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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

b~~LEGACY RESERVES INC.~~

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~~TABLE OF CONTENTS~~

ITEM 2.PROPERTIES

~~PART III~~

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.

	~~ITEM 10.~~	~~DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE~~
			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		44,967
Average sales price per unit (excluding commodity derivative cash settlements):
Oil price (per Bbl)	$	58.32	$	52.84	$	56.64	$	47.59
Natural gas liquids price (per Gal)	$	0.47	$	0.43	$	0.67	$	0.65
Natural gas price (per Mcf)(a)	$	2.08	$	1.96	$	2.59	$	2.74
Combined (per Boe)	$	32.55	$	27.58	$	31.96	$	26.58
Average sales price per unit (including commodity derivative cash settlements):
Oil price (per Bbl)	$	58.49	$	54.38	$	54.10	$	49.94
Natural gas liquids price (per Gal)	$	0.47	$	0.43	$	0.67	$	0.65
Natural gas price (per Mcf)(a)	$	2.08	$	2.25	$	2.68	$	2.93
Combined (per Boe)	$	32.63	$	29.15	$	31.29	$	28.05
Average WTI oil spot price (per Bbl)	$	56.98	$	56.98	$	65.23	$	50.80
Average Henry Hub natural gas spot price (per MMBtu)	$	2.56	$	2.56	$	3.15	$	2.99
Average unit costs per Boe:
Production costs, excluding production and other taxes	$	10.45	$	10.87	$	11.02	$	10.58
Ad valorem taxes	$	0.10	$	0.60	$	0.51	$	0.59
Production and other taxes	$	1.69	$	1.48	$	1.70	$	1.21
General and administrative, excluding transaction costs and LTIP	$	1.59	$	2.76	$	2.25	$	2.07
Total general and administrative	$	1.59	$	5.12	$	4.21	$	3.01
Depletion, depreciation, amortization and accretion	$	6.75	$	10.39	$	9.22	$	7.73

____________________

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

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

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Results of Operations

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

Legacy’s revenues from the sale of oil were $23.2 million, $300.9 million and $375.4 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. Legacy’s revenues from the sale of NGLs were $0.9 million, $14.1 million and $27.8 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. Legacy’s revenues from the sale of natural gas were $6.0 million, $101.5 million and $151.7 million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively. The $51.3 million decrease in oil revenue reflects a decrease in oil production of 536 MBbls (8%) and a decrease in average realized price of $3.44 per Bbl (6%) to $53.20 for the year ended December 31, 2019 from $56.64 for the year ended December 31, 2018. The decrease in realized oil price was primarily caused by a decrease in the average WTI crude oil price of $8.25 and partially offset by improved realized regional differentials. The decrease in production is primarily due to reduced horizontal drilling activity of our Permian Basin horizontal assets as well as natural declines. The $12.8 million decrease in NGL revenues reflects a decrease in realized NGL price of $0.24 per Gal (36%) to $0.43 per Gal for the year ended December 31, 2019 from $0.67 per Gal for the year ended December 31, 2018 and a decrease in NGL production of 6,922 MGals (17%) during 2019. The decrease in NGL production is primarily due to decreased ethane recoveries from our Piceance natural gas properties. The $44.2 million decrease in natural gas revenues reflects a decrease of our realized natural gas prices as well as a decrease in our natural gas production volumes. Average realized gas prices decreased by $0.62 per Mcf (24%) to $1.97 per Mcf for the year ended December 31, 2019 from $2.59 per Mcf for the year ended December 31, 2018, primarily due to worsening realized regional differentials and a decrease in the average NYMEX Henry Hub natural gas price of $0.59 per Mcf. Our natural gas production decreased by approximately 3,810 MMcf (7%), primarily due to due to natural production declines in our East Texas and Piceance Basin properties as well as third-party plant and gathering interruptions resulting in production shut-ins.

For the period of December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), Legacy recorded $6.3 million and $50.3 million of net losses on oil and natural gas derivatives, respectively. Commodity derivative gains and losses represent the changes in fair value of our commodity derivative contracts during the period and are primarily based on oil and natural gas futures prices. The net loss recognized during 2019 was primarily due to the increase in oil futures prices for periods beyond 2019, which decreased the fair value of our derivatives in such periods, partially offset by cash received on oil and natural gas derivative contracts during the year. For the year ended December 31, 2018 (Predecessor), Legacy recorded $49.2 million of net gains on oil and natural gas derivatives. The net gain recognized during 2018 was primarily due to the decrease in oil futures prices for periods beyond 2018, which increased the fair value of our derivatives in such periods, partially offset by cash payments on oil derivative contracts during the year. Settlements of such contracts resulted in cash (payments)/receipts of $0.1 million, $23.7 million and $(11.7) million for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), respectively.

