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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________

 Form 10-K

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2019
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from               to

Commission file number 1-38668

__________________

 Legacy Reserves Inc.

(Exact name of registrant as specified in its charter)

__________________

Delaware	82-4919553
(State or other jurisdiction of	(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:

None.

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 ☐     No☑

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  ☑     No  ☐

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  ☐     No  ☑

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 ☑     No  ☐

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

Large accelerated filer ☐	Accelerated filer  ☐
Non-accelerated filer ☑	Smaller reporting company  ☑
	Emerging growth company  ☐

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.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐ No ☑

The aggregate market value of voting and non-voting stock held by non-affiliates of the registrant as of June 28, 2019 was approximately $2.1 million based upon the closing price as reported on the OTCPK of the registrant's common stock on that date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐

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

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LEGACY RESERVES INC.

Table of Contents

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

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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 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.

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.

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 amount of oil and natural gas we produce;

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

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

•our ability to replace reserves;

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

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

•the level of our capital expenditures;

•our future operating results;

•national and global health crises, including outbreaks, epidemics, and pandemics such as coronavirus ("COVID-19"); 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. 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 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, 2019 are as follows:

•we had proved reserves of approximately 127.2 MMBoe, of which 61% were natural gas, 39% were oil and natural gas liquids (“NGLs”) and 96% were classified as proved developed producing; and

•our proved reserves to production ratio was approximately 8.3 years based on the annualized production volumes for the three months ended December 31, 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 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 interests remained outstanding.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On June 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”). On June 19, 2019, the Bankruptcy Court granted a motion seeking joint administration of the Chapter 11 Cases under the caption In re Legacy Reserves Inc., et al. On August 2, 2019, the Debtors filed the Joint Chapter 11 Plan of Reorganization for Legacy Reserves Inc. and its Debtor Affiliates (as amended, modified or supplemented from time to time, the “Plan”) with the Bankruptcy Court.

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On November 15, 2019, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Plan, and on December 11, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.

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

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	%

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, 2018 to December 31, 2019:

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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 PUD locations were removed from our PUD inventory because of non-consenting working interest owners. Due to their ownership level, their consent is required in order to develop the 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.

As of December 31, 2019, we identified 11 gross (9.5 net) recompletion and fracture stimulation projects.

Excluding any potential acquisitions, we expect to make capital expenditures of approximately $55 million during the year ending December 31, 2020.

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 was formed by certain of TPG Sixth Street Partners' investment funds. Our capital resources and liquidity have benefited 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").

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Oil and Natural Gas Derivative Activities

In order to mitigate price risk for a portion of our oil and natural gas production, we enter into oil and natural gas derivative contracts from time to time. At December 31, 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 for NYMEX WTI oil; fixed price swaps for NYMEX Henry Hub; fixed price swaps for the Midland-to-Cushing oil differentials; fixed price swaps for WAHA basis differentials; and fixed price swaps for CIG-Rockies basis differentials.

Marketing and Major Purchasers

For the period December 11, 2019 to December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the years ended December 31, 2018, and 2017 (Predecessor), Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to the purchasers as detailed in the table below.

	Successor	Predecessor
	Period from	Period from
	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.

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;

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•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;

•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.

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 Federal Clean Air Act and associated state laws and regulations. In addition, more stringent federal, state and local regulations 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. In September 2019, the EPA issued proposed amendments to the 2016 rule that would rescind methane emissions standards for the oil and gas industry.

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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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.

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,

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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, 2019, we had 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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ITEM 1A.RISK FACTORS

None.

ITEM 1B.UNRESOLVED STAFF COMMENTS

     None.

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ITEM 2.PROPERTIES

As 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 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, 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	%

__________________

(a)Reserves as of December 31, 2019 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, 2019.

	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

(c)As the Spraberry Field contains 24,212 MBoe, or 19.0% of total proved reserves of 127,223 MBoe, the following table presents the production, by product, for the Spraberry Field.

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	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

(d)As East Texas contains 36,713 MBoe, or 28.9% of total proved reserves of 127,223 MBoe, the following table presents the production, by product, for East Texas.

	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 the Piceance Basin contains 30,819 MBoe, or 24.2% of total proved reserves of 127,223 MBoe, the following table presents the production, by product, for the Piceance Basin.

	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 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, 2019, these four areas accounted for approximately 70% of our PV-10 and 78% of our total estimated proved reserves.

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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 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 wells were drilled on our properties 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 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 54 wells (54 producing, 0 injecting) in the Lea field with working interests ranging from 28.0% to 93.2% and net revenue 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 wells were drilled on our properties in the Lea field in 2019. Our engineers have identified 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.

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 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.

