums. Furthermore, none of our current derivative counterparties require us to post collateral. For a more detailed discussion of our derivative activities, please read “Business—Oil and Natural Gas Derivative Activities,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations~~” and “—Quantitative and Qualitative Disclosures About Market Risk~~.”

Title to Properties

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title opinions have been obtained on a portion of our properties.

As 30is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense.

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As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this document.

ITEM 3. LEGAL PROCEEDINGS

We are, from time to time, involved in litigation and claims arising out of our 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 our consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings cannot be predicted with certainty.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

~~Our~~There ~~common stock~~ is ~~listed~~no onestablished ~~the~~public ~~NASDAQ~~trading ~~Global~~market ~~Select~~for ~~Market~~our ~~under~~common ~~the symbol “LGCY~~stock.” As of ~~March~~April 1327, ~~2019~~2020, there were ~~114~~61,~~810~~062,~~671~~850 shares of common stock outstanding, held by approximately ~~109~~296 stockholders of record. This number reflects only the stockholders of record, and does not reflect all beneficial owners of common stock, such as those who hold their common stock through a broker.

~~Subsequent to the Corporate Reorganization, we have not paid any cash dividends and we currently do not anticipate paying any cash dividends in the foreseeable future.~~20

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ITEM 6. SELECTED FINANCIAL DATA

~~You~~Not should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Legacy’s consolidated financial statements and related notes included elsewhere in this annual report on Form 10-Kapplicable. ~~The operating results of the properties acquired have been included from their respective acquisition dates as discussed below.~~

	Years Ended December 31,
	2018			2017(a)			2016			2015(b)			2014(c)
	(In thousands, except per share/unit data)
Statement of Operations Data:
Revenues:
Oil sales	$	375,444		$	239,448		$	152,507		$	199,841		$	396,774
Natural gas liquids sales	27,750			24,796			15,406			16,645			27,483
Natural gas sales	151,667			172,057			146,444			122,293			108,042
Total revenues	554,861			436,301			314,357			338,779			532,299
Expenses:
Oil and natural gas production	200,285			183,219			179,333			194,491			198,801
Production and other taxes	29,532			19,825			14,267			16,383			31,534
General and administrative	73,039			49,372			43,639			46,511			38,980
Depletion, depreciation, amortization
and accretion	159,998			126,938			150,414			177,258			173,686
Impairment of long-lived assets	67,978			37,283			61,796			633,805			448,714
(Gain) loss on disposal of assets	(23,803		)	1,606			(50,095		)	(3,972		)	(2,479		)
Total expenses	507,029			418,243			399,354			1,064,476			889,236
Operating income (loss)	47,832			18,058			(84,997		)	(725,697		)	(356,937		)
Other income (expense):
Interest income	36			64			67			329			873
Interest expense	(117,008		)	(89,206		)	(79,060		)	(76,891		)	(67,218		)
Gain on extinguishment of debt	66,066			—			150,802			—			—
Equity in income (loss) of equity method investees	(19		)	17			—			126			428
Net gains (losses) on commodity derivatives	49,172			17,776			(41,224		)	98,253			138,092
Other	722			792			(179		)	841			258
Income (loss) before income taxes	46,801			(52,499		)	(54,591		)	(703,039		)	(284,504		)
Income tax (expense) benefit	(2,968		)	(1,398		)	(1,229		)	1,498			859
Net loss attributable to stockholders/unitholders	$	43,833		$	(53,897	)	$	(55,820	)	$	(701,541	)	$	(283,645	)

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	Years Ended December 31,
	2018		2017(a)			2016			2015(b)			2014(c)
Income/(Loss) per share (a)
Basic and diluted	$	0.42	$	(0.54	)	$	(0.57	)	$	(7.26	)	$	(3.23	)
Distributions paid per unit	$	—	$	—		$	—		$	1.46		$	2.41

____________________

(a) In accordance with ASC 805, income (loss) per share amounts for historical periods have been recomputed to reflect shares issued in the Corporate Reorganization.

Cash Flow Data:
Net cash provided by (used in) operating activities	$	175,941		$	99,795		$	3,296		$	2,046		$	207,216
Net cash provided by (used in)
investing activities	$	(188,128	)	$	(279,236	)	$	119,989		$	(377,420	)	$	(632,414	)
Net cash provided by (used in)
financing activities	$	12,110		$	177,718		$	(119,130	)	$	376,655		$	423,339
Capital expenditures	$	228,261		$	314,491		$	41,932		$	579,463		$	640,414

	Historical As of December 31,
	2018			2017(a)			2016			2015(b)			2014(c)
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	1,098		$	1,246		$	2,555		$	2,006		$	725
Other current assets	149,994			111,358			80,217			127,453			191,529
Oil and natural gas properties, net of
accumulated depletion, depreciation,
amortization and impairment	1,314,313			1,353,356			1,181,909			1,408,956			1,639,974
Other assets	9,526			27,122			35,145			74,705			66,378
Total assets	$	1,474,931		$	1,493,082		$	1,299,826		$	1,613,120		$	1,898,606
Current liabilities	$	984,650		$	144,810		$	86,609		$	81,093		$	97,576
Long-term debt	432,923			1,346,769			1,161,394			1,427,614			938,876
Other long-term liabilities	249,989			273,190			273,902			284,090			224,949
Stockholders'/Partners’ equity(deficit)	(192,631		)	(271,687		)	(222,079		)	(179,677		)	637,205
Total liabilities and stockholders'/partners’ equity (deficit)	$	1,474,931		$	1,493,082		$	1,299,826		$	1,613,120		$	1,898,606

____________________

(a) Includes the production and operating results of the properties acquired as a part of our assets acquired in conjunction with Acceleration Payment from the closing date on August 1, 2017 through December 31, 2017 and thereafter.

(b) Includes Legacy’s purchase of the oil and natural gas properties acquired in the Anadarko Acquisitions as of the closing date of the acquisition on July 31, 2015. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition through December 31, 2015 and thereafter.

(c) Includes Legacy’s purchase of the oil and natural gas properties acquired in the Piceance Acquisition as of the closing date of the acquisition on June 4, 2014. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition through December 31, 2014 and thereafter.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the ~~“Selected Historical Consolidated Financial Data” and the~~ accompanying financial statements and related notes included elsewhere in this annual report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “~~Risk Factors” and “~~Cautionary Statement Regarding Forward-Looking Information,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, actual results may differ materially from those anticipated or implied in the forward-looking statements.

Overview

Because of our historical growth through acquisitions and development of properties as well as large fluctuations in commodity prices, historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results. The operating results of the properties acquired as a part of our asset acquisition in conjunction with the acceleration payment (the "Acceleration Payment") under our joint development agreement with TPG Sixth Street Partners (the "JDA") have been included since August 1, 2017.

~~Going~~Emergence ~~Concern~~from Voluntary Reorganization under Chapter 11 Proceedings and Fresh Start Accounting

WeUpon ~~have~~the ~~significant~~Company’s ~~obligations~~emergence ~~and~~from ~~commitments coming due in~~ the ~~near~~Chapter ~~term.~~11 ~~On March 21~~Cases, ~~2019, we entered into an amendment to~~ the ~~Credit~~Company ~~Agreement~~adopted ~~(as~~fresh-start ~~defined~~accounting ~~below)~~in ~~pursuant~~accordance towith ~~which~~ the ~~lenders~~provisions ~~agreed~~set toforth ~~extend~~in ~~the~~ASC ~~maturity~~852. As ~~date~~a ~~from~~result ~~April~~of 1,the ~~2019~~application toof ~~May~~fresh-start 31accounting, ~~2019~~as ~~and~~well as ~~of December 31, 2018, we had availability under~~ the ~~Credit~~effects ~~Agreement~~ of ~~$32.9~~the ~~million. Without~~implementation ~~additional sources~~ of ~~capital~~the orPlan, athe ~~significant~~consolidated ~~restructuring~~financial ofstatements ~~our~~on ~~balance~~or ~~sheet,~~after the ~~maturity~~Effective ofDate ~~our~~are ~~Credit~~not ~~Agreement~~comparable ~~raises~~with ~~substantial~~the ~~doubt~~consolidated ~~about~~financial ~~our~~statements ~~ability~~prior to ~~continue~~the asEffective aDate. ~~going~~Refer ~~concern, which means that we may be unable~~ to ~~continue~~Note ~~operations~~1 ~~for~~of the ~~foreseeable~~Notes ~~future~~to orConsolidated ~~realize~~Financial ~~assets~~Statements ~~and~~for ~~discharge~~additional ~~liabilities in the ordinary course of operation~~information.

~~The~~References ~~report~~to ofthe ~~our~~“Successor” ~~independent~~or ~~registered~~“Successor ~~public~~Company” ~~accounting~~refer ~~firm~~to ~~that~~the ~~accompanies our audited consolidated~~ financial ~~statements~~position inand ~~this~~results ~~annual~~of ~~report~~operations onof ~~Form~~the ~~10-K~~new ~~contains~~reorganized anCompany ~~explanatory~~subsequent ~~paragraph~~to ~~regarding~~ the ~~substantial~~Effective ~~doubt~~Date. References ~~about our ability~~ to ~~continue~~“Predecessor” asor a“Predecessor ~~going~~Company” ~~concern.~~refer ~~The~~to ~~consolidated~~the financial ~~statements~~position doand ~~not~~results ~~include~~of ~~any~~operations ~~adjustments~~of ~~that~~the ~~might~~Company ~~result~~prior ~~from~~to the ~~outcome~~Effective ~~of the going concern uncertainty~~Date.

In order to improve our liquidity position, we are currently evaluating financial, transactional and other strategic alternatives. In the first quarter of 2019, we retained financial and legal advisors who specialize in such alternatives. There can be no assurance that sufficient liquidity can be raised from any one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations or at all. Please see “Risk Factors—Risks Related to Our Business—We have engaged financial and legal advisors to assist us in, among other things, evaluating financial, transactional and other strategic alternatives to address our liquidity and capital structure that may be time consuming, disruptive and costly to our business, and —We may need to seek relief under the U.S. Bankruptcy Code, even if we are successful in effecting a financial, transactional or other strategic alternative. Any bankruptcy proceeding may result in holders of our equity securities and our other stakeholders receiving little or no consideration,” in Item 1A.

We continue to focus on maintaining efficient operations to minimize production declines, improve lifting costs and well economics while regularly reviewing our asset portfolio and divesting non-core assets.

Trends Affecting Our Business and Operations

~~Irrespective~~Sustained ~~of our balance sheet constraints, sustained~~ periods of low prices for oil or natural gas have and could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by drilling to find additional reserves, acquiring more reserves than we produce, utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary recovery methods to re-pressure the reservoir and recover additional oil, recompleting or adding pay in existing wellbores and improving artificial lift.

Outlook. 35Crude oil prices have recently experienced a severe decrease due to the general economic downturn as a result of the COVID-19 pandemic and recent actions by Organization of the Petroleum Exporting Countries (“OPEC”) nations. The COVID-19 pandemic and the measures taken by governmental authorities in response thereto, such as travel bans, shelter-in-place orders, quarantines, and increased border and port controls and closures, have disrupted economic activity and increased the potential for an economic downturn. Moreover, the resulting reductions in travel and transportation have depressed global demand for oil and its byproducts. In its Oil Market Report for April 2020, the International Energy Agency reported that global oil demand is expected to fall by 9.3 million barrels per day year-on-year in 2020, and that refinery intake is also expected to

decrease with widespread run cuts and shutdowns globally as a result of lower demand.

Furthermore, crude oil prices have been impacted by increased supply by OPEC nations, although, as of April 2020, Russia and OPEC have reached a tentative agreement on production cuts. Other countries, including the U.S. and Canada, are expected to reduce production as well. As of April 2020, some states, including Texas and Oklahoma, are considering proration

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~~tertiary~~of ~~recovery~~oil ~~methods~~production in response to ~~re-pressure~~market conditions, which could limit the ~~reservoir~~amount of oil and ~~recover~~natural ~~additional~~gas ~~oil,~~we ~~recompleting~~can produce from our wells or ~~adding~~limit ~~pay~~the innumber ~~existing~~of ~~wellbores~~wells ~~and~~or ~~improving~~the ~~artificial~~locations ~~lift.~~at which we can drill.

~~Outlook.~~Many ~~The~~uncertainties ~~oil~~remain ~~and~~regarding ~~natural~~the ~~gas~~COVID-19 ~~industry~~pandemic isand ~~in a challenging environment, especially over~~ the ~~past~~disruption ~~five years, as evidenced by volatility~~ in the ~~crude~~ oil ~~prices~~market, ~~that ranged from over $100 per barrel in early 2014 to less than $30 per barrel in early 2016. While prices in 2017~~ and ~~2018~~it ~~have~~is ~~recovered~~impossible ~~off the lows experienced in 2016 they have experienced a sharp decline~~ at ~~the~~this ~~end~~time ofto ~~2018~~predict ~~from levels seen in 2017 and are still well below levels seen in 2014. Sustained development activity in~~ the ~~Permian~~full ~~Basin~~economic ~~has~~impact ~~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~~impact ~~Basin~~on ~~relative to benchmark crude oil and natural gas prices, which affect the prices we realize for~~ our ~~crude oil and natural gas production~~business. ~~The~~Due ~~narrowing~~to of these ~~basis differentials is largely dependent on the construction of new takeaway capacity~~ and other factors, ~~beyond~~the ~~our~~potential ~~control. While~~for ~~we believe that~~ a ~~significant~~near ~~number~~or ofmedium ~~these~~term ~~projects~~recovery ~~will be completed~~ in ~~2019,~~crude ~~there~~oil isprices ~~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~~uncertain. WeThe dooutlook ~~not have the ability to control the supply of these services and if we are unable to find adequate services~~ for ~~our~~natural ~~operations~~gas ~~at economic~~ prices, ~~there~~also ~~could~~remains ~~be a material adverse impact on our financial condition~~uncertain. ~~Also,~~Many ~~production~~oil ~~from~~and ~~our~~natural ~~horizontal~~gas ~~development~~companies ~~within~~have ~~the~~responded ~~Permian~~by ~~Basin~~announcing ~~has,~~intentions ~~from time~~ to ~~time,~~drastically ~~been~~cut ~~temporarily~~drilling ~~shut-in~~and orcompletions ~~constrained due to proximate development operations~~activities. 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~~2020 capital expenditures ~~are~~budget ~~expected~~of ~~to be~~ approximately $~~135~~55 million, ~~subject~~does tonot ~~any~~contain ~~limitations~~significant ~~contained~~amounts innecessary ~~the~~to ~~agreements~~maintain ~~governing~~leasehold ~~our indebtedness, in 2019~~ and ~~will~~is ~~continue~~subject to besignificant ~~focused~~change based on ~~the~~management’s ~~development~~view of ~~our~~commodity Permian Basin horizontal development assets, subject to any constraints imposed by our Term Loan Credit Agreement that may limit our capital expenditures as discussed in “Capital Resources and Liquidity—Future Liquidity Considerations”prices. We ~~intend to~~ continue to ~~prudently~~monitor ~~manage our historical low-decline proved developed producing oil~~ and ~~gas~~evaluate ~~properties~~any todevelopments ~~support~~with ~~the~~respect ~~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~~market inconditions ~~commodity prices, we recalculated our proved reserves as of December 31, 2018, using the five-year average forward price as of February 25, 2019~~ for ~~both WTI~~ oil and ~~NYMEX~~ natural gas. ~~While~~and ~~this~~the 5COVID-~~year~~19 ~~NYMEX forward strip price is not necessarily indicative of our overall outlook on future commodity prices~~pandemic, ~~this~~though ~~commonly~~we ~~used~~cannot ~~methodology~~guarantee ~~may~~that ~~help~~any ~~provide~~measures ~~investors with an understanding of the impact of a volatile commodity price environment. Under such assumptions,~~ we ~~estimate~~take ~~the~~in ~~cumulative~~response ~~projected~~thereto ~~production~~will ~~from~~be ~~our~~entirely ~~year-end~~effective ~~proved~~or ~~reserves~~effective ~~would~~at ~~decrease by approximately 8~~all.~~0% to 151.7 MMBoe from the reported 164.9 MMBoe, which is calculated as required by the SEC.~~

WeIn ~~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~~event party thereto as amended most recently by the Twelfth 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. Further, while we received a waiver of the covenant under our Term Loan Credit Agreement that ~~requires~~cash usflows tofrom ~~deliver~~operations ~~audited~~are ~~financial~~greater ~~statements~~than without a “going concern” or like qualification or exception, such waiver expires on May 31, 2019 and such default cannot be remedied. Upon delivery of our financial statements for the quarter ended March 31, 2019, we ~~expect~~currently ~~to be in violation of the current ratio covenant under our Credit Agreement~~anticipate, ~~which~~whether ~~would~~as ~~constitute~~ a ~~default~~result ~~under the Credit Agreement. Defaults, if not remedied, would require a waiver from our lenders in order for us to avoid an event~~ of ~~default~~increased 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~~reduced ainterest ~~potential~~expense ~~cross-default~~or ~~of all our existing indebtedness~~otherwise, ~~please read “Risk Factors—Risks Related to Our Business—If we are unable to refinance~~ or ~~repay~~additional ~~our~~external ~~indebtedness~~financing ~~under~~sources ~~our~~become ~~Credit~~available ~~Agreement when it comes due or otherwise fail~~ to ~~comply with certain restrictions and financial covenants in our Credit Agreement and Term Loan Credit Agreement~~us, we ~~could~~intend beto inpay ~~default~~down ~~under~~ our ~~Credit Agreement and Term Loan Credit Agreement which may result in acceleration or repayment of all of our outstanding indebtedness,” in Item 1A~~debt.