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

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

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

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

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

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

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

For the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor), income tax expense was zero, $0.1 million and $3.0 million, respectively. The effective income tax rates for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor) were 0.21%, 0.1% and 6.3%, respectively. For the period of December 11, 2019 through December 31, 2019 (Successor), our effective tax rate differed from the statutory rate primarily due to non-deductible executive compensation, and the valuation allowance. For the period of January 1, 2019 through December 10, 2019 (Predecessor), our effective rate differed from the statutory rate primarily due to non-deductible debt restructuring expenses and the valuation allowance.For the year ended December 31, 2018 (Predecessor), our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax, the 2023 Convertible Notes issuance, Texas margins tax, and the valuation allowance.

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

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

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

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

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

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

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

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

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

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

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across our historical properties primarily related to increased production rates combined with decreased reserves. Our depletion rate per Boe for the year ended December 31, 2018 was $9.22 compared to $7.73 for the year ended December 31, 2017. This increase is primarily driven by the increased depletion rates as discussed above.

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

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

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

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

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

Non-GAAP Financial Measure

Legacy’s management uses Adjusted EBITDA as a tool to provide additional information and a metric relative to the performance of Legacy’s business. Legacy’s management believes that Adjusted EBITDA is useful to investors because this measure is used by many companies in the industry as a measure of operating and financial performance and is commonly employed by financial analysts and others to evaluate the operating and financial performance of Legacy from period to period and to compare it with the performance of our peers. Adjusted EBITDA may not be comparable to a similarly titled measure of such peers because all entities may not calculate Adjusted EBITDA in the same manner.

The following presents a reconciliation of “Adjusted EBITDA,” which is a non-GAAP measure, to its nearest comparable GAAP measure. Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.

Adjusted EBITDA is defined as net income (loss) plus:

•Interest expense;

•(Gain) loss on extinguishment of debt;

•Income tax expense (benefit);

•Depletion, depreciation, amortization and accretion;

•Impairment of long-lived assets;

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•Loss (gain) on disposal of assets;

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

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

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

•Net (gains) losses on commodity derivatives;

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

•Exploration expenses; and

•Transaction costs.

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


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

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

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

____________________

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

For the period of December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), Adjusted EBITDA decreased (20)% to $222.8 million from $276.9 million for the year ended December 31, 2018 (Predecessor). This decrease is due primarily to decreased oil and natural gas production as well as decreased realized commodity prices. For the year ended December 31, 2018 (Predecessor), Adjusted EBITDA increased 22% to $276.9 million from $226.2 million for the year ended December 31, 2017 (Predecessor). This increase is due primarily to increased oil and natural gas production as well as increased realized commodity prices partially offset by lower commodity derivative realizations and increased production costs.

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Capital Resources and Liquidity

Since Legacy's emergence from the Chapter 11 Cases, Legacy’s primary sources of capital and liquidity have been cash flow from operations, realizations from our commodity derivatives, bank borrowings, or a combination thereof and Legacy’s primary use of capital has been for development of oil and gas wells and the repayment of bank borrowings.

Based upon current oil and natural gas price expectations and our commodity derivative positions, we anticipate that cash on hand and cash flow from operations will provide us sufficient liquidity to fund our operations in 2020, including our capital expenditures of approximately $55.0 million. The current outlook for commodity prices remains uncertain after a severe decline in March and April 2020. Our planned capital expenditures in 2020 does not contain significant amounts necessary to maintain leasehold interests, is not expected to maintain our year-end or Q4 2019 production levels, and is subject to significant change based on management’s view of commodity prices.

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

The COVID-19 pandemic may impact the ability of our customers to continue to purchase our produced oil and natural gas at current levels due to increased supply and storage capacity shortages, which would reduce our future expected revenues and may have a material adverse effect on our financial position, results of operations and liquidity.

Cash Flow from Operations

Our net cash provided by operating activities was $(0.1) million for the period December 11 to December 31, 2019 (Successor). For the period January 1, to December 10, 2019 (Predecessor), net cash provided by operating activities decreased relative to 2018 to $55.2 million, due to reorganization costs and lower realized commodity prices relative. For the year ended December 31, 2018 (Predecessor) cash provided by operating activities was $175.9 million.

Our net cash provided by (used in) operating activities was $175.9 million and $99.8 million for the years ended December 31, 2018 and 2017 (Predecessor), respectively, with the 2018 period being favorably impacted by higher realized commodity prices, partially offset by higher production expenses.

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

Investing Activities

Our cash capital expenditures were $7.2 million and $128.1 million for the period December 11 to December 31, 2019 (Successor), period January 1, to December 10, 2019 (Predecessor), respectively. The total is comprised primarily of development projects.

Our cash capital expenditures were $227.9 million for the year ended December 31, 2018 (Predecessor). The total includes $13.2 million related to individually immaterial acquisitions and $221.5 million of development projects.