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. As of December 31, 2019, our properties in the Piceance Basin contained 30,819 MBoe (18% liquids) of net proved reserves with a PV-10 of $50.2 million. The average net daily production from this field was 8,122 Boe/d for the fourth quarter of 2019. The estimated reserve life (R/P) for this field is 10.4 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, 2019, 2018 and 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, 2019, 2018 and 2017. As a result of this methodology, we used an average WTI posted price of $55.69 per Bbl for oil and an average Platts' Henry Hub natural gas price of $2.58 per MMBtu to calculate our estimate of proved reserves as of December 31, 2019. Please see the table below.

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	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. 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 24-year career with three publicly traded oil and natural gas producing companies, including Legacy. He has over 10 years of SEC & SPE reserve report preparation experience for domestic and international companies. For 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.

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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 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,
	2019		2019		2018		2017(a)
Production:
Oil (MBbls)	398		5,695		6,629		5,032
Natural gas liquids (MGal)	1,944		32,683		41,549		38,159
Gas (MMcf)	2,893		51,754		58,457		62,833
Total (MBoe)	926		15,099		17,361		16,413
Average daily production (Boe per day)	44,095		43,892		47,564		44,967
Average sales price per unit (excluding commodity derivative cash settlements):
Oil (per Bbl)	$	58.32	$	52.84	$	56.64	$	47.59
NGL (per Gal)	$	0.47	$	0.43	$	0.67	$	0.65
Gas (per Mcf)	$	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 (per Bbl)	$	58.49	$	54.38	$	54.10	$	49.94
NGL (per Gal)	$	0.47	$	0.43	$	0.67	$	0.65
Gas (per Mcf)	$	2.08	$	2.25	$	2.68	$	2.93
Combined (per Boe)	$	32.63	$	29.15	$	31.29	$	28.05
Average unit costs per Boe:
Production costs, excl'd 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, 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, 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. 

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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, 2019 relating to our leasehold acreage.

	Developed Acreage(a)		Undeveloped Acreage(b)		Total Acreage
	Gross(c)	Net(d)	Gross(c)	Net(d)	Gross(c)	Net(d)
Total	852,851	431,767	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, 2019, 2018 and 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 Ended December 31,
	2019	2018	2017
Gross:
Development
Productive	29	54	42
Dry	—	—	—
Total	29	54	42
Exploratory
Productive	—	—	—
Dry	—	—	—
Total	—	—	—
Net:
Development
Productive	12.4	27.6	27.4
Dry	—	—	—
Total	12.4	27.6	27.4
Exploratory
Productive	—	—	—
Dry	—	—	—
Total	—	—	—

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Summary of Development Projects

For the year ended December 31, 2019, we invested approximately $102.1 million in implementing our development strategy, including $69.3 million related to the drilling and completion of 29 gross (12.4 net) development wells. The remaining $32.8 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, 2020 will be approximately $55.0 million 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 market conditions for oil and natural gas.

Present Activities

As of December 31, 2019, we were not in the process of drilling or completing any wells.

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. All of these commodity 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.”

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 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.

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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

There is no established public trading market for our common stock. As of April 27, 2020, there were 61,062,850 shares of common stock outstanding, held by approximately 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.

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ITEM 6.SELECTED FINANCIAL DATA

Not applicable.

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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 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 “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.

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

Upon the Company’s emergence from the Chapter 11 Cases, the Company adopted fresh-start accounting in accordance with the provisions set forth in ASC 852. As a result of the application of fresh-start accounting, as well as the effects of the implementation of the Plan, the consolidated financial statements on or after the Effective Date are not comparable with the consolidated financial statements prior to the Effective Date. Refer to Note 1 of the Notes to Consolidated Financial Statements for additional information.

References to the “Successor” or “Successor Company” refer to the financial position and results of operations of the new reorganized Company subsequent to the Effective Date. References to “Predecessor” or “Predecessor Company” refer to the financial position and results of operations of the Company prior to the Effective Date.

Trends Affecting Our Business and Operations

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. Crude 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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of oil production in response to market conditions, which could 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.

Many uncertainties remain regarding the COVID-19 pandemic and the disruption in the oil market, and it is impossible at this time to predict the full economic impact and the impact on our business. Due to these and other factors, the potential for a near or medium term recovery in crude oil prices is uncertain. The outlook for natural gas prices also remains uncertain. Many oil and natural gas companies have responded by announcing intentions to drastically cut drilling and completions activities. Our 2020 capital expenditures budget of approximately $55 million does not contain significant amounts necessary to maintain leasehold and is subject to significant change based on management’s view of commodity prices. We continue to monitor and evaluate any developments with respect to market conditions for oil and natural gas and the COVID-19 pandemic, though we cannot guarantee that any measures we take in response thereto will be entirely effective or effective at all.

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 our debt.

Our future growth will depend on our ability to continue to add reserves in excess 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 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 expected production, which allows us to mitigate, but not eliminate, oil and natural gas price 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 access additional capital in the capital markets and through our revolving credit facility. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ability to execute our 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 Data (In thousands, except per unit data and production)

The following table sets forth our selected financial and operating data for the periods 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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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