~~Considering~~Our ~~the~~future ~~current~~growth ~~environment~~will ~~for~~depend ~~the~~on ~~oil~~our ~~and~~ability ~~natural~~to ~~gas~~continue ~~industry,~~to ~~our~~add ~~goals~~reserves in ~~2019~~excess ~~are~~of production. Our ability to: add reserves through organic development projects and acquisitions is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and completions equipment and personnel.

•Our ~~reposition~~revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. As set forth under “Investing Activities,” we have entered into oil and natural gas derivatives designed to mitigate the effects of price fluctuations covering a portion of our ~~balance~~expected ~~sheet~~production, bywhich ~~evaluating~~allows us to mitigate, but not eliminate, oil and ~~opportunistically~~natural ~~pursuing~~gas ~~strategic~~price ~~alternatives~~risk. By removing a portion of our price volatility on our future oil and natural gas production through 2023, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. Commodity prices may decrease, which could alter our acquisition and development plans, and adversely affect our growth strategy and ability to ~~materially~~access ~~reduce~~additional capital in the capital markets and through our ~~outstanding~~revolving ~~indebtedness~~credit facility. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and ~~restructure~~production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ~~near~~ability ~~term~~to ~~maturity~~execute ~~indebtedness~~our development plans and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas prices may have on the value of our proved reserves and their impact on any redetermination to our borrowing base under our revolving credit facility.

•Operating ~~minimize~~Data ~~production~~(In ~~declines~~thousands, ~~and~~except ~~operating~~per ~~costs~~unit ~~through~~data ~~efficient operations;~~ and production)

•The ~~efficiently~~following ~~develop~~table ~~our~~sets ~~horizontal~~forth ~~inventory~~our inselected ~~the~~financial ~~Permian~~and ~~Basin~~operating todata ~~generate~~for ~~strong~~the ~~cash-on-cash~~periods ~~investment returns~~indicated.


	Successor		Predecessor
	Period from		Period from		Year Ended December 31,
	December 11, 2019		January 1, 2019
	to December 31,		to December 10,
	2019		2019		2018		2017(b)
(In thousands, except per unit data and production)
Revenues
Oil sales	$	23,232	$	300,905	$	375,444	$	239,448
Natural gas liquids sales	916		14,082		27,750		24,796
Natural gas sales	6,016		101,488		151,667		172,057
Total revenues	$	30,164	$	416,475	$	554,861	$	436,301
Expenses:
Oil and natural gas production	$	9,685	$	164,100	$	191,345	$	173,599
Ad valorem taxes	94		9,132		8,940		9,620
Total	$	9,779	$	173,232	$	200,285	$	183,219
Exploration Expense	$	750	$	—	$	—	$	—
Production and other taxes	$	1,564	$	22,371	$	29,532	$	19,825
General and administrative, excluding transaction costs and LTIP	$	1,470	$	41,675	$	39,041	$	34,006
Transaction costs	—		20,898		5,635		8,769
LTIP expense	—		14,791		28,362		6,597
Total general and administrative	$	1,470	$	77,364	$	73,038	$	49,372

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In the event that cash flows from operations are greater than we currently anticipate, whether as a result of increased commodity prices, reduced interest expense or otherwise, or additional external financing sources become available to us, we intend to pay down debt, accelerate our development plan, and increase development capital expenditures.


Reorganization expense	$	—	$	(447,901)	$	—	$	—
Depletion, depreciation, amortization and accretion	$	6,259	$	156,935	$	159,998	$	126,938
Commodity derivative cash settlements:
Oil derivative cash settlements (paid)/received	67		8,773		(16,845)		11,840
Natural gas derivative cash settlements received	9		14,914		5,130		12,316
Total commodity derivative cash settlements	76		23,686		(11,715)		24,156
Production:
Oil (MBbls)	398		5,695		6,629		5,032
Natural gas liquids (MGal)	1,944		32,683		41,549		38,159
Natural gas (MMcf)	2,893		51,754		58,457		62,833
Total (MBoe)	926		15,099		17,361		16,413
Average daily production (Boe/d)	44,095		43,892		47,564		44,967
Average sales price per unit (excluding commodity derivative cash settlements):
Oil price (per Bbl)	$	58.32	$	52.84	$	56.64	$	47.59
Natural gas liquids price (per Gal)	$	0.47	$	0.43	$	0.67	$	0.65
Natural gas price (per Mcf)(a)	$	2.08	$	1.96	$	2.59	$	2.74
Combined (per Boe)	$	32.55	$	27.58	$	31.96	$	26.58
Average sales price per unit (including commodity derivative cash settlements):
Oil price (per Bbl)	$	58.49	$	54.38	$	54.10	$	49.94
Natural gas liquids price (per Gal)	$	0.47	$	0.43	$	0.67	$	0.65
Natural gas price (per Mcf)(a)	$	2.08	$	2.25	$	2.68	$	2.93
Combined (per Boe)	$	32.63	$	29.15	$	31.29	$	28.05
Average WTI oil spot price (per Bbl)	$	56.98	$	56.98	$	65.23	$	50.80
Average Henry Hub natural gas spot price (per MMBtu)	$	2.56	$	2.56	$	3.15	$	2.99
Average unit costs per Boe:
Production costs, excluding production and other taxes	$	10.45	$	10.87	$	11.02	$	10.58
Ad valorem taxes	$	0.10	$	0.60	$	0.51	$	0.59
Production and other taxes	$	1.69	$	1.48	$	1.70	$	1.21
General and administrative, excluding transaction costs and LTIP	$	1.59	$	2.76	$	2.25	$	2.07
Total general and administrative	$	1.59	$	5.12	$	4.21	$	3.01
Depletion, depreciation, amortization and accretion	$	6.75	$	10.39	$	9.22	$	7.73

Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through organic development projects and acquisitions. Our ability to add reserves through organic development projects and acquisitions is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and completions equipment and personnel.____________________

~~Our~~(a)We ~~revenues~~primarily ~~are~~report ~~highly~~and ~~sensitive~~account tofor ~~changes~~our inPermian ~~oil~~Basin ~~and~~ natural gas ~~prices~~volumes ~~and~~inclusive ~~to levels~~ of ~~production.~~the AsNGL ~~set~~content ~~forth~~contained ~~under~~within ~~“Investing~~those ~~Activities,” we have entered into oil and~~ natural gas ~~derivatives~~volumes. ~~designed~~Given ~~to mitigate~~ the ~~effects of~~ price ~~fluctuations~~disparity ~~covering~~between aan ~~portion~~equivalent amount of ~~our~~NGLs ~~expected~~compared ~~production, which allows us~~ to ~~mitigate, but not eliminate, oil and~~ natural gas, ~~price risk. By removing a portion of~~ our ~~price~~realized ~~volatility on our future oil and~~ natural gas ~~production through 2019, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas~~ prices on our cash flows from operations for those periods. Commodity prices may decrease, which could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the ~~capital~~Permian ~~markets~~Basin and ~~through~~for ~~our~~Legacy ~~revolving~~as ~~credit~~a ~~facility.~~whole Weare ~~continuously~~higher ~~conduct~~than ~~financial~~Henry ~~sensitivity~~Hub ~~analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and~~ natural gas ~~prices~~index ~~will affect our ability to execute our development plans and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas~~ prices ~~may~~due ~~have on the value of our proved reserves and their impact on any redetermination~~ to ~~our~~this ~~borrowing~~NGL ~~base under our revolving credit facility~~content.

(b)Includes 37the production and operating results of the properties acquired as a part of our asset acquisition in conjunction with the Acceleration Payment from the closing date on August 1, 2017 through December 31, 2017 and thereafter.

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Operating Data

	Year Ended December 31,
	2018			2017(b)		2016
	(In thousands, except per unit data and production)
Revenues
Oil sales	$	375,444		$	239,448	$	152,507
Natural gas liquids sales	27,750			24,796		15,406
Natural gas sales	151,667			172,057		146,444
Total revenues	$	554,861		$	436,301	$	314,357
Expenses:
Oil and natural gas production	$	191,345		$	173,599	$	169,755
Ad valorem taxes	8,940			9,620		9,578
Total	$	200,285		$	183,219	$	179,333
Production and other taxes	$	29,532		$	19,825	$	14,267
General and administrative, excluding transaction costs and LTIP	$	39,041		$	34,006	$	31,196
Transaction costs	5,635			8,769		5,245
LTIP expense	28,362			6,597		7,198
Total general and administrative	$	73,038		$	49,372	$	43,639
Depletion, depreciation, amortization and accretion	$	159,998		$	126,938	$	150,414
Commodity derivative cash settlements:
Oil derivative cash settlements (paid)/received	(16,845		)	11,840		37,464
Natural gas derivative cash settlements received	5,130			12,316		27,041
Total commodity derivative cash settlements	(11,715		)	24,156		64,505
Production:
Oil (MBbls)	6,629			5,032		4,019
Natural gas liquids (MGal)	41,549			38,159		36,757
Natural gas (MMcf)	58,457			62,833		66,824
Total (MBoe)	17,361			16,413		16,032
Average daily production (Boe/d)	47,564			44,967		43,803
Average sales price per unit (excluding commodity derivative cash settlements):
Oil price (per Bbl)	$	56.64		$	47.59	$	37.95
Natural gas liquids price (per Gal)	$	0.67		$	0.65	$	0.42
Natural gas price (per Mcf)(a)	$	2.59		$	2.74	$	2.19
Combined (per Boe)	$	31.96		$	26.58	$	19.61
Average sales price per unit (including commodity derivative cash settlements):
Oil price (per Bbl)	$	54.10		$	49.94	$	47.27
Natural gas liquids price (per Gal)	$	0.67		$	0.65	$	0.42
Natural gas price (per Mcf)(a)	$	2.68		$	2.93	$	2.60
Combined (per Boe)	$	31.29		$	28.05	$	23.63
Average WTI oil spot price (per Bbl)	$	65.23		$	50.80	$	43.29
Average Henry Hub natural gas spot price (per MMBtu)	$	3.15		$	2.99	$	2.52
Average unit costs per Boe:
Production costs, excluding production and other taxes	$	11.02		$	10.58	$	10.59
Ad valorem taxes	$	0.51		$	0.59	$	0.60
Production and other taxes	$	1.70		$	1.21	$	0.89
General and administrative, excluding transaction costs and LTIP	$	2.25		$	2.07	$	1.95
Total general and administrative	$	4.21		$	3.01	$	2.72
Depletion, depreciation, amortization and accretion	$	9.22		$	7.73	$	9.38

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

(b) Includes the production and operating results of the properties acquired as a part of our asset acquisition in conjunction with the Acceleration Payment from the closing date on August 1, 2017 through December 31, 2017 and thereafter.

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Results of Operations

~~Year~~Period ~~Ended~~of December 11, 2019 through December 31, ~~2018~~2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor) Compared to Year Ended December 31, ~~2017~~2018 (Predecessor)

Legacy’s revenues from the sale of oil were $~~375~~23.42 million, $300.9 million and $~~239~~375.4 million for the ~~years~~period ~~ended~~of December 11, 2019 through December 31, ~~2018~~2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and ~~2017~~the year ended December 31, 2018 (Predecessor), respectively. Legacy’s revenues from the sale of NGLs were $270.89 million, $14.1 million and $2427.8 million for the ~~years~~period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 ~~and 2017~~(Predecessor), respectively. Legacy’s revenues from the sale of natural gas were $~~151~~6.70 million, $101.5 million and $~~172~~151.17 million for the ~~years~~period ~~ended~~of December 11, 2019 through December 31, ~~2018~~2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and ~~2017~~the year ended December 31, 2018 (Predecessor), respectively. The $~~136~~51.03 million ~~increase~~decrease in oil revenue reflects ana ~~increase~~decrease in oil production of ~~1,597~~536 MBbls (328%) and ana ~~increase~~decrease in average realized price of $93.0544 per Bbl (196%) to $5653.6420 for the year ended December 31, ~~2018~~2019 from $4756.5964 for the year ended December 31, ~~2017~~2018. The ~~increase~~decrease in realized oil price was primarily caused by ana ~~increase~~decrease in the average WTI crude oil price of $148.4325 and partially offset by ~~worsening~~improved realized regional differentials. The ~~increase~~decrease in production is primarily due to ~~continued~~reduced ~~development~~horizontal drilling activity of our Permian Basin horizontal assets as well as ~~an increase in net well count under our JDA following the Acceleration Payment in 2017. The increase was partially offset by individually immaterial divestitures and~~ natural declines. The $312.08 million ~~increase~~decrease in NGL revenues reflects ana ~~increase~~decrease in realized NGL price of $0.0224 per Gal (336%) to $0.6743 per Gal for the year ended December 31, ~~2018~~2019 from $0.6567 per Gal for the year ended December 31, ~~2017~~2018 and ana ~~increase~~decrease in NGL production of 36,~~390~~922 MGals (917%) during ~~2018~~2019. The ~~increase~~decrease in NGL production is primarily due to ~~increased~~decreased ethane recoveries from our Piceance natural gas properties. The $2044.42 million decrease in natural gas revenues reflects a decrease of our realized natural gas prices as well as a decrease in our natural gas production volumes. Average realized gas prices decreased by $0.1562 per Mcf (524%) to $21.5997 per Mcf for the year ended December 31, ~~2018~~2019 from $2.7459 per Mcf for the year ended December 31, ~~2017~~2018, primarily due to worsening realized regional differentials ~~partially~~and ~~offset~~a bydecrease ~~an increase~~ in the average NYMEX Henry Hub natural gas price of $0.1659 per Mcf. Our natural gas production decreased by approximately 43,~~376~~810 MMcf (7%), primarily due to due to natural production declines in our East Texas and Piceance Basin properties ~~partially~~as ~~offset~~well byas ~~increased~~third-party ~~production~~plant ~~from~~and ~~the~~gathering ~~assets~~interruptions ~~developed~~resulting byin ~~our~~production ~~Permian Basin horizontal development program~~shut-ins.

For the ~~year~~period ~~ended~~of December 11, 2019 through December 31, ~~2018~~2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), Legacy recorded $496.23 million and $50.3 million of net ~~gains~~losses on oil and natural gas derivatives, respectively. Commodity derivative gains and losses represent the changes in fair value of our commodity derivative contracts during the period and are primarily based on oil and natural gas futures prices. The net ~~gain~~loss recognized during ~~2018~~2019 was primarily due to the ~~decrease~~increase in oil futures prices for periods beyond ~~2018~~2019, which ~~increased~~decreased the fair value of our derivatives in such periods, partially offset by cash ~~payments~~received on oil and natural gas derivative contracts during the year. For the year ended December 31, ~~2017~~2018 (Predecessor), Legacy recorded $1749.82 million of net gains on oil and natural gas derivatives. The net gain recognized during ~~2017~~ 2018 was primarily due to ~~cash receipts and~~ the decrease in ~~natural~~oil ~~gas~~ futures prices for periods beyond ~~2017~~2018, which increased the fair value of our derivatives in such periods., partially offset by cash payments on oil derivative contracts during the year. Settlements of such contracts resulted in cash (payments)/receipts of $~~(11~~0.1 million, $23.7) million and $24(11.27) million ~~during~~for ~~2018~~the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and ~~2017~~the year ended December 31, 2018 (Predecessor), respectively.

Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, were $9.7 million ($10.45 per Boe), $164.1 million ($10.87 per Boe) and $191.3 million ($11.02 per Boe) for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. This decrease in the most recent periods can be attributed to general cost containment activities as well as decreased marketing fees in our Piceance Basin properties. These decreases resulted in decreased production expenses per Boe for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor) compared to year ended December 31, 2018 (Predecessor). Legacy’s ad valorem tax expenses were $0.1 million, $9.1 million and $8.9 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. The increase in the most recent periods was primarily due to increased ad valorem taxes related to our Piceance Basin properties.

Legacy’s production and other taxes were $1.6 million, $22.4 million and $29.5 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. Production and other taxes decreased in the most recent periods due to lower oil revenues in 2019. On a per Boe basis, production and other taxes decreased to $1.69, $1.48 compared to $1.70 for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively due to lower realized oil prices.

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Legacy’s general and administrative expenses were $1.5 million, $77.4 million and $73.0 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. General and administrative expenses increased in the most recent periods due to increased pre-bankruptcy legal and consulting expenses, partially offset by a reduction in LTIP expense.

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A $6.3 million, $156.9 million, $160.0 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. Our depletion rate per Boe, was $6.76, $10.39 and $9.22 for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. The increased per Boe amount for the period of January 1, 2019 through December 10, 2019 (Predecessor) compared to the year ended December 31, 2018 (Predecessor) is attributable to higher depletion rates across our historical properties primarily driven by declining reserve volumes due to price declines.

Impairment expense was zero, $105.5 million and $68.0 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. In the period of January 1, 2019 through December 10, 2019, Legacy recognized $105.5 million of impairment expense on 20 separate producing fields primary related to declining commodity prices, primarily natural gas. In 2018, Legacy recognized impairment expense of $58.7 million in 50 separate producing fields, due primarily to the further decline in oil and natural gas futures prices in late 2018 as well as increased expenses and well performance during the year ended December 31, 2018 (Predecessor), which decreased the expected future cash flows below the carrying value of the assets. Additionally, in 2018 we recorded impairment of $9.3 million related to unproved properties acquired since 2010 that, in the current and expected future commodity price environment, are no longer economically viable.

Interest expense was $1.6 million, $115.7 million and $117.0 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. The slight decrease in interest expense for the period of January 1, 2019 through December 1, 2019 (Predecessor) is primarily due to accelerated amortization related to our Term Loan Credit Agreement acceleration of indebtedness to May 31, 2019, mostly offset by discontinuance of interest on our debt due to our filing Chapter 11 bankruptcy on June 18, 2019. Cash (receipts)/payments on our interest rate swaps were zero, $1.9 million and $(1.3) million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively.