We currently anticipate that our development capital budget, which predominantly consists of drilling, recompletion and well stimulation projects related to our horizontal Permian Basin inventory will be approximately $55.0 million for the year ending December 31, 2020. Our available borrowing capacity under our Successor Revolving Credit Facility is $88.0 million as of April 27, 2020. However, the COVID-19 pandemic and the disruption in the oil market is expected to lead to a significant

reduction in the borrowing base under our Successor Revolving Credit Facility. The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. As the majority of our capital budget is comprised of operated properties in which we control the timing of capital expenditure

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

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

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

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

The following tables summarize, for the periods indicated, our oil and natural gas derivatives in place as of April 27, 2020 covering the period from January 1, 2020 through December 31, 2023. We use derivatives, including swaps, enhanced swaps and three-way collars, as our mechanism for offsetting the cash flow effects of changes in commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to reduce the effects on cash flow of the floating prices we are paid by purchasers of our oil and natural gas. These transactions are mostly settled based upon the monthly average closing price of front-month NYMEX WTI oil and the price on the last trading day of front-month NYMEX Henry Hub natural gas.

Oil Swaps:


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

Natural Gas Swaps:


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

We have entered into regional crude oil differential swap contracts in which we have swapped the floating WTI-ARGUS (Midland) crude oil price for floating WTI-ARGUS (Cushing) less a fixed-price differential. As noted above, we receive a discount to the NYMEX WTI crude oil price at the point of sale. The following table summarizes the oil differential swap contracts currently in place as of April 27, 2020, covering the period from January 1, 2020 through December 31, 2023:


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

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


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

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


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

Financing Activities

Our net cash provided by (used in) financing activities was $(10.0) million, $91.7 million, and $12.1 million for the for the period December 11 to December 31, 2019 (Successor), period January 1, to December 10, 2019 (Predecessor), and year ended December 31, 2018, respectively.

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

Net cash used in financing activities for the period January 1, 2019 to December 10, 2019 (Predecessor) were repayments of debt of $779.8 million, which included repayment of debt of $596.0 million under the Predecessor Credit Facility in accordance with the Plan. In addition, net cash provided by financing activities included $626.8 million from borrowings under the credit facility, which included $388.0 million from proceeds from the Successor Revolving Credit Facility. In addition, net cash provided by financing activities included $256.3 million in proceeds from rights offerings.

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

Successor Credit Agreement

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

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The stated maturity date under the Credit Agreement is December 11, 2023. The loans under the Successor Revolving Credit Facility shall bear interest based on borrowing base utilization percentage at a rate per annum equal to the alternate base rate plus a margin ranging from 1.25% to 2.25% for alternate base rate loans or the adjusted LIBOR rate plus a margin ranging from 2.25% to 3.25% for LIBOR loans. Unused commitments under the Credit Agreement will accrue a commitment fee at a rate per annum of 0.50%. All interest and commitment fees are payable quarterly in arrears.

Legacy may elect, at its option, to prepay any loan under the Successor Revolving Credit Facility without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the Credit Agreement). Legacy may be required to make mandatory prepayments of the loans under the Successor Revolving Credit Facility in connection with certain borrowing base deficiencies. Additionally, if Legacy has outstanding borrowings, undrawn letters of credit and reimbursement obligations in respect of letters of credit issued under the Successor Revolving Credit Facility in excess of the aggregate revolving commitments, Legacy may be required to make mandatory prepayments.

Legacy’s obligations under the Successor Revolving Credit Facility are guaranteed by all of Legacy’s material domestic subsidiaries (the “Guarantors”) and secured by substantially all of the assets of Legacy and the Guarantors, including at least 95% of the net present value of Legacy’s and the Guarantors’ proved oil and gas properties, in each case subject to certain exceptions.

Additionally, the Credit Agreement contains customary events of default and remedies for credit facilities of this nature, including non-payment, breaches of representations and warranties, non-compliance with covenants or other agreements, bankruptcy, ERISA, failure of the loan documents to be in full force and effect, judgments and change of control.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies and Estimates

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

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

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

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Please read Note 3 of the Notes to Consolidated Financial Statements for a detailed discussion of all significant accounting policies that we employ and related estimates made by management.

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

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

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

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

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

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

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

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

Nature of Critical Estimate Item: Oil and Natural Gas Property Impairments — Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices.

As of December 31, 2019, a 10% decrease in net cash flows attributable to our production caused by any one or a combination of variables, including commodity prices, development costs, changes in production levels or other factors, would increase our recognized oil and natural gas property impairments by $3.9 million. We expect the COVID-19 pandemic and the disruption in the oil market to lead to a significant reduction in our reserves. As a result, we expect to recognize impairments to our oil and natural gas properties in 2020.

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued ASU No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms at commencement longer than twelve months. The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized an ROU asset and a lease liability, with the cumulative-effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:

•whether any expired or existing contracts were or contained leases;

•the lease classification for any expired or existing leases; and

•initial direct costs for any existing leases.

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

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

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

Finance leases are included in other property and equipment, other current liabilities, and other long-term liabilities in our consolidated balance sheets. Finance lease ROU assets (that is, amounts capitalized in other property and equipment) and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The finance lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. We generally amortize that ROU asset on a straight-line basis, while interest on the lease liability is calculated using the effective interest method. Lease expense recognized under our finance leases is, therefore, comprised of amortization on the finance lease ROU asset and interest on the finance lease liability.

Nature of Leases

In support of our operations, we lease certain corporate office space, field offices, compressors, drilling rigs, other production equipment, fleet vehicles and storage space under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Corporate and Field Offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to ten years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.

Compressors

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

To the extent that our compressor rental arrangements have a primary term of twelve months or less, we have elected to apply the practical expedient for short-term leases. For those short-term compressor contracts, we do not apply the lease recognition requirements, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Drilling Rigs

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

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

Other Production Equipment

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

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

Fleet Vehicles

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

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A.CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, or the “Exchange Act”) that are designed to ensure that information required to be disclosed in Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

Our management team, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2019. Based upon that evaluation and subject to the foregoing, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

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

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Management’s Annual Report on Internal Control over Financial Reporting

Legacy’s management is responsible for establishing and maintaining adequate control over financial reporting. Our internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

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

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

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

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

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ITEM 9B.OTHER INFORMATION

Termination of Registration

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

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PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

Set forth below is biographical information regarding the current members of our Board of Directors (the “Board” or the “Board of Directors”) and information regarding the specific experience, qualifications, attributes and skills that qualify ~~the nominees~~then to serve on the Board.

~~Name~~	~~Principal Occupation~~	~~Age~~	~~Director Since~~
~~Paul T. Horne~~ Name			~~Mr. Horne~~Principal Occupation	Age	Director Since
Richard Betz			Richard F. Betz was appointed to the Board ~~of Directors~~ in December ~~2014~~2019 and ~~was appointed as~~is currently the ~~Chairman~~Chief Executive Officer of Lithos Resources since February 2020. Prior to Mr. Betz’ appointment to the Board, ~~of Directors in May 2016. Mr. Horne~~he served as Chief Executive Officer and as a director of ~~Legacy~~Resolute Energy Corporation (“Resolute”) from January 2017 until March ~~2015~~2019. From March 2012 until ~~February 2019.~~his appointment as Chief Executive Officer of Resolute, Mr. ~~Horne previously~~Betz served ~~as President of Legacy from March 2015 to March 2018,~~ as Executive Vice President and Chief Operating Officer of ~~Legacy from~~Resolute. From September 2009 to March 2012, ~~to March 2015 and~~Mr. Betz served as ~~Executive~~Senior Vice President, Strategy and Planning of ~~Operations~~Resolute and was Vice President, Business Development from July 2009 to September 2009. Prior to that, Mr. Betz served as Vice President, Business Development of ~~Legacy from our~~a predecessor of Resolute since its founding in ~~October 2005~~2004. Prior to ~~March 2012. From January 2000 to October 2005,~~2004, Mr. ~~Horne served~~Betz worked as ~~Operations Manager~~a Managing Director of ~~Moriah Resources, Inc. From January 1985 to January 2000, Mr. Horne worked for Mobil E&P U.S. Inc. in a variety of petroleum engineering~~Chase Securities and ~~operations management roles primarily~~successor companies in the ~~Permian Basin.~~oil and gas investment banking coverage group with primary responsibility for mid-cap exploration and production companies as well as leveraged finance and private equity. Mr. ~~Horne has a Bachelor~~Betz received an MBA from the Wharton School of ~~Science~~the University of Pennsylvania and an undergraduate degree ~~in Petroleum Engineering~~ from ~~Texas A&M~~Villanova University.	57 58	December ~~2014~~ 2019

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

David Coppé			~~Mr. Vann~~David Coppé was appointed to the Board ~~of Directors upon completion of our private equity offering~~ in ~~March 2006 and was named Lead Independent Director of the Board of Directors on May 12, 2016. From 1970 through 1979,~~December 2019. Prior to his current role, Mr. ~~Vann was employed in the refining division of Exxon Company USA, and from 1979 through January 2001, Mr. Vann was employed by Koch Industries. From February 2001 through December 2004, Mr. Vann~~Coppé served as Director and Head of Energy, Private Equity of Caisse de Depot et Placement du Québec from March 2017 until March 2019. From November 2012 until his appointment as Director and Head of Energy, Private Equity, Mr. Coppé served as President and Chief Executive Officer of ~~Entergy — Koch, LP, an energy trading and transportation company.~~Probe Holdings, Inc. Mr. ~~Vann continues to serve Entergy as a consultant and serves~~Coppé served on ~~the advisory board and consults with Texon, LP, a private energy marketing company. On May 8, 2006, Mr. Vann was appointed to~~ the board of directors of ~~Crosstex~~Logan International, Inc. from 2006 until 2016, and also served on a number of other private company boards. He started his career as a field engineer for Schlumberger and also worked for Goldman Sachs and Cadent Energy ~~L.P. (now EnLink Midstream~~ Partners, LP), a publicly traded midstream master limited partnership. From January 2009 through June 2010, Mr. Vann served as an advisory board member for Enexus, LLC, which is a subsidiary of Entergy Corporation. From October 2012 to October 2017, Mr. Vann served as an Executive Advisor for CCMP Capital Advisors, LLC, a private equity firm. ~~In October 2017, Mr. Vann joined~~He currently serves on the board of ~~PQ Chemical, which is~~ RDV Resources (f/k/a ~~portfolio company~~Sheridan I). Mr. Coppé received an MBA from Massachusetts Institute of ~~CCMP Capital. Mr. Vann has~~Technology and a ~~Bachelor of Science~~Mechanical Engineering degree ~~in Chemical Engineering, with honors,~~ from the University of ~~Kansas. Mr. Vann serves on the Board of Advisors for the School of Engineering at the University of Kansas, which selected him to receive its Distinguished Engineering Service Award in 2012.~~Louvain, Belgium.	71 48	~~March 2006~~