For the period of December 11, 2019 through December 31, 2019 (Successor), we did not record any gain on extinguishment of debt. For the period of January 1, 2019 through December 10, 2019 (Predecessor), we recorded $13.1 million on extinguishment of debt due to the exchange of our 6.625% Senior Notes due 2021 (the "2021 Senior Notes") and exchange and conversion of our 8% Convertible Senior Notes due 2023 ("2023 Convertible Notes" and, together with the Senior Notes, the "Notes") . During the year ended December 31, 2018, we recorded a gain on extinguishment of debt of $66.1 million due to (i) the repurchase of our 2021 Senior Notes and (ii) the exchange of our 8% Senior Notes due 2020 (the "2020 Senior Notes" and, together with the 2021 Senior Notes, the "Senior Notes") and our 2021 Senior Notes for our 2023 Convertible Notes.

For the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), income tax expense was zero, $0.1 million and $3.0 million, respectively. The effective income tax rates for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor) were 0.21%, 0.1% and 6.3%, respectively. For the period of December 11, 2019 through December 31, 2019 (Successor), our effective tax rate differed from the statutory rate primarily due to non-deductible executive compensation, and the valuation allowance. For the period of January 1, 2019 through December 10, 2019 (Predecessor), our effective rate differed from the statutory rate primarily due to non-deductible debt restructuring expenses and the valuation allowance. For the year ended December 31, 2018 (Predecessor), 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, the 2023 Convertible Notes issuance, Texas margins tax, and the valuation allowance.

For the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), Legacy recognized reorganization expense of zero, $447.9 million and zero respectively. Reorganization items represent costs or income directly associated with

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the Chapter 11 Cases that have been incurred since June 18, 2019 (when we filed voluntary petitions for relief under Chapter 11), as well as gains from liabilities settled and fresh start accounting adjustments.

As a result of the items described above, Legacy recorded net income/(losses) of $3.1 million, $173.9 million and $43.8 million for the for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively.

Year Ended December 31, 2018 (Predecessor) Compared to Year Ended December 31, 2017 (Predecessor)

Legacy’s revenues from the sale of oil were $375.4 million and $239.4 million for the years ended December 31, 2018 and 2017, respectively. Legacy’s revenues from the sale of NGLs were $27.8 million and $24.8 million for the years ended December 31, 2018 and 2017, respectively. Legacy’s revenues from the sale of natural gas were $151.7 million and $172.1 million for the years ended December 31, 2018 and 2017, respectively. The $136.0 million increase in oil revenue reflects an increase in oil production of 1597 MBbls (32%) and an increase in average realized price of $9.05 per Bbl (19%) to $56.64 for the year ended December 31, 2018 from $47.59 for the year ended December 31, 2017. The increase in realized oil price was primarily caused by an increase in the average WTI crude oil price of 14.43 and partially offset by worsening realized regional differentials. The increase in production is continued development of our Permian Basin horizontal assets as well as an increase in net well count under our JDA following the Acceleration Payment. The increase was partially offset by individually immaterial divestitures and natural declines. The $3.0 million increase in NGL revenues reflects an increase in realized NGL price of $0.02 per Gal (3%) to $0.67 per Gal for the year ended December 31, 2018 from $0.65 per Gal for the year ended December 31, 2017 and an increase in NGL production of 3,390 MGals (9%) during 2018. The increase in NGL production is primarily due to increased ethane recoveries from our Piceance natural gas properties. The $20.4 million decrease in natural gas revenues reflects a decrease of our realized natural gas prices as well as a decrease in our natural gas production volumes. Average realized gas prices decreased by $(0.14) per Mcf (5)% to $2.59 per Mcf for the year ended December 31, 2018 from $2.74 per Mcf for the year ended December 31, 2017, primarily due to worsening realized regional differentials partially offset by an increase in the average NYMEX Henry Hub natural gas price of 0.16 per Mcf. Our natural gas production decreased by approximately 4,376 MMcf (7)%, primarily due to natural production declines in our East Texas and Piceance Basin properties partially offset by increased production from the assets developed by our Permian Basin horizontal development program.

For the year ended December 31, 2018, Legacy recorded $49.2 million of net gains on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivative contracts during the period and are primarily based on oil and natural gas futures prices. The net gain recognized during 2018 was primarily due to decrease in oil futures prices for periods beyond 2018, which increased the fair value of our derivatives in such periods, partially offset by cash payments on oil derivative contracts during the year. For the year ended December 31, 2017, Legacy recorded $17.8 million of net gains on oil and natural gas derivatives. The net gain recognized during 2017 was primarily due to cash receipts and the decrease in natural gas futures prices for periods beyond 2017, which increased the fair value of our derivatives in such periods. Settlements of such contracts resulted in cash (payments)/receipts of $(11.7) million and $24.2 million during 2018 and 2017, respectively.

Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, increased to $191.3 million ($11.02 per Boe) for the year ended December 31, 2018 from $173.6 million ($10.58 per Boe) for the year ended December 31, 2017. This increase is primarily attributable to increased workover and repair activity across all operating regions as well as general cost increases due to higher commodity prices and field activity. These increases resulted in increased production expenses per Boe during 2018 compared to 2017. Legacy’s ad valorem tax expense decreased period over period primarily due to reductions in ad valorem tax expenses on certain non-operated properties.

Legacy’s production and other taxes were $29.5 million and $19.8 million for the years ended December 31, 2018 and 2017, respectively. Production and other taxes increased due to higher ~~oil~~total revenues in 2018. On a per Boe basis, production and other taxes increased to $1.70 for the year ended December 31, 2018 from $1.21 for the year ended December 31, 2017 due to higher realized oil prices.

Legacy’s general and administrative expenses were $73.0 million and $49.4 million for the years ended December 31, 2018 and 2017, respectively. General and administrative expenses increased approximately $23.7 million between periods primarily due to a $21.8 million increase in long-term incentive compensation expense due to the acceleration of expense in conjunction with the Corporate Reorganization.

Legacy’s 39depletion, depreciation, amortization and accretion expense, or DD&A, was $160.0 million and $126.9 million for the years ended December 31, 2018 and 2017, respectively. DD&A increased primarily due to higher depletion rates

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Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $160.0 million and $126.9 million for the years ended December 31, 2018 and 2017, respectively. DD&A increased primarily due to higher depletion rates across our historical properties primarily related to increased production rates combined with decreased reserves. Our depletion rate per Boe for the year ended December 31, 2018 was $9.22 compared to $7.73 for the year ended December 31, 2017. This increase is primarily driven by the increased depletion rates as discussed above.

Impairment expense was $68.0 million and $37.3 million for the years ended December 31, 2018 and 2017, respectively. In 2018, Legacy recognized $58.7 million of impairment expense in 50 separate producing fields, due primarily to the further decline in oil and natural gas futures prices in late 2018 as well as increased expenses and well performance during the year ended December 31, 2018, which decreased the expected future cash flows below the carrying value of the assets. Additionally, we recorded impairment of $9.3 million related to unproved properties acquired since 2010 that, in the current and expected future commodity price environment, are no ~~loger~~longer economically viable. In 2017, Legacy recognized impairment expense of $37.3 million in 47 separate producing fields, due primarily to the further decline in oil and natural gas futures prices in early 2017 as well as increased expenses and well performance during the ~~year~~ ended December 31, 2017, which decreased the expected future cash flows below the carrying value of the assets.

Interest expense was $117.0 million and $89.2 million for the years ended December 31, 2018 and 2017, respectively. The increase in interest expense is primarily due to interest expense on our Second Lien Term Loans issued in October 2016 partially offset by a reduction in bond interest expense due to repurchases of our ~~6.625% senior unsecured notes maturing on December 1, 2020 (the "~~2021 Senior Notes") completed during 2018. Cash (receipts)/payments on our interest rate swaps were $(1.3) million and $0.8 million in 2018 and 2017, respectively.

During the year ~~ended~~ December 31, 2018, we recorded a gain on extinguishment of debt of $66.1 million due to the repurchase of 2021 Senior Notes and ~~the~~ exchange of Senior Notes for 2023 Convertible ~~Senior~~ Notes.

Income tax expense was $3.0 million and $1.4 million for the years ended December 31, 2018 and 2017, respectively. Income tax expense for both periods is primarily related to certain subsidiaries which were subject to corporate income tax prior to the Corporate Reorganization. The change in our income tax provision in 2018 was due to the Corporate Reorganization along with Legacy’s position to record a full valuation allowance. The effective income tax rates for the years ended December 31, 2018, and 2017 were 6.3% and (2.7)%, respectively. 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, the 2023 Convertible Notes issuance, Texas margins tax, and the valuation allowance. For the year ended December 31, 2017, our effective tax rate differed from the statutory rate primarily due to Legacy LP’s loss not being subject to U.S. federal income tax and Texas margins tax.

As a result of the items described above, Legacy recorded net income/(losses) of $43.8 million and $(53.9) million for the years ended December 31, 2018 and 2017, respectively.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Legacy’s revenues from the sale of oil were $239.4 million and $152.5 million for the years ended December 31, 2017 and 2016, respectively. Legacy’s revenues from the sale of NGLs were $24.8 million and $15.4 million for the years ended December 31, 2017 and 2016, respectively. Legacy’s revenues from the sale of natural gas were $172.1 million and $146.4 million for the years ended December 31, 2017 and 2016, respectively. The $86.9 million increase in oil revenue reflects an increase in oil production of 1,013 MBbls (25%) and an increase in average realized price of $9.64 per Bbl (25%) to $47.59 for the year ended December 31, 2017 from $37.95 for the year ended December 31, 2016. The increase in realized oil price was primarily caused by an increase in the average WTI crude oil price of $7.51 and improved realized regional differentials. The increase in production is due to an increase in net well count under our JDA following the Acceleration Payment and continued development of our Permian Basin horizontal assets. The increase was partially offset by individually immaterial divestitures and natural declines. The $9.4 million increase in NGL revenues reflects an increase in realized NGL price of $0.23 per Gal (55%) to $0.65 per Gal for the year ended December 31, 2017 from $0.42 per Gal for the year ended December 31, 2016 and an increase in NGL production of 1,402 MGals (4%) during 2017. The $25.6 million increase in natural gas revenues reflects an increase our realized natural gas prices partially offset by a decrease in our natural gas production volumes. Average realized gas prices increased by $0.55 per Mcf (25%) to $2.74 per Mcf for the year ended December 31, 2017 from $2.19 per Mcf for the year ended December 31, 2016, primarily due to an increase in the average NYMEX Henry Hub natural gas price of $0.47 per Mcf over the same time period and increased natural gas volumes produced from assets in the Permian Basin which are accounted for inclusive of the NGL content contained within the natural gas volumes, resulting in a realized gas price for those assets that is higher than the NYMEX Henry Hub index price. Our natural gas production decreased by approximately 3,991 MMcf (6%), primarily due to natural production declines in our East Texas and Piceance Basin properties partially offset by increased production from the assets developed by our Permian Basin horizontal development program.

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For the year ended December 31, 2017, Legacy recorded $17.8 million of net gains on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivative contracts during the period and are primarily based on oil and natural gas futures prices. The net gain recognized during 2017was primarily due to cash receipts and the decrease in natural gas futures prices for periods beyond 2017, which increased the fair value of our derivatives in such periods. For the year ended December 31, 2016, Legacy recorded $41.2 million of net losses on oil and natural gas derivatives. The net loss recognized during 2016 was primarily due to the increase in futures prices for periods beyond 2016, which reduced the fair value of our derivatives in such periods. Settlements of such contracts resulted in cash receipts of $24.2 million and $64.5 million during 2017 and 2016, respectively.

Legacy’s oil and natural gas production expenses, excluding ad valorem taxes, increased to $173.6 million ($10.58 per Boe) for the year ended December 31, 2017 from $169.8 million ($10.59 per Boe) for the year ended December 31, 2016. This increase is primarily attributable to increased workover and repair activity across all operating regions, increased well count due to our Permian horizontal drilling program and increased working interests under our JDA following the Acceleration Payment partially offset by general cost reduction efforts. These reduction efforts, as well as the increase in oil and NGL production, resulted in decreased production expenses per Boe during 2017compared to 2016. Legacy’s ad valorem tax expense remained consistent period over period due to increased oil and natural gas property valuations offset by immaterial divestitures.

Legacy’s production and other taxes were $19.8 million and $14.3 million for the years ended December 31, 2017 and 2016, respectively. Production and other taxes increased due to higher total revenues in 2017. On a per Boe basis, production and other taxes increased to $1.21 for the year ended December 31, 2017 from $0.89 for the year ended December 31, 2016 due to higher realized prices.

Legacy’s general and administrative expenses were $49.4 million and $43.6 million for the years ended December 31, 2017 and 2016, respectively. General and administrative expenses increased approximately $5.7 million between periods primarily due to a $3.5 million increase in transaction-related expenses and other general cost increases.

Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $126.9 million and $150.4 million for the years ended December 31, 2017 and 2016, respectively. DD&A decreased primarily due to lower depletion rates across our historical properties primarily related to impairment charges incurred in 2016 and 2017, which reduced our depletable cost basis. This decrease was partially offset by additional well count from our Permian Basin horizontal development program. Our depletion rate per Boe for the year ended December 31, 2017 was $7.73 compared to $9.38 for the year ended December 31, 2016. This decrease is primarily driven by a lower net cost basis on our historical assets due to previously recognized depletion and impairment.

Impairment expense was $37.3 million and $61.8 million for the years ended December 31, 2017 and 2016, respectively. In 2017, Legacy recognized $37.3 million of impairment expense in 47 separate producing fields, due primarily to the further decline in oil and natural gas futures prices in early 2017 as well as increased expenses and well performance during the year ended December 31, 2017, which decreased the expected future cash flows below the carrying value of the assets. In 2016, Legacy recognized impairment expense of $61.8 million in 43 separate producing fields, due primarily to well performance and the further decline in commodity prices during the year ended December 31, 2016, which decreased the expected future cash flows below the carrying value of the assets.

Interest expense was $89.2 million and $79.1 million for the years ended December 31, 2017 and 2016, respectively. The increase in interest expense is primarily due to interest expense on our Second Lien Term Loans issued in October 2016 partially offset by a reduction in bond interest expense due to repurchases and exchanges of our 8% senior unsecured notes maturing on December 1, 2020 (the "2020 Senior Notes") and our 6.625% senior unsecured notes maturing on December 1, 2021 (the "2021 Senior Notes", together with the 2020 Senior Notes, the "Senior Notes") completed during 2016. Additionally, interest expenses related to the gains (losses) on our interest rate swaps decreased by $3.3 million to $1.2 million in 2017 from $(2.1) million in 2016. Cash payments on our interest rate swaps were $0.8 million and $2.7 million in 2017 and 2016, respectively.

As a result of the items described above, Legacy recorded net losses of $53.9 million and $55.8 million for the years ended December 31, 2017 and 2016, respectively. The decrease in net loss was primarily due to a decrease in impairment expense to $37.3 million during the year ended December 31, 2017 from $61.8 million for the year ended December 31, 2016 as well as increased revenue from our oil, natural gas and NGL production. These factors were partially offset by a decrease in the gain on extinguishment of debt in 2017 as compared to 2016.

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Non-GAAP Financial Measure

Legacy’s management uses Adjusted EBITDA as a tool to provide additional information and a metric relative to the performance of Legacy’s business. Legacy’s 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 our peers. Adjusted EBITDA may not be comparable to a similarly titled measure of such peers because all entities 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) loss on extinguishment of debt;

• Income tax expense (benefit);

• Depletion, depreciation, amortization and accretion;

• Impairment of long-lived assets;

~~• Loss (gain) on disposal of assets;~~28

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

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

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

• Net (gains) losses on commodity derivatives;

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

• Transaction costs.

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~~The~~•Loss ~~following table presents a reconciliation of Legacy’s consolidated net income~~ (~~loss~~gain) toon ~~Adjusted~~disposal ~~EBITDA~~of ~~for the years ended December 31, 2018, 2017 and 2016, respectively.~~ assets;

	Year Ended December 31,
	2018			2017			2016
	(In thousands)
Net income (loss)	$	43,833		$	(53,897	)	$	(55,820	)
Plus:
Interest expense	117,008			89,206			79,060
Gain on extinguishment of debt	(66,066		)	—			(150,802		)
Income tax expense (benefit)	2,968			1,398			1,229
Depletion, depreciation, amortization and accretion	159,998			126,938			150,414
Impairment of long-lived assets	67,978			37,283			61,796
Loss (gain) on disposal of assets	(23,803		)	1,606			(50,095		)
Equity income (loss) of equity method investees	19			(17		)	—
Unit-based compensation expense	28,362			6,597			7,198
Minimum payments received in excess of overriding royalty interest earned(a)	1,902			1,936			1,659
Net (gains) losses on commodity derivatives	(49,172		)	(17,776		)	41,224
Net cash settlements received on commodity derivatives	(11,715		)	24,156			64,505
Transaction costs	5,636			8,769			5,245
Adjusted EBITDA	$	276,948		$	226,199		$	155,613

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

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

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

•Net (gains) losses on commodity derivatives;

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

•Exploration expenses; and

•Transaction costs.