~~TABLE OF CONTENTS~~

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

The aggregate fees for professional services rendered by BDO USA, LLP, for the fiscal years ended December 31, 2019 and 2018 ~~and 2017~~ were:

Year ended December 31

2018
2017
Audit Fees⁽¹⁾
$
1,069,208

$
654,945

Audit-Related Fees⁽¹⁾
$
8,500

$
58,465

Tax Fees
$
—

$
—

All Other Fees (Executive compensation)⁽²⁾
$
—

$
30,640

Total
$
1,077,708

$
744,050

~~(1)~~

~~In the above table, “~~~~Audit Fees~~” are fees we paid for professional services for the audit of our consolidated financial statements included in our annual report on Form 10-K or for services that are normally provided by our principal accountants in connection with statutory and regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work. “~~Audit-Related Fees~~~~” are fees billed for assurance and related services in connection with acquisition transactions and related regulatory filings.~~

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~~(2)~~

“~~All Other Fees (Executive compensation studies)~~” are fees billed for compensation consulting services in 2017 in connection with a study of compensation programs related to named executive officers and outside directors of a broad peer group of exploration and production companies and publicly traded limited partnerships.


	Year ended December 31
	2019		2018
Audit Fees(1)	$	860,812	$	1,069,208
Audit-Related Fees(1)	$	—	$	8,500
Tax Fees	$	—	$	—
All Other Fees	$	—	$	—
Total	$	860,812	$	1,077,708

(1) In the above table, “Audit Fees” are fees we paid for professional services for the audit of our consolidated financial statements included in our annual report on Form 10-K or for services that are normally provided by our principal accountants in connection with statutory and regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work. “Audit-Related Fees” are fees billed for assurance and related services in connection with acquisition transactions and related regulatory filings.

In regard to executive compensation services, as required by the Public Company Accounting Oversight Board, all services are approved in advance by the ~~Audit Committee.~~Board of Directors. All compensation consulting services are provided under the terms of a separate engagement letter that describes the approved services and the company’s acceptance of its responsibilities. Under the terms of the engagement, BDO USA, LLP does not perform management functions or make any management decisions. Legacy must designate an individual with suitable skill, knowledge and experience to oversee the consulting engagement, evaluate the adequacy and results of the services performed, accept responsibility for the results of the services and establish and maintain internal controls and monitor ongoing activities.

The ~~Audit Committee’s~~Board of Director’s policy is to pre-approve any audit services and any permissible non-audit services provided by Legacy’s independent auditors on behalf of Legacy. These services may include audit services, audit-related services, and other services. Pre-approval is detailed as to the specific service or category of service and is subject to a specific approval.

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PART IV

~~TABLE OF CONTENTS~~

~~PART IV~~

ITEM 15.EXHIBITS, ~~AND~~ FINANCIAL STATEMENT SCHEDULES

(a)(1) and (2) Financial Statements

The consolidated financial statements of Legacy Reserves Inc. are listed on the Index to Financial Statements to this annual report on Form 10-K beginning on page F-1.

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(a)(3) Exhibits

The following documents are filed as a part of this annual report on Form 10-K or incorporated by reference:


Exhibit
Number		Description
2.1	—	~~Description~~Joint Chapter 11 Plan of Reorganization for Legacy Reserves Inc. and its Debtor Affiliates (incorporated by reference to Exhibit A of the Order confirming the Joint Chapter 11 Plan of Reorganization for Legacy Reserves Inc. and Its Debtor Affiliates, filed as Exhibit 2.1 to Legacy Reserve Inc.'s current report on Form 8-K (File No. 001-38668) filed on November 19, 2019).
~~31.1~~ 3.1	—	Second Amended and Restated Cert i ficate of Incorporation of Legacy Reserves Inc. (filed as Exhibit 3.1 to Legacy Reserves Inc.'s current r eport on Form 8-K (File No. 001-38668) on December 17 , 201 9 , and incorporated herein by reference).
3.2	—	Third Amended and Restated Bylaws of Legacy Reserves Inc. (filed as Exhibit 3.2 to Legacy Reserves Inc.'s c urrent r eport on Form 8-K (File No. 001-38668) on December 17 , 201 9 , and incorporated herein by reference).

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Exhibit
Number		Description






10.1	—	Credit Agreement, among Legacy Reserves Inc. as Borrower, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, and the Issuing Bank, dated as of December 11, 2019, (filed as Exhibit 10.1 to Legacy Reserves Inc.'s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.2	—	Stockholders Agreement among Legacy Reserves Inc., each of the Persons who are listed on Schedule 1 thereto each of the Persons who are listed on Schedule2 thereto, and each Person who becomes a party thereto pursuant to Article IV as a Stockholder, dated as of December 11, 2019 (filed as Exhibit 10.2 to Legacy Reserves Inc.'s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.3	—	Management Stockholders Agreement among Legacy Reserves Inc., each of the Persons who are listed on Schedule 1 thereto, and each Eligible Employee, Consultant or Non-Employee Director of the Company and/or one or more of its subsidiaries, dated as of December 11, 2019 (filed as Exhibit 10.3 to Legacy Reserves Inc.'s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.4†	—	Second Amended and Restated Employment Agreement dated as of December 11, 2019, between Legacy Reserves Inc., Legacy Reserves Services, LLC and James Daniel Westcott (filed as Exhibit 10.4 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.5†	—	Second Amended and Restated Employment Agreement, dated as of December 11, 2019, between Legacy Reserves Inc., Legacy Reserves Services, LLC and Kyle M. Hammond (filed as Exhibit 10.5 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.6†	—	Amended and Restated Employment Agreement, dated as of December 11, 2019, between Legacy Reserves Inc., Legacy Reserves Services, LLC and Robert L. Norris (filed as Exhibit 10.6 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.7†	—	Amended and Restated Employment Agreement, dated as of December 11, 2019, between Legacy Reserves Inc., Legacy Reserves Services, LLC and Albert E. Ferrara, III (filed as Exhibit 10.7 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.8†	—	Amended and Restated Employment Agreement, dated as of December 11, 2019, between Legacy Reserves Inc., Legacy Reserves Services, LLC and Cory J. Elliott (filed as Exhibit 10.8 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.9†	—	Amended and Restated Employment Agreement, dated as of December 11, 2019, between Legacy Reserves Inc., Legacy Reserves Services, LLC and Micah C. Foster (filed as Exhibit 10.9 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.10†	—	Legacy Reserves Inc. 2019 Management Incentive Plan, effective as of December 11, 2019 (filed as Exhibit 10.10 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.11†	—	Form of Stock Option Award Agreement Pursuant to the Legacy Reserves Inc. 2019 Management Incentive Plan (filed as Exhibit 10.11 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on December 17, 2019, and incorporated herein by reference)
10.12†	—	Form of Restricted Stock Unit Award Agreement Pursuant to the Legacy Reserves Inc. 2019 Management I ncentive Plan (filed as Exhibit 10.12 to Legacy Reserves Inc.’s current report on Form 8-K (File No.001-38668) on December 17, 2019, and incorporated herein by reference)
10.13†	—	Legacy Reserves Services, LLC 2019 Key Employee Incentive Plan, effective as of May 17, 2019 (filed as Exhibit 10.1 to Legacy Reserves Inc.’s current report on Form 8-K (File No. 001-38668) on May 23, 2019,and incorporate herein by reference)

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Exhibit
Number		Description
21.1*	—	List of subsidiaries of Legacy Reserves Inc.
24.1*	—	Power of Attorney (included on the Signature pages of this annual report on Form 10-K)
31.1*	—	Rule 13a-14(a) Certification of CEO (under Section 302 of the Sarbanes-Oxley Act of 2002)
~~31.2~~ 31.2*	—	— Rule 13a-14(a) Certification of CFO (under Section 302 of the Sarbanes-Oxley Act of 2002)
32.1*	—	Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002)
99.1*	—	Summary Reserve Report from LaRoche Petroleum Consultants, Ltd.
101.INS*	—	XBRL Instance Document
101.SCH*	—	XBRL Taxonomy Extension Schema Document
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document

____________________


*						Filed herewith
†						Management contract or compensatory plan or arrangement

ITEM 16.FORM 10-K SUMMARY

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this annual report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, on the ~~26th~~29th day of April, ~~2019.~~

2020.

LEGACY RESERVES INC.