The following table presents a reconciliation of Legacy’s consolidated net income (loss) to Adjusted EBITDA for the period December 11 to December 31, 2019 (Successor), period January 1, to December 10, 2019 (Predecessor), and the years ended December 31, 2018 and 2017 (Predecessor):


	Successor		Predecessor
	Period from		Period from
	December 11, 2019		January 1, 2019
	to December 31,		to December 10,		Year Ended December 31,
(In thousands)	2019		2019		2018		2017

Net income (loss)	$	3,050	$	173,876	$	43,833	$	(53,897)
Plus:
Interest expense	1,607		115,660		117,008		89,206
Gain on extinguishment of debt	—		(13,105)		(66,066)		—
Income tax expense (benefit)	3		105		2,968		1,398
Depletion, depreciation, amortization and accretion	6,259		156,935		159,998		126,938
Impairment of long-lived assets	—		105,532		67,978		37,283
Loss (gain) on disposal of assets	(565)		2,130		(23,803)		1,606
Equity income (loss) of equity method investees	2		35		19		(17)
Unit-based compensation expense	—		14,791		28,362		6,597
Minimum payments received in excess of overriding royalty interest earned(a)	395		2,058		1,902		1,936

Net (gains) losses on commodity derivatives	6,292		50,294		(49,172)		(17,776)
Net cash settlements received on commodity derivatives	77		23,687		(11,715)		24,156
Exploration expense	750		—		—		—
Transaction and other restructuring related charges	—		(427,003)		5,635		8,769
Adjusted EBITDA	$	17,870	$	204,995	$	276,947	$	226,199

____________________

(a) A portion of minimum payments received 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 ~~year~~period ~~ended~~of December 11, 2019 through December 31, ~~2018~~2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), Adjusted EBITDA ~~increased~~decreased 22(20)% to $~~276~~222.98 million from $~~226~~276.29 million for the year ended December 31, ~~2017~~2018 (Predecessor). This ~~increase~~decrease is due primarily to ~~increased~~decreased oil and natural gas production as well as ~~increased~~decreased realized commodity prices ~~partially offset by lower commodity derivative realizations and increased production costs~~. For the year ended December 31, ~~2017~~2018 (Predecessor), Adjusted EBITDA increased 4522% to $~~226~~276.29 million from $~~155~~226.62 million for the year ended December 31, ~~2016~~2017 (Predecessor). This increase is due primarily to increased oil and natural gas production as well as increased realized commodity prices partially offset by lower commodity derivative realizations and increased production costs.

~~Capital Resources and Liquidity~~29

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, our second lien term loans 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 on hand and cash flow from operations will provide us sufficient liquidity to fund our operations in 2019 including our planned capital expenditures of approximately $135 million, subject to any limitations contained in the agreements governing our indebtedness. However, we could breach certain 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. While we have received a waiver under our Term Loan Credit Agreement that requires us to deliver audited financial statements without a “going concern” or like qualification or exception, such waiver expires on May 31, 2019 and such default cannot be remedied. Further, upon delivery of our financial statements for the quarter ended March 31, 2019, we expect to be in violation of the current ratio covenant under our Credit Agreement, which would constitute a default under the Credit Agreement. Defaults, 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 or Term Loan 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.”

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~~Our~~Capital ~~Credit~~Resources Agreement initially became a current liability as of April 1, 2018 as the Credit Agreement was set to mature on April 1, 2019. On March 21, 2019, we entered into the Twelfth Amendment (the “Twelfth Amendment”) to our Credit Agreement, providing for, among other things, (i) an extension of the maturity of the Credit Agreement to May 31, 2019, (ii) an increase in the applicable interest rate by 2.25%, (iii) the payment of a fee equal to 0.35% of the amount of the current borrowing base under the Credit Agreement, payable on the effective date of the Twelfth Amendment, (iv) the mandatory termination of our derivative contracts three days prior to the maturity of the Credit Agreement, (vi) the reduction in the borrowing base from $575 million to $570 million, effective May 22, 2019, (vii) the reduction in the maximum consolidated cash balance we can maintain without prepaying the loans to $15 million, effective April 1, 2019 and (viii) the payment of a fee equal to 0.15% of the amount of the current borrowing base under the Credit Agreement, payable on the earliest to occur of (x) May 31, 2019 or (y) an acceleration of the outstanding indebtedness under the Credit Agreement. Additionally, the Amendment waives certain deviations from the requirements of the Credit Agreement, including the delivery of fiscal year 2018 audited financial statements with a “going concern” or like qualification or exception and non-compliance with the current ratio covenant for the fourth quarter of 2018.Liquidity

~~Our~~Since ~~commodity~~Legacy's ~~derivatives~~emergence ~~position,~~from ~~which~~the weChapter ~~use~~11 toCases, ~~mitigate~~Legacy’s ~~commodity~~primary ~~price~~sources ~~volatility~~of capital and ~~(if~~liquidity ~~positive)~~have ~~support~~been cash flow from operations, realizations from our ~~borrowing~~commodity ~~capacity~~derivatives, ~~resulted~~bank inborrowings, ~~$11.7~~or ~~million~~a combination thereof and Legacy’s primary use of ~~cash~~capital ~~payments~~has inbeen for development of oil and gas wells and the ~~year~~repayment ~~ended~~of ~~December 31,~~bank ~~2018~~borrowings.

AsBased ~~market~~upon ~~conditions~~current ~~warrant,~~oil weand ~~may,~~natural ~~subject~~gas toprice ~~certain~~expectations ~~restrictions,~~and ~~repurchase, exchange or otherwise pay down~~ our ~~outstanding~~commodity ~~debt,~~derivative ~~including our Senior Notes~~positions, inwe ~~open~~anticipate ~~market~~that ~~transactions,~~cash ~~privately~~on ~~negotiated~~hand ~~transactions,~~and bycash ~~tender~~flow ~~offer~~from oroperations ~~otherwise~~will ~~which~~provide ~~may~~us ~~impact~~sufficient ~~the trading~~ liquidity ofto ~~such~~fund ~~securities.~~our ~~The~~operations ~~amounts involved~~ in ~~any such transactions~~2020, ~~individually~~including orour incapital ~~the~~expenditures ~~aggregate,~~of ~~may be material. In January 2018, we repurchased~~ approximately $~~187~~55.10 million. ofThe ~~original~~current ~~principal~~outlook ~~amount~~for ofcommodity ~~our~~prices ~~2021~~remains ~~Senior~~uncertain ~~Notes~~after ~~from~~a ~~certain~~severe ~~holders~~decline in aMarch ~~single~~and ~~transaction.~~April ~~During the fourth quarter 2018, we exchanged $3~~2020.1 ~~million~~Our ~~and~~planned ~~$5.3~~capital ~~million~~expenditures ofin 2020 ~~Senior~~does ~~Notes~~not ~~and~~contain ~~2021~~significant ~~Senior~~amounts ~~Notes,~~necessary ~~respectively,~~to ~~for~~maintain 1leasehold ~~million~~interests, ~~shares~~is ofnot ~~common~~expected ~~stock~~to ~~and~~maintain 2our ~~million~~year-end ~~shares~~or ofQ4 ~~our~~2019 ~~common~~production ~~stock~~levels, ~~respectively. During 2016, Legacy LP repurchased approximately $52.0 million of original principal amount of 2020 Senior Notes~~ and ~~$117.3~~is ~~million~~subject ofto ~~original~~significant ~~principal~~change ~~amount~~based ~~of 2021 Senior Notes~~ on ~~the~~management’s ~~open~~view ~~market, and exchanged 2,719,124 units for $15.0 million~~ of ~~face~~commodity ~~amount of our 2020 Senior Notes~~prices.

~~Future~~Our ~~Liquidity~~commodity ~~Considerations~~derivatives position, which we use to mitigate commodity price volatility and (if positive) support our borrowing capacity, resulted in $0.1 million and $23.7 million of cash payments for the period December 11 to December 31, 2019 (Successor) and the period January 1, to December 10, 2019 (Predecessor), respectively.

~~Our~~The ~~Term~~COVID-19 ~~Loan~~pandemic ~~Credit~~may ~~Agreement~~impact ~~contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. Under~~ the ~~Term~~ability ~~Loan Credit Agreement, if as~~ of ~~the last day of any fiscal quarter,~~ our ~~“First~~customers ~~Lien~~to ~~Debt~~continue to ~~EBITDA”~~purchase ~~ratio~~our isproduced ~~less~~oil ~~than~~and ~~(i)~~natural ~~1.50:1.00~~gas ~~between~~at ~~March~~current ~~31,~~levels ~~2018~~due ~~and~~to ~~June~~increased ~~30,~~supply ~~2019~~ and ~~(ii)~~storage ~~1.25:1.00~~capacity ~~between September 30~~shortages, ~~2019~~which ~~and~~would ~~December~~reduce ~~31,~~our ~~2019,~~future ~~then~~expected werevenues ~~are~~and ~~restricted~~may ~~from~~have ~~spending~~a ~~more~~material ~~than~~adverse ~~$60~~effect ~~million~~ on ~~capital~~our ~~expenditures~~financial position, ~~acquisitions~~results ~~or investments for the subsequent four quarters. As~~ of ~~December 31,~~operations ~~2018,~~and ~~our First Lien Debt to EBITDA ratio was 1~~liquidity.~~95.~~

Interest payments on our Senior Notes are payable on June 1, 2019 and December 1, 2019 through the respective maturities.

In order to improve our liquidity position, we are currently evaluating financial, transactional and other strategic alternatives which include, among others, a sale or other business combination transaction, sales of assets, financing transactions, or some combination of these. There can be no assurance that sufficient liquidity can be raised from any one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations. The significant risks and uncertainties described under “Risk Factors-Risks Related to the Business” raise substantial doubt about our ability to continue as a going concern. The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements in this annual report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about Legacy’s ability to continue as a going concern.

Cash Flow from Operations

Our net cash provided by operating activities was $~~175~~(0.91) million ~~and $99.8 million~~ for the ~~years~~period ~~ended~~December 11 to December 31, ~~2018~~2019 ~~and~~(Successor). ~~2017~~For the period January 1, ~~respectively~~to December 10, ~~with~~2019 ~~the~~(Predecessor), net cash provided by operating activities decreased relative to 2018 ~~period~~to ~~being~~$55.2 ~~favorably~~million, ~~impacted~~due byto ~~higher~~reorganization costs and lower realized commodity prices relative. For the year ended December 31, ~~partially~~2018 ~~offset~~(Predecessor) cash provided by ~~higher~~operating ~~production~~activities ~~expenses~~was $175.9 million.

Our net cash provided by (used in) operating activities was $~~100~~175.29 million and $(099.3)8 million for the years ended December 31, ~~2017~~ 2018 and ~~2016~~2017 (Predecessor), respectively, with the ~~2017~~2018 period being favorably impacted by higher realized commodity prices, partially offset by higher production expenses.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, NGL and natural gas prices. Oil, NGL and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control, including the COVID-19 pandemic. Our future cash flow from operations will depend on the prices of oil, NGLs and natural gas, as well as our ability to maintain production and manage expenditures in light of the COVID-19 pandemic.

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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, NGLs and natural gas.

Investing Activities

Our cash capital expenditures were $~~227~~7.92 million and $128.1 million for the ~~year~~period ~~ended~~December 11 to December 31, ~~2018.~~2019 ~~The~~(Successor), ~~total~~period ~~includes~~January ~~$13.2~~1, ~~million related~~ to ~~individually~~December ~~immaterial~~10, ~~acquisitions~~2019 ~~and~~(Predecessor), ~~$221~~respectively.5 The ~~million~~total ofis comprised primarily of development projects.

Our cash capital expenditures were $~~313~~227.9 million for the year ended December 31, ~~2017~~2018 (Predecessor). The total includes $~~163~~13.42 million related to ~~the Acceleration Payment and 6~~ individually immaterial acquisitions and $~~150~~221.65 million of development projects.

We currently anticipate that our development capital budget, which predominantly consists of drilling, recompletion and well stimulation projects related to our horizontal Permian Basin inventory will be approximately $~~135~~55.0 million, ~~subject to any limitations contained in the agreements governing our indebtedness,~~ for the year ending December 31, ~~2019~~2020. Our available borrowing capacity under our Successor Revolving Credit ~~Agreement~~Facility is $288.90 million as of ~~March~~April 1327, ~~2019~~2020. ~~The amount and timing of our capital expenditures is largely discretionary and within our control~~However, ~~with~~ the ~~exception~~COVID-19 ofpandemic ~~certain projects managed by other operators. Accordingly, we routinely monitor~~ and ~~adjust~~the ~~our~~disruption ~~capital expenditures~~ in ~~response~~the ~~to changes in~~ oil ~~and~~market ~~natural~~is ~~gas~~expected ~~prices,~~to ~~drilling~~lead ~~and~~to acquisition costs, industry conditions, non-operated capital requirements and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a ~~timely manner as well as other regulatory matters.~~significant

Wereduction ~~enter~~in ~~into~~the ~~oil~~borrowing ~~and~~base ~~natural~~under ~~gas~~our ~~derivatives~~Successor toRevolving ~~reduce~~Credit ~~the~~Facility. ~~impact~~The ofamount ~~oil~~ and ~~natural~~timing ~~gas~~of ~~price volatility on~~ our ~~operations.~~capital Atexpenditures ~~March 13,~~is ~~2019,~~largely wediscretionary ~~had~~and inwithin ~~place~~our ~~oil~~control, ~~natural~~with ~~gas~~the ~~and~~exception ~~price differential derivatives covering portions~~ of ~~our~~certain ~~estimated~~projects ~~2019~~managed ~~oil~~by ~~and~~other ~~natural gas production~~operators. ~~However,~~As ~~our~~the ~~Credit~~majority ~~Agreement~~of ~~provides~~our ~~for~~capital ~~the~~budget ~~mandatory~~is ~~termination~~comprised of ~~our~~operated ~~derivative~~properties ~~contracts~~in ~~three~~which ~~days~~we ~~prior~~control to the ~~maturity~~timing ~~date~~ of ~~our~~capital ~~Credit Agreement.~~expenditure

activity, if the borrowing base reduction under our Successor Revolving Credit Facility is larger than expected we can and will

defer a portion or all of our planned capital expenditures to a future date. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions, non-operated capital requirements and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner as well as other regulatory matters.

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We enter into oil and natural gas derivatives to reduce the impact of oil and natural gas price volatility on our operations. At April 27, 2020, we had in place oil, natural gas and price differential derivatives covering portions of our estimated oil and natural gas production for 2020 through 2023.

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 in place as of ~~March~~April 1327, ~~2019~~2020 covering the period from January 1, ~~2019~~2020 through December 31, ~~2019~~2023. We use derivatives, including swaps, enhanced swaps and three-way collars, as our mechanism for offsetting the cash flow effects of changes in commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to reduce the effects on cash flow of the floating prices we are paid by purchasers of our oil and natural gas. These transactions are mostly settled based upon the monthly average closing price of front-month NYMEX WTI oil and the price on the last trading day of front-month NYMEX Henry Hub natural gas.

Oil Swaps:

Calendar Year	~~Volumes (Bbls)~~	~~Average Price per Bbl~~	~~Price~~Volumes ~~Range per Bbl~~(Bbls)			Average Price per Bbl	Price Range per Bbl
2019	3,285,000	$61.33	$57.15	-	$67.65
2020			3,660,000			$55.62	$54.10	-	$56.00
2021			2,555,000			$52.80	$52.40	-	$53.22
2022			2,190,000			$51.03	$49.95	-	$51.95
2023			1,898,000			$50.51	$49.40	-	$50.90

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) 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 downtimes 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 swap contracts currently in place as of March 13, 2019, covering the period from January 1, 2018 through December 31, 2019:

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Calendar Year		Volumes (Bbls)		Average Price per Bbl		Price Range per Bbl
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 March 13, 2019, covering the period from January 1, 2019 through December 31, 2019:

		Average Long	Average Short
Calendar Year	Volumes (Bbls)	Put Price per Bbl	Call Price per Bbl
2019	1,460,000	$70.00	(2.91)

Natural Gas Swaps:

		~~Average~~	~~Price Range per~~			Average	Price Range per
Calendar Year	~~Volumes (MMBtu)~~	~~Price per MMBtu~~	Volumes (MMBtu)			Price per MMBtu	MMBtu
2019	37,175,000	$3.36	$3.05	-	$4.40
2020			39,640,000			$2.33	$2.28	-	$2.40
2021			34,675,000			$2.41	$2.37	-	$2.44
2022			32,850,000			$2.41	$2.41	-	$2.42
2023			29,200,000			$2.45	$2.44	-	$2.47

We have ~~also~~ entered into regional ~~natural~~crude ~~gas~~oil differential swap contracts in which we have swapped the floating ~~CIG~~WTI-ARGUS ~~natural~~(Midland) ~~gas~~crude oil price for floating WTI-ARGUS (Cushing) less a ~~floating~~fixed-price differential. As noted above, we receive a discount to the NYMEX ~~Henry~~WTI ~~Hub~~crude oil price ~~less~~at athe ~~fixed~~point ~~differential~~of sale. The following table summarizes ~~these~~the ~~type~~oil ofdifferential ~~enhanced~~ swap contracts currently in place as of ~~March~~April 1327, ~~2019~~2020, covering the period from January 1, ~~2019~~2020 through December 31, ~~2019~~2023:

		Average	Price Range per
Calendar Year			Volumes (Bbls)			Average Price per Bbl	Price Range per Bbl
Calendar Year	Volumes (MMBtu)	Price per MMBtu	MMBtu
2020			3,170,000			$0.95	$0.90	-	$1.00
2019	3,600,000	$(0.47)	$(0.46)	-	$(0.49)
2021			2,555,000			$1.06	$1.05	-	$1.10
2022			1,825,000			$1.14	$1.07	-	$1.20
2023			1,825,000			$1.07	$1.00	-	$1.15

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We have entered into regional natural gas differential swap contracts in which we have swapped the floating WAHA natural gas price for a floating NYMEX Henry Hub price less a fixed differential. The following table summarizes this type of enhanced swap in place as of April 27, 2020, covering the period from January 1, 2020 through December 31, 2023:


		Average	Price Range per
Calendar Year	Volumes (Bbls)	Price per MMBtu	MMBtu
2020	6,410,000	$(1.85)	$(1.74)	-	$(1.98)
2021	7,300,000	$(1.14)	$(1.14)	-	$(1.15)
2022	7,300,000	$(0.77)	$(0.74)	-	$(0.80)
2023	7,300,000	$(0.62)	$(0.62)	-	$(0.62)

We have also entered into regional natural gas differential swap contracts in which we have swapped the floating CIG natural gas price for a floating NYMEX Henry Hub price less a fixed differential. The following table summarizes these type of enhanced swap contracts currently in place as of April 27, 2020, covering the period from January 1, 2020 through December 31, 2023:


		Average	Price Range per
Calendar Year	Volumes (MMBtu)	Price per MMBtu	MMBtu
2020	9,470,000	$(0.56)	$(0.55)	-	$(0.58)
2021	7,300,000	$(0.56)	$(0.56)
2022	7,300,000	$(0.54)	$(0.54)
2023	7,300,000	$(0.54)	$(0.54)

Financing Activities

Our net cash provided by (used in) financing activities was $12(10.10) million ~~for the year ended December 31~~, ~~2018 and~~ $~~177~~91.7 million ~~for the year ended December 31~~, 2017. During the year ended December 31, 2018, total net borrowings under our Credit Agreement were $42.0 million. We raised $131.0 million in proceeds, net of original issue discount, but excluding other offering expenses paid by us, from a draw under our Term Loan Credit Agreement and ~~used the proceeds to repurchase~~ $~~187~~12.1 million ~~of Senior Notes~~ for ~~$132.1~~the ~~million, inclusive of accrued but unpaid interest. Legacy’s net cash provided by financing activities was $177.7 million~~ for the ~~year~~period ~~ended~~ December ~~31,~~ ~~2017,~~11 ~~compared~~ to ~~$119.1~~ ~~million used in financing activities for the year ended~~ December 31, ~~2016.~~2019 ~~During the year ended December 31~~(Successor), ~~2017,~~period ~~total~~January ~~net borrowings under our Credit Agreement were $36.0 million. We raised $142.~~1 ~~million in proceeds~~, ~~net~~to ofDecember ~~original issue discount~~10, ~~but~~2019 ~~excluding other offering expenses paid by us~~(Predecessor), ~~from~~and ~~a draw under our Term Loan Credit Agreement. Our net cash used in financing activities was $119.1 million for the~~ year ended December 31, ~~2016. During the year ended December 31~~2018, ~~2016, total net repayments under our Revolving Credit Agreement were $145~~respectively.0 ~~million. We raised $58.8 million in proceeds, net of original issue discount, but excluding other offering expenses paid by us, from a draw under our Term Loan Credit Agreement.~~

~~Our~~The primary driver of net cash used in financing activities during the period December 11 to December 31, 2019 (Successor) were repayments of debt of $27.0 million under the Successor Revolving Credit Facility.

OnNet ~~April~~cash 1,used ~~2014,~~in ~~Legacy~~financing LPactivities ~~entered~~for 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~~period ~~party~~January ~~thereto (as amended, the “Credit Agreement”). On March 21, 2019, the maturity of the Credit Agreement was extended from April~~ 1, 2019 to ~~May~~December 3110, 2019. ~~Our~~(Predecessor) ~~obligations~~were ~~under~~repayments ~~the Credit Agreement are secured by mortgages on over 95%~~ of ~~the~~debt ~~total value~~ of ~~its~~$779.8 ~~oil~~million, ~~and~~which ~~natural~~included ~~gas~~repayment ~~properties as well as a pledge~~ of ~~all~~debt of ~~its ownership interests in our operating subsidiaries and Legacy's ownership interests in the General Partner~~$596.0 ~~Concurrently~~million ~~with the Corporate Reorganization, the General Partner and Legacy Inc. provided guarantees of Legacy LP's obligations~~ under the Predecessor Credit ~~Agreement.~~Facility ~~The~~in ~~amount~~accordance ~~available~~with ~~for borrowing at any one time is limited to~~ the ~~borrowing base and contains a $2 million sub-limit for letters of credit~~Plan. ~~The~~In ~~borrowing base is currently set at $575 million~~addition, ~~and~~net ascash ofprovided ~~March 13,~~by ~~2019,~~financing weactivities ~~have~~included ~~approximately~~ $~~571~~626.8 million ~~drawn~~from borrowings under the ~~Credit~~credit ~~Agreement~~facility, ~~leaving~~which ~~approximately~~included $2388.90 million offrom ~~current~~proceeds ~~availability.~~from ~~Under~~ the ~~terms~~Successor ofRevolving ~~the~~ Credit ~~Agreement, our borrowing base reduces to $570 million on May 22, 2019~~Facility. ~~Additionally,~~In ~~either Legacy or the lenders may~~addition, ~~once~~net ~~during~~cash ~~each~~provided ~~calendar~~by ~~year,~~financing ~~elect~~activities toincluded ~~redetermine~~$256.3 ~~the~~million ~~borrowing~~in ~~base~~proceeds ~~between~~from ~~scheduled~~rights ~~redeterminations~~offerings. ~~Legacy also~~

During 46the year ended December 31, 2018, total net borrowings under our Term Loan Credit Agreement were $42.0 million. We raised $131.0 million in proceeds, net of original issue discount, but excluding other offering expenses paid by us, from a draw under our Term Loan Credit Agreement and used the proceeds to repurchase $187.1 million of Senior Notes for $132.1 million, inclusive of accrued but unpaid interest.

Successor Credit Agreement

On the Effective Date, Legacy entered into a credit agreement (the "Credit Agreement") among Legacy, as borrower, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as the administrative agent, the collateral agent and the issuing bank. Pursuant to the Credit Agreement, the lenders party thereto agreed to provide a new reserves-based revolving credit facility (the "Successor Revolving Credit Facility") with initial aggregate commitments in the amount of $1.5 billion, subject to a borrowing base. The initial borrowing base under the Credit Agreement is $460 million. Semi-annual redetermination occurs on April 1 and October 1 of each year. Our available borrowing capacity under our Successor Revolving Credit Facility is $88.0 million as of April 27, 2020. However, we expect the COVID-19 pandemic and the disruption in the oil market to lead to a significant reduction in the borrowing base under the Successor Revolving Credit Facility, which will reduce our borrowing capacity.

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~~has~~The ~~the~~stated ~~right,~~maturity ~~once~~date ~~during~~under ~~each calendar year, to request~~ the ~~redetermination~~Credit ofAgreement ~~the~~is ~~borrowing~~December ~~base~~11, ~~upon~~2023. ~~the~~The ~~proposed~~loans ~~acquisition~~under ~~of certain oil and natural gas properties where~~ the ~~purchase~~Successor ~~price~~Revolving isCredit ~~greater~~Facility ~~than~~shall ~~10%~~bear ofinterest ~~the~~based ~~borrowing~~on ~~base then in effect. Any increase in the~~ borrowing base ~~requires~~utilization ~~the~~percentage ~~consent~~at ofa ~~all~~rate ~~the~~per ~~lenders,~~annum ~~and~~equal ~~any~~to ~~decrease in or maintenance of~~ the ~~borrowing~~alternate base ~~must~~rate beplus ~~approved~~a bymargin ~~the~~ranging ~~lenders~~from ~~holding~~1.25% atto ~~least 66-~~2/3.25% offor ~~the~~alternate ~~outstanding~~base ~~aggregate~~rate ~~principal amounts of the~~ loans or ~~participation~~the ~~interests~~adjusted inLIBOR ~~letters~~rate ofplus ~~credit~~a ~~issued~~margin ~~under~~ranging ~~the~~from ~~Credit Agreement~~2.25% ~~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/~~3.25% offor ~~the~~LIBOR ~~outstanding~~loans. Unused ~~aggregate~~commitments ~~principal~~under ~~amounts of~~ the ~~loans~~Credit orAgreement ~~participation~~will ~~interests~~accrue ina ~~letters~~commitment offee ~~credit~~at ~~issued~~a ~~under~~rate ~~the~~per ~~Credit~~annum ~~Agreement~~of so0.50%. All ~~long~~interest asand itcommitment ~~does~~fees ~~not~~are ~~increase~~payable ~~the~~quarterly ~~borrowing base then~~ in ~~effect~~arrears.

AsLegacy ~~of December 31,~~may ~~2018~~elect, ~~our~~at ~~ratio~~its ~~of consolidated current assets to consolidated current liabilities was less than 1.0 to 1.0~~option, ~~in violation of a covenant contained in our Credit Agreement. On March 21, 2019, we received waivers with respect~~ to ~~compliance~~prepay ~~with~~any ~~such~~loan ~~covenant~~under ~~for~~ the ~~fiscal~~Successor ~~quarter~~Revolving ~~ended~~Credit ~~December 31,~~Facility ~~2018 and the requirement of delivery of fiscal year 2018 audited financials~~ without apremium ~~"going concern" qualification~~ or ~~exception.~~penalty ~~Except~~(except with respect to ~~compliance~~any ~~with~~break ~~the~~funding ~~financial~~payments ~~covenant~~which ~~that~~may ~~has~~be ~~been~~payable ~~waived,~~pursuant asto ~~of December 31, 2018, we were in compliance with all covenants of~~ the Credit Agreement). Legacy ~~Depending~~may onbe ~~future~~required 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~~make anmandatory ~~event~~prepayments of ~~default~~the ~~and~~loans ~~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~~Successor ~~under~~Revolving ~~our~~ Credit ~~Agreement~~Facility ~~were~~in toconnection ~~accelerate,~~with ~~subject to~~ certain ~~limitations,~~borrowing ~~the~~base ~~indebtedness~~deficiencies. ~~under our Credit Agreement as a result of a default~~Additionally, ~~such~~if ~~acceleration~~Legacy ~~could~~has ~~cause a cross-default of all of our other~~ outstanding ~~indebtedness~~borrowings, ~~and~~undrawn ~~permit~~letters ~~the holders~~ of ~~such~~credit ~~indebtedness~~and toreimbursement ~~accelerate~~obligations ~~the~~in ~~maturities~~respect of ~~such~~letters ~~indebtedness. While no assurances can be made that, in the event~~ of acredit ~~covenant~~issued ~~breach,~~under ~~such a waiver will be granted, we believe~~ the ~~long-term~~Successor ~~global~~Revolving ~~outlook~~Credit ~~for~~Facility ~~commodity~~in ~~prices~~excess ~~and our efforts to date, which include asset sales completed and anticipated as~~ of the ~~date~~aggregate ofrevolving ~~this filing~~commitments, ~~will~~Legacy ~~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~~required to make ~~distributions~~mandatory ~~to our shareholders and our financial condition and liquidity would be adversely affected~~prepayments. ~~For further information related to our Credit Agreement, please refer to "—Footnote 3—Debt" in the Notes to Condensed Consolidated Financial Statements.~~

~~The~~Legacy’s ~~Credit~~obligations ~~Agreement~~under ~~permits~~the usSuccessor toRevolving ~~issue~~Credit ~~additional~~Facility ~~senior~~are ~~notes~~guaranteed inby ~~order~~all ~~to refinance our currently outstanding Senior Notes as well as to issue an additional $300 million in aggregate principal amount~~ of ~~new~~Legacy’s ~~senior~~material ~~notes,~~domestic insubsidiaries ~~each case, subject to specified conditions in the Credit Agreement~~ (~~including pro forma compliance with~~ the ~~first~~“Guarantors”) ~~lien debt to EBITDA ratio~~ and ~~interest~~secured ~~coverage ratio described below), which include that the borrowing base shall be reduced~~ by ansubstantially ~~amount~~all ~~equal to (i) (A) in the case~~ of ~~new senior notes, 25% of~~ the ~~stated~~assets ~~principal amount~~ of ~~such~~Legacy ~~senior notes~~ and ~~(B) in~~ the ~~case of refinancing our currently outstanding Senior Notes~~Guarantors, ~~100%~~including ~~of the portion of the new debt that exceeds the original principal amount of the senior notes being refinanced or (ii) in the sole discretion of the lenders holding~~ at least ~~66-2/3~~95% of the ~~outstanding~~net ~~aggregate~~present ~~principal~~value ~~amounts~~ of ~~the~~Legacy’s ~~loans~~and ~~or participation interests in letters of credit issued under~~ the ~~Credit~~Guarantors’ ~~Agreement~~proved ~~prior~~oil toand ~~the~~gas ~~issuance of the senior notes or new debt~~properties, ~~an amount less than the amount specified~~ in ~~clause~~each ~~(A).~~case Insubject ~~addition,~~to wecertain ~~must prepay any amount outstanding under the Credit Agreement in excess of the redetermined borrowing base upon such a reduction~~exceptions.

~~Prior~~The toCredit Agreement contains customary representations and warranties and also customary affirmative and negative covenants, in each case for credit facilities of this nature, including restrictions on the ~~Twelfth~~incurrence ~~Amendment~~of indebtedness, liens, fundamental changes, asset sales, investments, dividends, redemptions, repayments of other debt and hedge agreements. Additionally, Legacy ~~could~~is ~~elect~~required ~~that~~as ~~borrowings~~of bethe ~~comprised~~last ~~entirely~~day of ~~alternate~~any ~~base~~fiscal ~~rate~~quarter, commencing with the fiscal quarter ending March 31, 2020, to maintain (~~"ABR"~~a) ~~loans~~a ormaximum ~~Eurodollar~~total ~~loans~~net leverage ratio of 3.50 ~~Interest~~to on1.00 ~~the~~and ~~loans~~(b) isa ~~determined~~minimum ascurrent ~~follows:~~ratio of 1.00 to 1.00.

~~• with respect to ABR loans~~Additionally, the ~~alternate~~Credit ~~base~~Agreement ~~rate~~contains ~~equals~~customary ~~the~~events ~~highest~~ of ~~the~~default ~~prime~~and ~~rate,~~remedies ~~the~~for ~~Federal~~credit ~~funds~~facilities ~~effective~~of ~~rate~~this ~~plus 0.50%~~nature, orincluding ~~the one~~non-~~month London Interbank Offered Rate (“LIBOR”) plus 1.00%~~payment, ~~plus~~breaches anof ~~applicable~~representations ~~margin ranging from~~ and ~~including 1.00% to 2.00% per annum~~warranties, ~~determined~~non-compliance bywith ~~the~~covenants ~~percentage~~or ofother ~~the~~agreements, ~~borrowing base then in effect that is utilized~~bankruptcy, ~~provided~~ERISA, ~~that~~failure ~~if the ratio~~ of ~~our first lien debt as of~~ the ~~last~~loan ~~day~~documents ~~of any fiscal quarter~~ to ~~our~~be ~~EBITDA (as defined~~ in ~~the~~full ~~Credit~~force ~~Agreement)~~and ~~for the four fiscal quarters ending on such day is greater than 3.00 to 1.00~~effect, ~~then~~judgments ~~the~~and ~~applicable~~change ~~margin~~of ~~shall be increased by 0~~control.~~50% during the next succeeding fiscal quarter, or~~

• with respect to any Eurodollar loans, one-, two-, three- or six-month LIBOR plus an applicable margin ranging from and including 2.00% to 3.00% per annum, determined by the percentage of the borrowing base then in effect that is utilized.

Effective March 21, 2019, the Twelfth Amendment provides an increase of 2.25% to the interest rate paid on all ABR and Eurodollar loans.

We pay a commitment fee ranging from and including 0.375% to 0.50% per annum on the average daily amount of the unused amount of the commitments under the Credit Agreement, determined by the percentage of the borrowing base then in effect that is utilized, payable quarterly.

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

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

• incur indebtedness;

• enter into certain leases;

• grant certain liens;

• enter into certain derivatives;

• make certain loans, acquisitions, capital expenditures and investments;

• make distributions other than from available cash;

• merge, consolidate or allow certain material changes in the character of our business;

• repurchase Senior Notes or repay second lien term loans;

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

• maintain a consolidated cash balance in excess of $20 million, or, effective April 1, 2019, $15 million, without prepaying the loans in an amount equal to such excess.

Our 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 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination to not be greater than 4.50 to 1.00 beginning with the fiscal quarter ending 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 2.00 to 1.00;

• 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 1.00 to 1.00, excluding current maturities under the Credit Agreement and non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives;

• 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 our proved developed producing oil and gas properties (“PDP PV-10”), as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be, beginning with the reserve report to be delivered on July 1, 2017 (giving pro forma effect to material acquisitions or dispositions since the date of such reports), (ii) the net mark to market value of our swap agreements and (iii) our cash and cash equivalents to (b) Secured Debt to not be equal to or less than 1.00 to 1.00 .

If an event of default exists under our Credit Agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following would be an event of default:

• failure to pay any principal when due or any reimbursement amount, interest, fees or other amount within certain grace periods;

• a representation or warranty is proven to be incorrect when made;

• failure to perform or otherwise comply with the covenants or conditions contained in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

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• default by us on the payment of any other indebtedness in excess of $15.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

• bankruptcy or insolvency events involving us or any of our subsidiaries;

• the loan documents cease to be in full force and effect;

• our failing to create a valid lien, except in limited circumstances;

• a change in control, which will occur upon (a) Legacy Inc. ceasing to (i) be the beneficial owner of 100% of the equity interests of the General Partner, (ii) control the General Partner or (iii) be the beneficial owner of 100% of the limited partner equity interests in Legacy LP; (b) the General Partner ceases to be the sole general partner of Legacy LP; (c) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or greater than 50% of the properties or assets of Legacy LP and its subsidiaries taken as a whole; (d) the adoption of a plan relating to the liquidation or dissolution of Legacy Inc. or Legacy LP; (e) the consummation of any transaction that results in any person becoming the beneficial owner of more than 50% of the aggregate voting power of Legacy Inc.; or (f) the first day on which a majority of the members of the Board are not continuing directors;

• the entry of, and failure to pay, one or more adverse judgments in excess of $15.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

• specified ERISA events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.0 million in any year;

• the Intercreditor Agreement (as defined below) ceases to be in effect, except to the extent permitted by the terms thereof; and

• if an “Event of Default” occurs under the Term Loan Credit Agreement (as defined below).

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 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.