By:

~~By:~~

/S/S/ ROBERT L. NORRIS

Name:

Robert L. Norris

Title:

Chief Financial Officer (Principal Financial Officer)

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints James D. Westcott and Robert L. Norris, or either of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this annual report on Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

/S/ JAMES D. WESTCOTT

Director and Chief Executive Officer

April 29, 2020

James D. Westcott

(Principal Executive Officer)

/S/ KYLE M. HAMMOND

Director and Chief Operating Officer

April 29, 2020

Kyle M. Hammond

(Principal Operating Officer)

/S/ ROBERT L. NORRIS

Chief Financial Officer

April 29, 2020

Robert L. Norris

(Principal Financial Officer)

/S/ MICAH C. FOSTER

Chief Accounting Officer and Controller

April 29, 2020

Micah C. Foster

(Principal Accounting Officer)

/S/ RICHARD F. BETZ

Director

April 29, 2020

Richard F. Betz

/S/ DAVID COPPÉ

Director

April 29, 2020

David Coppé

/S/ GARY GOULD

Director

April 29, 2020

Gary Gould

/S/ ROBERT HORN

Director

April 29, 2020

Robert Horn

/S/ DOUGLAS W. YORK

Director

April 29, 2020

Douglas W. York

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


			Page
Report of Independent Registered Public Accounting Firm			2
Consolidated Financial Statements:
Consolidated Balance Sheets			3
Consolidated Statements of Operations			6
Consolidated Statements of Stockholders’ Equity			7
Consolidated Statements of Cash Flows			9
Notes to Consolidated Financial Statements			11
Unaudited Supplementary Information			53

F-1

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Report of Independent Registered Public Accounting Firm

Stockholders and Board of Directors

Legacy Reserves Inc.

Midland, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Legacy Reserves Inc. (the “Company”) as of December 31, 2019 (Successor) and 2018 (Predecessor), the related consolidated statements of operations, stockholders’ equity/unitholders’ (deficit), and cash flows for the periods from December 11, 2019 to December 31, 2019 (Successor), the period from January 1, 2019 to December 10, 2019 (Predecessor) and for each of the two years in the period ended December 31, 2018 (Predecessor), and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 (Successor) and 2018 (Predecessor), and the results of their operations and their cash flows for the period from December 11, 2019 to December 31, 2019 (Successor), the period from January 1, 2019 to December 10, 2019 (Predecessor) and for each of the two years in the period ended December 31, 2018 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

Change in Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, upon emerging from bankruptcy proceedings on December 11, 2019, the Company became a new entity for financial reporting purposes and applied fresh-start accounting. The Company’s assets and liabilities were recorded at their estimated fair values, which differed materially from the previously recorded amounts. As a result, the consolidated financial statements for period following the application of fresh-start accounting are not comparable to the financial statements for previous periods.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Emphasis of Matter

As more fully described in Note 20 to the consolidated financial statements, the Company may be materially impacted by the novel strain Coronavirus (COVID-19), which was declared a global pandemic by the World Health Organization in March 2020, as well as the ongoing effect of the severe decrease in crude oil prices.


/s/ BDO USA, LLP

We have served as the Company's auditor since 2005.

Houston, Texas

April 29, 2020

F-2

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LEGACY RESERVES INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2019 AND 2018

F-3

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	Successor		Predecessor
	2019		2018
	(In thousands)
ASSETS
Current assets:
Cash	$	4,306	$	1,098
Restricted cash	24,039		—
Accounts receivable, net:
Oil and natural gas	62,543		56,615
Joint interest owners	15,842		15,370
Other	2		—
Fair value of derivatives (Notes 11 and 12)	569		66,662
Prepaid expenses and other current assets	9,708		11,347
Total current assets	117,009		151,092
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting	650,839		3,471,456
Unproved properties	280,025		19,863
Accumulated depletion, depreciation, amortization and impairment	(4,921)		(2,177,006)
Total oil and natural gas properties, net	925,943		1,314,313
Other property and equipment, net of accumulated depreciation and amortization of $— and $12,323, respectively	5,993		2,456
Operating rights, net of amortization of $0 and $6,123, respectively	—		894
Fair value of derivatives (Notes 11 and 12)	—		3,135
Other assets	—		3,041

Total assets	$	1,048,945	$	1,474,931
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Current debt, net	$	—	$	856,646
Accounts payable	12,021		11,227
Accrued oil and natural gas liabilities (Note 3)	61,176		98,886
Fair value of derivatives (Notes 11 and 12)	10,223		—
Asset retirement obligation (Note 14)	4,739		3,938
Other	28,717		13,953
Total current liabilities	116,876		984,650
Long-term debt (Note 5)	369,549		432,923
Asset retirement obligation (Note 14)	147,754		248,796
Fair value of derivatives (Notes 11 and 12)	3,491		550
Other long-term liabilities	2,055		643
Total liabilities	639,725		1,667,562

Stockholders' equity (deficit):
Common stock, $0.01 par value; 945,000,000 shares authorized, 109,442,278 shares outstanding at December 31, 2018 (Predecessor)			1,094
Common stock, $0.01 par value; 600,000,000 shares authorized, 61,062,850 shares outstanding at December 31, 2019 (Successor)	611

Additional paid-in capital	405,559		24,752
Retained earnings (accumulated deficit)	3,050		(218,477)
Total stockholders’ equity (deficit)	409,220		(192,631)
Total liabilities and stockholders' equity (deficit)	$	1,048,945	$	1,474,931

F-4

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See accompanying notes to consolidated financial statements.