On March 21, 2019, we entered into the Twelfth Amendment, providing for, among other things, (i) an extension of the maturity of the Credit Agreement to May 31, 2019, (ii) an increase in the applicable interest rate by 2.25%, (iii) the payment of a fee equal to 0.35% of the amount of the current borrowing base under the Credit Agreement, payable on the effective date of the Twelfth Amendment, (iv) the mandatory termination of our derivative contracts three days prior to the maturity of the Credit Agreement, (vi) the reduction in the borrowing base from $575 million to $570 million, effective May 22, 2019, (vii) the reduction in the maximum consolidated cash balance we can maintain without prepaying the loans to $15 million, effective April 1, 2019 and (viii) the payment of a fee equal to 0.15% of the amount of the current borrowing base under the Credit Agreement, payable on the earliest to occur of (x) May 31, 2019 or (y) an acceleration of the outstanding indebtedness under the Credit Agreement. Additionally, the Amendment waives certain deviations from the requirements of the Credit Agreement, including the delivery of fiscal year 2018 audited financial statements with a “going concern” or like qualification or exception and non-compliance with the current ratio covenant for the fourth quarter of 2018.

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As of December 31, 2018, we were in compliance with all financial and other covenants of the Credit Agreement other than the ratio of consolidated current assets to consolidated current liabilities. On March 21, 2019, we received a waiver of the covenant that required us to deliver audited financial statements without a "going concern" or like qualification or exception. 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 or foreclosure on our oil and natural gas properties. 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, including our second lien term loans and Senior Notes, and permit the holders of such indebtedness to accelerate the maturities of such indebtedness.

Our Second Lien Term Loans

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 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. Effective March 21, 2019, the Seventh Amendment (as defined below) to the Term Loan Credit Agreement provides an increase of 2.25% to the interest rate paid on all term loans. 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 the 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 December 31, 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 December 31, 2018) to October 25, 2019 and relaxed the asset coverage ratio to 0.85 to 1.00 until the fiscal quarter ended December 31, 2018. Borrowings of additional amounts under the Term Loan Credit Agreement are subject to the consent of the lenders thereunder. The Third Amendment became effective on January 5, 2018.

We used the initial $60.0 million of gross loan proceeds from our Term Loan Credit Agreement to repay outstanding indebtedness and pay associated transaction expenses. We used subsequent draws to fund the acceleration payment under our JDA and repurchase a portion of our 2021 Senior Notes. The Second Lien Term Loans under the Term Loan Credit Agreement will be issued with an upfront fee of 2% and bear interest at a rate of 12.00% per annum payable quarterly in cash. The Second Lien Term Loans may be used for general corporate purposes and for the repayment of outstanding indebtedness, in each case as may be approved by us and GSO. The Term Loan Credit Agreement contains customary prepayment provisions and make-whole premiums.

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

• not permit, as of the last day of the fiscal quarter, the ratio of the sum of (i) PDP PV-10, (ii) the net mark to market value of our swap agreements and (iii) our cash and cash equivalents to Secured Debt to be less than (i) 0.85 to 1.00 through and including the fiscal quarter ended December 31, 2018 and (ii) 1.00 to 1.00 thereafter;

• not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, our 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;

• We are required to mortgage 95% of the total value of all of its Oil and Gas Properties set forth in the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin; and

• require us to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions.

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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

• 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.

On March 21, 2019, we entered into the Seventh Amendment (the “Seventh Amendment”) to our Term Loan Credit Agreement. The Seventh Amendment waives, through May 31, 2019, the requirement of the Term Loan Credit Agreement that the delivery of fiscal year 2018 audited financial statements not include a “going concern” or like qualification or exception. The Seventh Amendment also provides for, among other things, (i) an increase in the applicable interest rate by 2.25%, (ii) a fee equal to 0.35% of the aggregate amount of term loans currently outstanding under the Term Loan Credit Agreement, to be paid in kind by increasing the aggregate amount of term loans outstanding as of the effective date of the Seventh Amendment and (iii) a fee equal to 0.15% of the aggregate amount of term loans currently outstanding under the Term Loan Credit Agreement, to be paid in kind by increasing the aggregate amount of term loans outstanding on the earliest to occur of (x) May 31, 2019 or (y) an acceleration of the outstanding indebtedness under the Term Loan Credit Agreement.

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 December 31, 2018, we were in compliance with all financial and other covenants of the Term Loan Credit Agreement. On March 21, 2019, we received a waiver of the covenant that required us to deliver audited financial statements without a "going concern" or like qualification or exception.

A customary intercreditor agreement was entered into by Wells Fargo Bank, National Association, as priority lien agent, and Cortland Capital Markets Services LLC, as junior lien agent and acknowledged and accepted by Legacy and the subsidiary guarantors (the "Intercreditor Agreement"). If an event of default exists under the Term Loan Credit Agreement, subject to the terms of the Intercreditor Agreement, the lenders will be able to accelerate the maturity of the Term Loan Credit Agreement and exercise other rights and remedies.

8% Senior Notes Due 2020

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 $300.0 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. We received net proceeds of approximately $286.7 million, after deducting the discount to initial purchasers and offering expense paid by us.

Legacy has the option to redeem the 2020 Senior Notes, in whole or in part, at any time at par with any accrued and unpaid interest, if any, to the date of redemption.

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, Legacy Reserves Marketing 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,

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covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to Note 17 - Subsidiary Guarantors in the Notes to the Consolidated Financial Statements for further details on our 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 certain other conditions; (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 or Term Loan Credit Agreement were to accelerate the indebtedness under the Credit Agreement or Term Loan 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.

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

During the year ended December 31, 2016, we repurchased a face amount of $52.0 million of our 2020 Senior Notes on the open market. We treated these repurchases as an extinguishment of debt. Accordingly, we recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.

On June 1, 2016, we exchanged 2,719,124 units for $15.0 million of face amount of its outstanding 2020 Senior Notes. We treated this exchange as an extinguishment of debt. Accordingly, we recognized a gain for the difference between (1) the face amount of the 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 units issued in the exchange based on the closing price on June 1, 2016. We previously repurchased and exchanged, and have not retired, $67.0 million of our 2020 Senior Notes. Subject to certain restrictions, we retain our voting rights under the indenture governing the 2020 Senior Notes.

On September 20, 2018, Legacy exchanged approximately $21.0 million aggregate principal amount of 2020 Senior Notes for $21.0 million aggregate principal amount of 2023 Convertible Notes. On November 21, 2018, Legacy exchanged $3.1 million aggregate principal amount of 2020 Senior Notes for 1 million shares of our common stock.

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 its 2021 Senior Notes. The 2021 Senior Notes were issued at 98.405% of par. We received approximately $240.7 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses paid 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 its 6.625% 2021 Senior Notes. This issuance of the additional 2021 Senior Notes was at 99.0% of par. We received approximately $291.8 million of net cash proceeds, after deducting the discount to initial purchasers and offering expenses payable by us.

The terms of the 2021 Senior Notes, including 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 par together with any accrued and unpaid interest, if any, to the date of redemption.

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

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under our Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under our Credit Agreement or Term Loan 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.

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

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. On December 17, 2018, Legacy exchanged $5.3 million aggregate principal amount of 2021 Senior Notes for 2 million shares of our common stock.

On December 31, 2017, we entered into an agreement to repurchase a face amount of $187.1 million of our 2021 Senior Notes from certain holders in a single transaction. The transaction was settled on January 5, 2018 and was therefore recognized in 2018. We treated these repurchases 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 year ended December 31, 2016, we repurchased a face amount of $117.3 million of our 2021 Senior Notes on the open market. We treated these repurchases 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. We previously repurchased, and have not retired, $304.4 million of our 2021 Senior Notes. Subject to certain restrictions, we retain our voting rights under the indenture governing the 2021 Senior Notes.

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) $109.0 million aggregate principal amount of 2021 Senior Notes for $109.0 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 $101.0 million, resulting in a debt discount of $29.0 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. 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:

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Early Conversion Date		Early Conversion Payment
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. Additionally, if the lenders under Legacy's Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under the Credit Agreement or Term Loan Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2023 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness.

During the year ended December 31, 2018, certain holders of the 2023 Convertible Notes exercised their option to convert $1.9 million of face amount of 2023 Convertible Notes in exchange for 316,828 shares of our common stock.

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

Off-Balance Sheet Arrangements

None.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2018 is provided in the following table.

	Obligations Due in Period
Contractual Cash Obligations	2019		2020-2021		2022-2023		Thereafter		Total
	(In thousands)
Long-term debt
Revolving credit facility(a)	$	541,000	$	—	$	—	$	—	$	541,000
Interest on revolving credit facility(b)	7,362		—		—		—		7,362
Second Lien Term Loans	338,626		—		—		—		338,626
Interest on Second Lien Term Loans	40,635		—		—		—		40,635
Senior Notes	—		208,885		259,382		—		468,267
Interest on Senior Notes	35,656		48,136		17,735		—		101,527
Office lease	1,376		1,024		—		—		2,400
Total contractual cash obligations	$	964,655	$	258,045	$	277,117	$	—	$	1,499,817

____________________

(a) Represents amounts outstanding under our revolving credit facility as of December 31, 2018.

(b) Based upon our weighted average interest rate of 5.44% under our revolving credit facility as of December 31, 2018.

Critical Accounting Policies and Estimates

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

•it 54requires assumptions to be made that were uncertain at the time the estimate was made, and

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

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~~involve~~Please ~~judgments~~read ~~and~~Note ~~uncertainties~~3 toof ~~such~~the anNotes extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. We based our estimates on historical experience and various other assumptions that are believed to beConsolidated ~~reasonable~~Financial ~~under~~Statements ~~the circumstances, the results of which form the basis~~ for ~~making~~a ~~judgments~~detailed ~~about~~discussion ~~the carrying values~~ of ~~assets~~all ~~and~~significant ~~liabilities~~accounting policies that ~~are~~we ~~not~~employ ~~readily apparent from other sources. Actual results may differ from these estimates~~ and ~~assumptions~~related ~~used in preparation of the financial statements. Changes in these~~ estimates ~~and~~made ~~assumptions~~by ~~could materially affect our financial position, results of operations or cash flows~~management. ~~Management considers an accounting estimate to be critical if:~~

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

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

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Please read Note 1 of the Notes to Consolidated Financial Statements for a detailed discussion of all significant accounting policies that we employ and related estimates made by management.

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

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

Effect if Different Assumptions Used: Units-of-production method to deplete our oil and natural gas properties — A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the year ended December 31, ~~2018~~2019 by approximately 10%.

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

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

Effect if Different Assumptions Used: Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and present value calculation, could differ from actual results, despite our efforts to make an accurate estimate. We engage independent engineering firms to evaluate our properties annually. We consider the remaining estimated useful life from the year-end reserve report prepared by our independent reserve engineers in estimating when abandonment could be expected for each property. On an annual basis we evaluate our latest estimates against actual abandonment costs incurred.

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Nature of Critical Estimate Item: Derivative Instruments and Hedging Activities — We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production and interest expense by reducing our exposure to price fluctuations and interest rate changes. Currently, these transactions are swaps, enhanced swaps and collars whereby we exchange our floating price for our oil and natural gas for a fixed price and floating interest rates for fixed rates with qualified and creditworthy counterparties. The contracts with our counterparties enable us to avoid margin calls for out-of-the-money positions.

We do not specifically designate derivative instruments as cash flow hedges, even though they reduce our exposure to changes in oil and natural gas prices and interest rate changes. Therefore, the mark-to-market of these instruments is recorded in current earnings. We estimate market values utilizing software provided by a third party firm, which specializes in valuing derivatives, and validate these estimates by comparison to counterparty estimates as the basis for these end-of-period mark-to-market adjustments. In order to estimate market values, we use forward commodity price curves, if available, or estimates of forward curves provided by third party pricing experts. For our interest rate swaps, we use a yield curve based on money market rates and interest swap rates to estimate market value. When we record a mark-to-market adjustment resulting in a gain or loss in a current period, this change in fair value represents a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. As shown in the previous tables, we have hedged a portion of our future production through ~~2019~~2023.

Nature of Critical Estimate Item: Oil and Natural Gas Property Impairments — Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties 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 Legacy'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.

As of December 31, ~~2018~~2019, a 10% decrease in net cash flows attributable to our production caused by any one or a combination of variables, including commodity prices, development costs, changes in production levels or other factors, would increase our recognized oil and natural gas property impairments by $213.19 million. We expect the COVID-19 pandemic and the disruption in the oil market to lead to a significant reduction in our reserves. As a result, we expect to recognize impairments to our oil and natural gas properties in 2020.

Recently Issued 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~~The ~~engaged~~new astandard ~~third~~was ~~party~~effective ~~consultant~~for tous ~~assist~~in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with ~~its~~the ~~implementation~~date of ~~ASU~~initial ~~2016-02~~application on January 1, 2019. ~~Leases~~Consequently, ~~will~~upon betransition, ~~classified~~we asrecognized ~~either~~an ~~finance~~ROU orasset ~~operating~~and a lease liability, with ~~that~~the ~~classification~~cumulative-effect ~~affecting~~of ~~the~~adoption ~~pattern~~in retained earnings as of ~~expense~~January ~~recognition~~1, in2019. We further utilized the ~~income~~package ~~statement.~~of practical expedients at transition to not reassess the following:

~~ASU~~•whether ~~2016-02~~any isexpired ~~effective~~or ~~for~~existing fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Legacy will adopt ASU 2016-02 using a modified retrospective approach in the first quarter of 2019 (that is, the period of adoption). At transition, Legacy will utilize the package of practical expedients provided in ASU 2016-02 that allow companies, among other things, to not reassess contracts ~~that~~were ~~commenced prior to adoption. In addition, Legacy expects to utilize the practical expedient to not evaluate land easements that existed~~ or ~~expired~~contained ~~before the adoption of ASU 2016-02 and that were not previously accounted for as~~ leases ~~under currently effective lease accounting guidance.~~ ;

~~Legacy is evaluating~~ •the provisions of ASU 2016-02 and finalizing the impact it will have on its consolidated results of operations, financial position and financial disclosures. Legacy believes that the new guidance will impact its consolidated balance sheet due to the recognition of right-of-use assets and lease ~~liabilities~~classification ~~that~~for ~~are~~any ~~not~~expired ~~recognized~~or ~~under~~existing ~~currently effective guidance (for example, operating~~ leases).; ~~The~~and ~~adjustments that will be required upon implementation of ASU 2016-02, which Legacy anticipates to be less than $15 million, have not been finalized.~~

~~Legacy~~•initial ~~commonly~~direct ~~enters~~costs ~~into lease agreements in support of its operations~~ for ~~assets~~any ~~such~~existing ~~as office space, vehicles, drilling rigs, compressors and other well equipment~~leases. In its efforts to determine the impact of ASU 2016-02, Legacy developed an implementation approach that included 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. Legacy is also implementing a financial lease accounting system solution to facilitate compliance with ASU 2016-02.

In 57addition, we elected the practical expedient to not assess whether existing or expired land easements that were not previously accounted for as leases under superseded guidance are or contain a lease under the new leases guidance.

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We capitalize operating and finance leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

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~~ITEM~~Operating 7Aleases are included in other property and equipment, other current liabilities, and other long-term liabilities in our consolidated balance sheets. ~~QUANTITATIVE~~Operating ~~AND~~lease ~~QUALITATIVE~~ROU ~~DISCLOSURES~~assets ~~ABOUT~~and ~~MARKET~~liabilities ~~RISK~~are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

~~The~~Finance ~~primary~~leases ~~objective~~are ofincluded ~~the~~in ~~following~~other ~~information~~property isand toequipment, ~~provide~~other ~~forward-looking~~current ~~quantitative~~liabilities, and ~~qualitative~~other ~~information~~long-term ~~about~~liabilities in our ~~potential~~consolidated ~~exposure~~balance tosheets. ~~market~~Finance ~~risks.~~lease ~~The~~ROU ~~term~~assets ~~“market~~(that ~~risk”~~is, ~~refers~~amounts tocapitalized in other property and equipment) and liabilities are recognized at the ~~risk~~commencement date of ~~loss~~an ~~arising~~arrangement ~~from~~based ~~adverse~~on ~~changes~~the inpresent ~~oil~~value ~~and~~of ~~natural~~lease ~~gas~~payments ~~prices~~over ~~and~~the ~~interest~~lease ~~rates~~term. The ~~disclosures~~finance ~~are~~lease ~~not~~ROU ~~meant~~asset toalso beincludes ~~precise~~any ~~indicators~~lease ofpayments ~~expected~~made ~~future~~to ~~losses~~the lessor prior to lease commencement, ~~but~~less ~~rather~~any ~~indicators~~lease ofincentives, ~~reasonably~~and ~~possible~~initial ~~losses~~direct costs incurred. ~~This~~We ~~forward~~generally amortize that ROU asset on a straight-~~looking~~line ~~information~~basis, ~~provides~~while ~~indicators~~interest ofon ~~how~~the welease ~~view~~liability ~~and~~is ~~manage~~calculated ~~our~~using ~~ongoing~~the ~~market~~effective ~~risk~~interest ~~exposures~~method. ~~All~~Lease ofexpense recognized under our ~~market~~finance ~~risk~~leases ~~sensitive~~is, ~~instruments~~therefore, ~~were~~comprised ~~entered~~of ~~into~~amortization ~~for~~on ~~purposes~~the ~~other~~finance ~~than~~lease ~~speculative~~ROU ~~trading~~asset and interest on the finance lease liability.

~~Commodity~~Nature ~~Price~~of ~~Risk~~Leases

~~Our~~In ~~major~~support ~~market~~of ~~risk exposure is in the pricing applicable to~~ our ~~oil~~operations, ~~and~~we ~~natural~~lease ~~gas~~certain ~~production.~~corporate ~~Realized~~office ~~pricing~~space, isfield ~~primarily~~offices, ~~driven~~compressors, bydrilling ~~the~~rigs, ~~spot~~other ~~market prices applicable to our natural gas~~ production ~~and the prevailing price for crude oil. Pricing for oil~~equipment, ~~natural~~ ~~gas~~fleet ~~and~~vehicles ~~NGLs has been volatile~~ and ~~unpredictable~~storage ~~for~~space ~~several~~under ~~years,~~cancelable and wenon-cancelable ~~expect this volatility to continue in the future~~contracts. ~~The~~A ~~prices~~more wedetailed ~~receive~~description ~~for production depend on many factors outside~~ of our ~~control,~~material ~~such~~lease astypes ~~the~~is ~~strength~~included ~~of the global economy and the supply of oil outside of the United States~~below.

WeCorporate ~~periodically enter into~~ and ~~anticipate~~Field entering into derivative arrangements 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 activities 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.Offices

AsWe ofenter ~~December 31,~~into ~~2018,~~long-term ~~the~~contracts ~~fair~~to ~~market~~lease ~~value~~corporate ofand ~~Legacy’s~~field ~~commodity~~office ~~derivative~~space ~~positions~~in ~~was~~support ~~a net asset~~ of ~~$67.2~~company ~~million~~operations. AsThese ofcontracts ~~December 31,~~are ~~2017,~~generally ~~the~~structured ~~fair~~with ~~market~~an ~~value~~initial ofnon-cancelable ~~Legacy’s~~term ~~commodity~~of ~~derivative~~two ~~positions~~to ~~was~~ten ayears. ~~net~~To ~~asset~~the ofextent ~~$6.3~~that ~~million.~~our Wecorporate ~~routinely~~and ~~monitor~~field ~~the~~office ~~credit~~contracts ~~default~~include ~~risk~~renewal ofoptions, ~~our~~we ~~counterparties~~evaluate ~~via~~whether ~~risk~~we ~~monitoring~~are ~~services.~~reasonably ~~For~~certain ~~more~~to ~~discussion~~exercise ~~about~~those ~~our~~options ~~derivative~~on ~~transactions~~a ~~and~~contract toby ~~see~~contract abasis ~~table~~based ~~listing~~on ~~the~~expected ~~oil~~future ~~and~~office ~~natural~~space ~~gas~~needs, ~~derivatives~~market ~~for~~rental ~~2019~~rates, ~~through~~drilling ~~December~~plans ~~31,~~and ~~2019,~~other ~~please~~factors. ~~read~~We ~~“Management’s~~have ~~Discussion~~further ~~and~~determined ~~Analysis~~that ofour ~~Financial~~current ~~Condition~~corporate and ~~Results~~field ofoffice ~~Operations—Investing~~leases ~~Activities~~represent operating leases.”

If oil prices decline by $1.00 per Bbl, then the PV-10 of our combined proved reserves as of December 31, 2018 would decline from $1,350.0 million to $1,323.0 million, or 2.00%. If natural gas prices decline by $0.10 per Mcf, then the PV-10 of our combined proved reserves as of December 31, 2018 would decline from $1,350.0 million to $1,325.4 million, or 1.82%. However, larger decreases in oil and natural gas prices may have a disproportionate impact on our standardized measure.Compressors

~~Interest~~We ~~Rate~~rent ~~Risks~~compressors from third parties in order to facilitate the downstream movement of our production to market. Our compressor arrangements are typically structured with a non-cancelable primary term of one to twenty four months and often continue thereafter on a month-to-month basis subject to termination by either party with thirty days’ notice. We have concluded that our compressor rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease without incurring a significant penalty. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.

AtTo ~~December 31, 2018, Legacy had debt outstanding under~~ the ~~Credit~~extent ~~Agreement~~that ofour ~~$541.0~~compressor ~~million,~~rental ~~which~~arrangements ~~incurred~~have ~~interest~~a atprimary ~~floating~~term ~~rates~~of intwelve ~~accordance~~months ~~with~~or ~~its~~less, ~~Credit~~we ~~Agreement.~~have ~~The~~elected ~~average~~to ~~annual~~apply ~~interest~~the ~~rate~~practical ~~incurred~~expedient ~~by Legacy~~ for ~~the~~short-term ~~year ended December 31, 2018 on its floating rate borrowings was 5~~leases.~~14%.~~ AFor 1%those ~~increase~~short-term incompressor ~~LIBOR~~contracts, onwe ~~Legacy’s~~do ~~outstanding~~not ~~floating~~apply ~~rate~~the ~~debt~~lease asrecognition ~~of December 31~~requirements, ~~2018~~and ~~would~~we ~~result~~recognize inlease anpayments ~~estimated~~related ~~$3.1~~to ~~million~~these ~~increase~~arrangements in ~~annual~~profit ~~interest~~or ~~expense~~loss ~~as Legacy has entered into interest rate swaps to mitigate the volatility of interest rates. The interest rate swaps expire~~ on ~~September 1, 2019 and cover $235 million of floating rate debt with~~ a ~~weighted~~straight-~~average~~line ~~fixed~~basis ~~rate~~over ~~of 1.36%. Our Credit Agreement provides for~~ the ~~mandatory~~lease ~~termination of our interest rate swaps three days prior to the maturity date of the Credit Agreement~~term. 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.

~~ITEM~~Drilling ~~8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA~~Rigs

We enter into daywork contracts for drilling rigs with third party service contractors to support the development and exploitation of undeveloped reserves and acreage. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days’ notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling). We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period.

We have further elected to apply the practical expedient for short-term leases to our drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our drilling rig contracts, and we recognize lease payments related to these arrangements in capital expenditures on a straight-line basis over the lease term.

Other Production Equipment

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We rent other production equipment, primarily electric submersible pumps, from third party vendors to be used in our production operations. These arrangements are typically structured with a non-cancelable term of 1 to 3 months and often continue thereafter on a month-to-month basis subject to termination by either party with thirty days’ notice. We have concluded that we are not reasonably certain of executing the month-to-month renewal options beyond a twelve month period based on the historical term for which we have used other production equipment, and, therefore, our other equipment agreements represent operating leases with a lease term up to twelve months.

We have further elected to apply the practical expedient for short-term leases to our other production equipment contracts. Accordingly, we do not apply the lease recognition requirements to these contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Fleet Vehicles

We execute fleet vehicle leases with a third party vendor in support of our day-to-day drilling and production operations. Our vehicle leases are typically structured with a term of 18 to 48 months. We have concluded that the majority of our vehicle leases represent operating leases.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements and supplementary financial data are included in this annual report on Form 10-K beginning on page F-3.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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 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 team, 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 December 31, ~~2018~~2019. 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.

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). During the third quarter of 2018, we added internal control processes over financial reporting as a result of our Corporate Reorganization and resulting federal income tax requirements. There have been no other changes in our internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.39

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Management’s Annual Report on Internal Control over Financial Reporting

Legacy’s management is responsible for establishing and maintaining adequate control over financial reporting. Our internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, and effected by the board of directors, management and other personnel, 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. Our internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our board of directors; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. 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 and procedures may deteriorate.

As of December 31, ~~2018~~2019, management assessed the effectiveness of Legacy’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework (2013),” issued by the Committee of Sponsoring Organizations of the Treadway Commission. This assessment included design effectiveness and operating effectiveness of internal controls over financial reporting as well as the safeguarding of assets. Based on that assessment, management determined that Legacy maintained effective internal control over financial reporting as of December 31, ~~2018~~2019, based on those criteria.

BDO USA, LLP, the independent registered public accounting firm who also audited our Consolidated Financial Statements included in this Annual Report on Form 10-K, has issued an attestation report on our internal control over financial reporting as of December 31, 2018, which is set forth below under “Attestation Report.”40

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~~Report~~ITEM of9B.OTHER ~~Independent Registered Public Accounting Firm~~INFORMATION

~~Stockholders~~Termination ~~and Board~~ of ~~Directors~~Registration

~~Legacy~~On ~~Reserves~~January ~~Inc~~2, 2020, we provided certification and notice of termination of the registration of our common stock under Section 12(g) of the Exchange Act. There were approximately 151 holders of record as of the certification or notice date.

~~Midland, Texas~~41

Opinion on Internal Control over Financial Reporting

We have audited Legacy Reserves Inc.’s (the “Company’s”) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, stockholders’/unitholders’ deficit, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes and our report dated March 22, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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.

/s/ BDO USA, LLP

Houston, Texas

March 22, 2019

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ITEM 9B. OTHER INFORMATION

Amendments to Credit Agreement and Term Loan Credit Agreement

On March 21, 2019, we entered into the Twelfth Amendment (the “Twelfth Amendment”) to our Credit Agreement. The Twelfth Amendment provides for, among other things, (i) an extension of the maturity of the Credit Agreement to May 31, 2019, (ii) an increase in the applicable interest rate by 2.25%, (iii) the payment of a fee equal to 0.35% of the amount of the current borrowing base under the Credit Agreement, payable on the effective date of the Twelfth Amendment, (iv) the mandatory termination of our derivative contracts three days prior to the maturity of the Credit Agreement, (vi) the reduction in the borrowing base from $575 million to $570 million, effective May 22, 2019, (vii) the reduction in the maximum consolidated cash balance we can maintain without prepaying the loans to $15 million, effective April 1, 2019 and (viii) the payment of a fee equal to 0.15% of the amount of the current borrowing base under the Credit Agreement, payable on the earliest to occur of (x) May 31, 2019 or (y) an acceleration of the outstanding indebtedness under the Credit Agreement. Additionally, the Amendment waives certain deviations from the requirements of the Credit Agreement, including the delivery of fiscal year 2018 audited financial statements with a “going concern” or like qualification or exception and non-compliance with the current ratio covenant for the fourth quarter of 2018.

The foregoing description of the Twelfth Amendment does not purport to be complete and is qualified in its entirety by reference to the Twelfth Amendment, which is filed as Exhibit 10.53 to this Annual Report on Form 10-K and incorporated by reference herein.

The foregoing description of the Seventh Amendment does not purport to be complete and is qualified in its entirety by reference to the Seventh Amendment, which is filed as Exhibit 10.54 to this Annual Report on Form 10-K and incorporated by reference herein.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

WeBoard ~~intend to include the information required by this Item 10 in Legacy’s definitive proxy statement for its 2019 annual meeting~~ of ~~stockholders, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2018.~~Directors

~~Our~~Set ~~Code~~forth ofbelow ~~Ethics~~is ~~covers~~biographical ainformation ~~wide~~regarding ~~range~~the ofcurrent ~~business~~members ~~practices~~of ~~and procedures and furthers~~ our ~~fundamental~~Board ~~principles~~ of ~~integrity,~~Directors ~~honesty~~(the ~~and~~“Board” ~~ethical~~or ~~conduct.~~the ~~The~~“Board ~~Code~~ of ~~Ethics~~Directors”) ~~was~~and ~~approved~~information byregarding ~~our~~the ~~board~~specific ~~of directors. Our Code of Ethics~~experience, ~~which is applicable to all directors~~qualifications, ~~officers~~attributes and ~~employees~~skills ofthat ~~Legacy,~~qualify isthen ~~posted at http://www.legacyreserves.com/governance. We also intend~~ to ~~post~~serve ~~any changes to or waivers of our Code of Business Ethics for our executive officers~~ on ~~our~~the ~~website~~Board.

ITEM 11. EXECUTIVE COMPENSATION


Name	Principal Occupation	Age	Director Since
Richard Betz	Richard F. Betz was appointed to the Board in December 2019 and is currently the Chief Executive Officer of Lithos Resources since February 2020. Prior to Mr. Betz’ appointment to the Board, he served as Chief Executive Officer and as a director of Resolute Energy Corporation (“Resolute”) from January 2017 until March 2019. From March 2012 until his appointment as Chief Executive Officer of Resolute, Mr. Betz served as Executive Vice President and Chief Operating Officer of Resolute. From September 2009 to March 2012, Mr. Betz served as Senior Vice President, Strategy and Planning of Resolute and was Vice President, Business Development from July 2009 to September 2009. Prior to that, Mr. Betz served as Vice President, Business Development of a predecessor of Resolute since its founding in 2004. Prior to 2004, Mr. Betz worked as a Managing Director of Chase Securities and successor companies in the oil and gas investment banking coverage group with primary responsibility for mid-cap exploration and production companies as well as leveraged finance and private equity. Mr. Betz received an MBA from the Wharton School of the University of Pennsylvania and an undergraduate degree from Villanova University.	58	December 2019

	The Board determined that Mr. Betz should be nominated to our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas industry, including 15 years of service in executive positions.

David Coppé	David Coppé was appointed to the Board in December 2019. Prior to his current role, Mr. Coppé served as Director and Head of Energy, Private Equity of Caisse de Depot et Placement du Québec from March 2017 until March 2019. From November 2012 until his appointment as Director and Head of Energy, Private Equity, Mr. Coppé served as President and Chief Executive Officer of Probe Holdings, Inc. Mr. Coppé served on the board of directors of Logan International, Inc. from 2006 until 2016, and also served on a number of other private company boards. He started his career as a field engineer for Schlumberger and also worked for Goldman Sachs and Cadent Energy Partners, a private equity firm. He currently serves on the board of RDV Resources (f/k/a Sheridan I). Mr. Coppé received an MBA from Massachusetts Institute of Technology and a Mechanical Engineering degree from the University of Louvain, Belgium.	48	December 2019

	The Board determined that Mr. Coppé is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas industry that was attained through his 22 years of service in the oil and gas industry, including 14 years serving in directorship or executive positions.

We intend to include information with respect to executive compensation in Legacy’s definitive proxy statement for its 2019 annual meeting of stockholders, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2018.42

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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We intend to include information regarding Legacy’s securities authorized for issuance under equity compensation plans and ownership of Legacy’s outstanding securities in Legacy’s definitive proxy statement for its 2019 annual meeting of stockholders, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2018.


Gary Gould	Gary Gould was appointed to the Board in December 2019 and is currently a Senior Advisor to GSO Capital Partners LP ("GSO"). Prior to his appointment, Mr. Gould served as the Chief Operating Officer (COO) of EQT Corporation (EQT) and as President of EQT Production Company from April to August, 2019. From November 2015 until his announcement as COO at EQT in March 2019, Mr. Gould served as Senior Vice President of Production and Resource Development for Continental Resources, Inc. (“Continental”). From April 2015 to November 2015, Mr. Gould served as Senior Vice President of Operations for Continental and, prior to that, as Senior Vice President of Operations and Resource Development of Continental from May 2014 to April 2015. In prior roles, Mr. Gould served as Vice President of Resource Development at Continental Resources and as Vice President/Director of Reservoir Technology for Chesapeake Energy. Mr. Gould earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Kansas.	55	December 2019

	The Board determined that Mr. Gould is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include expertise in the oil and gas industry that was attained through his 32 years of service in engineering and executive positions with various oil and gas companies.

Robert Horn	Robert Horn was appointed to the Board in December 2019 and is currently a Senior Managing Director of Blackstone and is Co-Head of Energy Investing for GSO Capital Partners. Mr. Horn sits on the investment committees for GSO’s energy funds, performing credit funds, distressed funds and structured credit funds. Prior to joining GSO, Mr. Horn worked in Credit Suisse’s Global Energy Group, where he advised on high yield financings and merger and acquisition assignments for companies in the power and utilities sector. Mr. Horn graduated with honors from McGill University.	38	December 2019

	The Board determined that Mr. Horn is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas industry, including expertise in managing oil and gas investments and for his prior directorship experience serving various oil and gas companies.

~~ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE~~43

WeTable ~~intend to include the information regarding related party transactions in Legacy’s definitive proxy statement for its 2019 annual meeting~~ of ~~stockholders, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2018.~~Contents

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES


Douglas W. York	Douglas W. York was appointed to the Board in April 2020. Mr. York previously served on our Board from October 2018 to December 2019. Mr. York is a Co-Founder and Managing Director of Sequel Energy Group LLC. Since 2016, Mr. York has also served as Managing Member for Halflight Land & Minerals LLC. Previously, Mr. York served as Co-Founder and Managing Member of privately held Sequel Energy, LLC during September 2006 through July 2014. Sequel Energy, LLC was formed in September 2006 and was focused on the acquisition and development of operated and non-operated interests in Louisiana, Oklahoma and North Dakota prior to divesting its assets in late 2013 and early 2014. Before co-founding Sequel, Mr. York spent ten years during August 1996 through March 2006 with St. Mary Land and Exploration Company (NYSE - SM), a publicly-traded company with operations in multiple U.S. basins, where he served as VP, Engineering and Acquisitions and later as EVP and COO. Mr. York served as Regional Engineer for the Northern Business Unit of the Rockies Region for three years during December 1993 through July 1996 with Meridian Oil Company. Mr. York began his career with ARCO Oil and Gas Company from November 1993 through January 1984, where his roles included Drilling Engineering, Reservoir Engineering and Planning. Mr. York holds a B.S. Degree in Petroleum Engineering from the University of Tulsa. He has served on the Boards of the Independent Petroleum Association of the Mountain States, Montana Petroleum Association, Petroleum Engineering Advisory Board at the University of Tulsa, KLR Energy Acquisition Corp. and the Development Board of Colorado UpLift.	59	April 2020

	The Board determined that Mr. York should be nominated to our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: managing a public oil and gas company, experience in the valuation of oil and gas properties and financial expertise.

Kyle M. Hammond	Kyle M. Hammond was promoted to President of Legacy in March 2019 and continues to serve as its Chief Operating Officer. Mr. Hammond was appointed to the Board in December 2019. Prior to Mr. Hammond’s promotion, he served as Executive Vice President and Chief Operating Officer of Legacy since March 2015. From its formation in August 2011 to his appointment as Executive Vice President and Chief Operating Officer of Legacy, Mr. Hammond served as President and Chief Executive Officer and as a director of FireWheel Energy LLC, a private equity backed oil and gas development company headquartered in Midland, Texas. Prior to forming FireWheel Energy LLC, Mr. Hammond served as VP of Operations for the Permian Division of XTO Energy/Exxon from 2003 to August 2011. Mr. Hammond currently serves on the board of directors of Abilene Christian University, Blanks Ranch Properties, LLC and Midland Christian School. Mr. Hammond earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.	59	December 2019

	The Board determined that Mr. Hammond is qualified to serve on our Board of Directors due to his service as our Chief Operating Officer, and his pertinent experience, qualifications, attributes and skills, which include: the knowledge and experience attained through 17 years of service in the oil and gas industry, with a focus in the Permian Basin, and his familiarity with our operations.

We intend to include information regarding principal accountant fees and services in Legacy’s definitive proxy statement for its 2019 annual meeting of stockholders under the heading “Independent Registered Public Accounting Firm,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2018.44

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James Daniel Westcott	James Daniel Westcott was promoted to Chief Executive Officer of Legacy in March 2019 and was appointed to the Board in March 2019. Prior to Mr. Westcott’s promotion, he served as President of Legacy since March 2018 and as Chief Financial Officer since September 2012. From July 2006 to his appointment at Legacy, Mr. Westcott served as a Principal at GSO, a division of The Blackstone Group L.P., where he was involved in the sourcing, structuring, evaluation and management of debt and equity investments for public and private companies in the energy and power industries. From August 2004 to July 2006, Mr. Westcott worked as an investment banker at J.P. Morgan’s Global Energy Group. Mr. Westcott is currently a Director of Peace Gospel International, a nonprofit organization with charitable programs in Asia and Africa. Mr. Westcott received a Bachelor of Arts degree in Science Technology & Society and a Master of Science degree in Management Science, both from Stanford University.	39	March 2019

	The Board determined that Mr. Westcott is qualified to serve on our Board of Directors due to his service as our Chief Executive Officer and prior service as our Chief Financial Officer, and his pertinent experience, qualifications, attributes and skills, which include: sourcing and structuring investments in oil and gas companies and familiarity with our operations.

Executive Officers

The following table shows information for our executive officers.

Name

Age

Position

James Daniel Westcott

Chief Executive Officer

Kyle M. Hammond

President and Chief Operating Officer

Robert L. Norris

Chief Financial Officer

Albert E. Ferrara, III

General Counsel and Corporate Secretary

Cory J. Elliott

Chief Information Officer

Micah C. Foster

Chief Accounting Officer and Controller

Our executive officers serve at the discretion of the Board of Directors. None of our executive officers and directors are related.

James Daniel Westcott was promoted to Chief Executive Officer of Legacy in March 2019 and was appointed to the Board in March 2019. Prior to Mr. Westcott’s promotion, he served as President of Legacy since March 2018 and as Chief Financial Officer since September 2012. From July 2006 to his appointment at Legacy, Mr. Westcott served as a Principal at GSO, a division of The Blackstone Group L.P., where he was involved in the sourcing, structuring, evaluation and management of debt and equity investments for public and private companies in the energy and power industries. From August 2004 to July 2006, Mr. Westcott worked as an investment banker at J.P. Morgan’s Global Energy Group. Mr. Westcott is currently a Director of Peace Gospel International, a nonprofit organization with charitable programs in Asia and Africa. Mr. Westcott received a Bachelor of Arts degree in Science Technology & Society and a Master of Science degree in Management Science, both from Stanford University.

Kyle M. Hammond was promoted to President in March 2019 and has served as Chief Operating Officer of Legacy since March 2015. From its formation in August 2011 to his appointment as Executive Vice President and Chief Operating Officer of Legacy, Mr. Hammond served as President and Chief Executive Officer and a director of FireWheel Energy LLC (“FireWheel”), a private equity backed oil and gas development company headquartered in Midland, Texas. Prior to forming FireWheel, Mr. Hammond served as VP of Operations for the Permian Division of XTO Energy/Exxon from 2003 to August 2011. Mr. Hammond earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. Mr. Hammond currently serves on the board of directors of Abilene Christian University and Midland Christian School.

Robert L. Norris was appointed Chief Financial Officer of Legacy in February 2019. From April 2015 to his appointment at Legacy, Mr. Norris served as a Principal at The Catalyst Group, a private equity firm focused on lower middle market investments, where he was involved in the sourcing, structuring, evaluation, and execution of equity investments and the

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management of the firm’s portfolio companies. From June 2014 to March 2015, Mr. Norris led the corporate development and strategy efforts at Civeo, a workforce accommodations provider that was spun out from Oil States International. From August 2003 to June 2014, Mr. Norris served in various capacities at Oil States International, a diversified oilfield service company, ultimately leading their corporate development and strategy groups. Mr. Norris received a Bachelor of Arts degree in Economics and an MBA both from the University of Texas, Austin.

Albert E. Ferrara, III was appointed General Counsel and Corporate Secretary of Legacy in January 2019. Mr. Ferrara joined Legacy in February 2014 as Associate General Counsel and was promoted to Deputy General Counsel in October 2016. From August 2013 through February 2014, Mr. Ferrara worked in the land department of Concho Resources, Inc. From July 2007 through July 2010, prior to attending law school, Mr. Ferrara was an investment banker in the Global Energy Group of Morgan Stanley & Co., Inc. in Houston, Texas focusing on providing securities underwriting and mergers and acquisitions advice to companies in the oil and natural gas industry. Mr. Ferrara graduated with a Bachelor of Arts in Economics from Yale University and a Juris Doctor with Honors from the University of Oklahoma College of Law.

Cory J. Elliott was appointed Chief Information Officer of Legacy in January 2019. Previously, Mr. Elliott served as Vice President of Information Technology from May 2018 until his appointment as Chief Information Officer. Before that, Mr. Elliott served as IT Director from July 2013 until May of 2018. From January 2010 to July 2013, Mr. Elliott served as IT Director for Compressor Systems, Inc. From October 2008 to December 2010, Mr. Elliott served as Infrastructure Director for Key Energy Services. From March 2005 to August 2008, Mr. Elliott served as IT Manager for Basic Energy Services. Mr. Elliott began his career with Pure Resources, a Division of Unocal, in August of 2000 until March 2005. Mr. Elliott has a Computer Science degree from Texas State Technical College. Mr. Elliott has 19 years of technology and oil and gas industry experience.

Micah C. Foster is Chief Accounting Officer and Controller of Legacy. Mr. Foster was appointed Chief Accounting Officer in April 2012. Mr. Foster joined Legacy’s predecessor in January 2006 and served as Financial Accountant from March 2006 to July 2008, Financial Reporting Manager from July 2008 to July 2010, and Assistant Controller from July 2010 to October 2011. In October 2011, Mr. Foster was promoted to Controller. Prior to joining Legacy, Mr. Foster worked as staff auditor and then senior auditor at Ernst & Young, LLP from July 2003 to January 2006. Mr. Foster holds a BBA in Accounting and Finance from Abilene Christian University and is a Certified Public Accountant.

Code of Ethics

The Board has adopted a Code of Ethics applicable to all employees, officers and directors. The Code of Ethics is available on our website at www.legacyreserves.com and in print to any stockholder who requests it. Amendments to or waivers from the Code of Ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the Code of Ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.

Section 16(a) Beneficial Ownership Reporting Compliance

Under Section 16(a) of the Exchange Act, directors, certain officers, and beneficial owners of 10% or more of our common stock (“Reporting Persons”) were required from time to time to file with the SEC and NASDAQ reports of ownership and changes of ownership. Reporting Persons are required to furnish Legacy with copies of all Section 16(a) reports they file. Based solely on its review of forms and written representations received from Reporting Persons with respect to the fiscal year ended December 31, 2019, Legacy believes that all filing requirements applicable to its directors and officers had been met.

ITEM 11.EXECUTIVE COMPENSATION

2019 Summary Compensation Table

The following table sets forth the aggregate compensation awarded to, earned by or paid to our Named Executive Officers ("NEO") for the fiscal year ended December 31, 2019, and 2018.

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Name and Principal Position	Year	Salary ($)(a)		Bonus ($)		Unit Awards ($)(b)		Stock Awards ($)(c)(d)		Non-Equity Incentive Plan Compensation ($)(e)		All Other Compensation ($)			Total ($)
Paul T. Horne	2019	$	112,500	$	—	$	—	$	—	$	—	$	15,458	(f)	$	127,958
Chairman of the Board and	2018	$	666,667	$	604,061	$	6,423,085	$	4,030,984	$	—	$	838,621	(f)	$	12,563,418
Chief Executive Officer (1)

James Daniel Westcott	2019	$	645,833	$	1,350,000	$	—	$	—	$	2,552,284	$	19,000	(g)	$	4,567,117
Chief Executive Officer(2)	2018	$	491,667	$	366,098	$	3,468,466	$	11,197,183	$	—	$	481,971	(g)	$	16,005,385

Kyle M. Hammond	2019	$	491,667	$	1,000,000	$	—	$	—	$	1,158,743	$	21,600	(h)	$	2,672,010
President and Chief	2018	$	445,833	$	247,878	$	3,275,773	$	6,718,312	$	—	$	689,907	(h)	$	11,377,703
Operating Officer(3)

Robert L. Norris	2019	$	345,205	$	600,000	$	—	$	—	$	634,260	$	15,833	(i)	$	1,595,298
Chief Financial Officer (4)	2018	$	—	$	—	$	—	$	—	$	—	$	—		$	—

1.Effective March 1, 2019, Mr. Horne retired from his role as Chief Executive Officer of the Company.

2.Effective March 1, 2019, in connection with Mr. Horne’s retirement as Chief Executive Officer of the Company, Mr. Westcott was promoted to Chief Executive Officer of the Company.

3.Effective March 1, 2019, in connection with Mr. Westcott’s promotion to Chief Executive Officer of the Company, Mr. Hammond was promoted to President and Chief Operating Officer of the Company.

4.Effective February 19, 2019, Mr. Norris was appointed as Chief Financial Officer of the Company.

(a) For Messrs. Westcott, and Hammond annual salary increases (where applicable) for 2019 and 2018 became effective on March 1, 2019 and March 1, 2018, respectively.

(b) Phantom units were granted to officers on February 16, 2018. The amount shown reflects the grant date fair value of these awards based upon the Financial Accounting Standards Board’s authoritative guidance relating to stock compensation. The assumptions used in calculating these amounts are discussed further in Note 16 – “Share-Based Compensation” to the financial statements in the Partnership’s annual report on Form 10-K filed with the SEC on February 23, 2018. Assuming all performance and service conditions are met at the maximum possible level, the grant date fair value of the unit awards granted in 2018 pursuant to the compensation policy for each NEO is as follows: Mr. Horne: $6,936,093; Mr. Westcott: $3,745,490; and Mr. Hammond: $3,537,407. In connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. Under the individual phantom unit award agreements, such vested phantom units (and any related distribution equivalent rights) were generally to be settled in cash. As described above, pursuant to the terms of the Phantom Unit Settlement Agreement, each NEO that was to receive a cash amount in settlement of their phantom units became eligible instead to receive a portion of that settlement amount and forfeited, without consideration, his right to receive any remaining portion of the settlement amount. The aggregate settlement amount to be awarded to all executive officers, including each of NEOs, was $13.8 million, and the executive officers, including each of NEOs, agreed to forfeit an aggregate of $7.8 million pursuant to the Phantom Unit Settlement Agreements, each in proportion to each executive officer’s settlement amount.

(c) Represents initial grants of restricted stock units ("RSU") in the Company to our NEOs after the consummation of the Corporate Reorganization under our 2018 Incentive Plan. The following vesting schedule applies to the restricted stock units awarded in 2018: (i) 25% on March 1, 2020; (ii) 25% on March 1, 2021, and (ii) the remaining 50% on March 1, 2022, calculated in accordance with the Financial Accounting Standards Board’s Accounting Standards Codification Topic 718, Compensation — Stock Compensation. The grant date fair value of RSUs is determined using the fair value of our common stock on the date of grant. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan with no recovery.

(d) The market value of the restricted stock units, based on the closing price of the Partnership’s units on March 23, 2018, the approval date, for each NEO is as follows: Mr. Horne: $2,700,000; Mr. Westcott: $7,500,000; and Mr. Hammond: $4,500,000. The information in this footnote is provided as supplemental to, and not as a substitute for, the information

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presented in accordance with SEC rules in the 2019 Summary Compensation Table. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan with no recovery.

(e) For 2019, reflects the aggregate sum of incentive cash compensation paid to each NEO under the Company’s 2019

Key Employee Incentive Plan.

(f) Reflects for 2019: $15,458 of 401(k) employer matching contributions. Reflects for 2018: $22,000 of 401(k) employer matching contributions and $51,977 of unit distributions received by Mr. Horne on his phantom units. As described above, in connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. For phantom units, amounts, if any, for 2018 include the cash settlement amount provided for in Mr. Horne’s Phantom Unit Settlement Agreement, less any amount already accounted for in the “Unit Awards” column.

(g) Reflects for 2019: $19,000 of 401(k) employer matching contributions. Reflects for 2018: $18,500 of 401(k) employer matching contributions and $47,874 of unit distributions received by Mr. Westcott on his phantom units. As described above, in connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. For phantom units, amounts, if any, for 2018 include the cash settlement amount provided for in Mr. Westcott’s Phantom Unit Settlement Agreement, less any amount already accounted for in the “Unit Awards” column.

(h) Reflects for 2019: $21,600 of 401(k) employers matching contributions. Reflects for 2018: $22,000 of 401(k) employer matching contributions. As described above, in connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. For phantom units, amounts, if any, for 2018 include the cash settlement amount provided for in Mr. Hammond’s Phantom Unit Settlement Agreement, less any amount already accounted for in the “Unit Awards” column.

(i) Reflects for 2019: $15,833 of 401(k) employers matching contribution for Mr. Norris.

Outstanding Equity Awards at 2019 Fiscal Year-End

In connection with the closing of the Chapter 11 Cases, all of our outstanding equity awards were terminated.

Employment Agreements

Through our wholly-owned subsidiary Legacy Reserves Services LLC (formerly Legacy Reserves Services, Inc.), at the beginning of 2018, we had employment agreements with Messrs. Horne, Hammond and Westcott. Mr. Norris entered into an employment agreement with Legacy Reserves Services LLC in February 2019 in connection with his appointment as Chief Financial Officer. Each of the NEOs entered into amended and restated employment agreements, effective December 11, 2019, in connection with Legacy's emergence from the Chapter 11 Cases.

Key Employee Incentive Plan

On May 17, 2019, the Board of Directors, upon the recommendation of the Compensation Committee of the Board, approved and adopted the Legacy Reserves 2019 Key Employee Incentive Plan (the “Incentive Plan”). Under the Incentive Plan, each participant was eligible to earn a performance bonus in cash following the end of each fiscal quarter in 2019 (the “Quarterly Bonuses”), depending upon the extent to which certain specified performance goals were achieved for each such quarter. In addition to being measured on a quarterly basis, the performance goals were measured cumulatively from January 1, 2019 through the end of the fourth quarter of 2019 and each participant’s Quarterly Bonus for the fourth quarter of 2019 could have been adjusted up or down (but to not less than zero) by an amount based on the results of the cumulative performance goals minus the Quarterly Bonuses actually paid for each quarter. In order to earn a Quarterly Bonus for any quarter, a participant must generally have remained employed by the Company through the end of the applicable quarter.

Retention Agreements

Each of our NEOs, other than Mr. Horne, entered into a Retention Agreement with the Company in May 2019. Each Retention Agreement provided that the Company would advance to each officer a cash retention payment as soon as practicable after such officer has executed and returned a copy of his Retention Agreement to the Company.

Each officer will earn and become fully vested in the retention payment if, and only if: (a) such officer remains employed through the Vesting Date (as defined in the Retention Agreements) or (b) such officer’s employment is terminated prior to the Vesting Date due to death or disability or by the Company without Cause (as defined in the each officer’s employment agreement).

In the event that an officer’s employment terminates prior to the Vesting Date for any reason other than a termination by the Company without Cause or due to death or disability, such officer will be required to repay to the Company the (a) net

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(after-tax) amount of the retention payment, if the repayment occurs in 2019 or (b) entire gross amount of the retention payment, if the repayment occurs in 2020 or thereafter.

Director Compensation

Under the Company’s director compensation policy that was in effect until May 2019, in addition to an annual grant of shares of common stock of the Company valued at $125,000, each non-employee director was entitled to receive an annual retainer, which was paid quarterly, and $1,000 for each Board of Directors and committee meeting lasting less than one hour and $1,500 for each Board of Directors and committee meeting lasting one hour or more for each meeting in excess of the four quarterly Board meetings scheduled each year.

Under the Company's director compensation policy in effect after May 2019, each non-employee director was entitled to receive an annual retainer, which was paid quarterly, and $1,000 for each Board of Directors and committee meeting lasting less than one hour and $1,500 for each Board of Directors and committee meeting lasting one hour or more for each meeting in excess of the four quarterly Board meetings scheduled each year.

Each non-employee director was also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees. Each director will be indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

The following table sets forth the aggregate compensation awarded to, earned by or paid by the Company to our non-employee directors during 2019. No non-employee directors appointed to the Board of Directors in connection with the closing of the Chapter 11 Cases received any compensation during 2019.

Director Compensation for the 2019 Fiscal Year


										Change in Pension Value and Nonqualified Deferred Compensation Earnings
	Year	Fees Earned ($)(a)		Share and Unit Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)							All Other Compensation ($)		Total ($)


Paul T. Horne	2019	$	265,750	$	125,000	$	—	$	—	$	—		$	—	$	390,750
James Daniel Westcott	2019	$	—	$	—	$	—	$	—	$	—	<

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