F-5

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LEGACY RESERVES INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


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

Revenues:
Oil sales	$	23,232	$	300,905	$	375,444	$	239,448
Natural gas liquids (NGL) 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	9,779		173,232		200,285		183,219
Exploration Expense	750		—		—		—
Production and other taxes	1,564		22,371		29,532		19,825
General and administrative	1,470		77,364		73,039		49,372
Depletion, depreciation, amortization and accretion	6,259		156,935		159,998		126,938
Impairment of long-lived assets	—		105,532		67,978		37,283
Loss (gain) on disposal of assets	(565)		2,130		(23,803)		1,606
Total expenses	19,257		537,564		507,029		418,243
Operating income (loss)	10,907		(121,089)		47,832		18,058
Other income (expense):
Interest income	5		46		36		64
Interest expense (Notes 5, 11 and 12)	(1,607)		(115,660)		(117,008)		(89,206)
Gain on extinguishment of debt	—		13,105		66,066		—
Equity in income of equity method investees	(2)		(35)		(19)		17
Net gains (losses) on commodity derivatives (Notes 11 and 12)	(6,292)		(50,294)		49,172		17,776
Reorganization items, net (Note 2)	—		447,901		—		—
Other	42		7		722		792
Income (loss) before income taxes	3,053		173,981		46,801		(52,499)
Income tax expense	(3)		(105)		(2,968)		(1,398)
Net Income (loss)	$	3,050	$	173,876	$	43,833	$	(53,897)



Net Income (loss) per share — basic and diluted (Note 15)	$	0.05	$	1.51	$	0.42	$	(0.54)
Weighted average number of shares used in
computing loss per share —
Basic and Diluted	61,063		114,811		105,087		100,049

See accompanying notes to consolidated financial statements.

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LEGACY RESERVES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS'/UNITHOLDERS’ DEFICIT

FOR THE YEARS ENDED DECEMBER 31, 2018 (Predecessor) AND 2017 (Predecessor)


	Series A Preferred Equity				Series B Preferred Equity					Incentive Distribution Equity					Unitholders' Equity (Deficit)									Stockholders' Deficit
	Units	Amount		Units	Amount		Units	Amount		Limited Partner Units	Limited Partner Amount		General Partner Amount		Shares	Par Value		APIC		Acc. Deficit		Total Deficit
	(In thousands)




















Balance, December 31, 2016	2,300	$	55,192	7,200	$	174,261	100	$	30,814	72,056	$	(482,200)	$	(146)	—	$	—	$	—	$	—	$	—
Units issued to Legacy Board of Directors for services	—	—		—	—		—	—		287	586		—		—	—		—		—		—

Unit-based compensation	—	—		—	—		—	—		—	3,703		—		—	—		—		—		—
Vesting of restricted and phantom units	—	—		—	—		—	—		252	—		—		—	—		—		—		—





Net loss	—	—		—	—		—	—		—	(53,883)		(14)		—	—		—		—		—
Balance, December 31, 2017	2,300	$	55,192	7,200	$	174,261	100	$	30,814	72,595	$	(531,794)	$	(160)	—	$	—	$	—	$	—	$	—
Units issued to Legacy Board of Directors for services	—	—		—	—		—	—		60	522		—		33	—		162		—		162
Unit-based compensation	—	—		—	—		—	—		—	3,753		—		—	—		4,108		—		4,108
Vesting of restricted and phantom units	—	—		—	—		—	—		339	—		—		1,550	—		—		—		—
Units issued in exchange for Standstill Fee	—	—		—	—		—	—		3,800	5,928		—		—	—		—		—		—
Debt exchange	—	—		—	—		—	—		—	—		—		3,422	34		23,815		—		23,849
Corporate Reorganization	(2,300)	(55,192)		(7,200)	(174,261)		(100)	(30,814)		(76,794)	521,591		160		104,437	1,060		(3,333)		(262,310)		(264,583)
Net income	—	—		—	—		—	—		—	—		—		—	—		—		43,833		43,833
Balance, December 31, 2018	—	$	—	—	$	—	—	$	—	—	$	—	$	—	109,442	$	1,094	$	24,752	$	(218,477)	$	(192,631)

See accompanying notes to consolidated financial statements.

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LEGACY RESERVES INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)



	Stockholders' Equity (Deficit)
	Shares	Par Value		APIC		Acc. Deficit		Total Deficit
(In thousands)
Balance, December 31, 2018 (Predecessor)	109,442	$	1,094	$	24,752	$	(218,477)	$	(192,631)

Stock-based compensation	—	—		14,782		—		14,782
Debt exchange	5,368	54		3,663		—		3,717
ASC 842 Adoption	—	—		—		256		256
Net loss	—	—		—		173,876		173,876
Balance, December 10, 2019 (Predecessor)	114,810	$	1,148	$	43,197	$	(44,345)	$	—
Cancellation of Predecessor equity	(114,810)	$	(1,148)	$	(43,197)	$	44,345	$	—
Balance, December 10, 2019 (Predecessor)	—	$	—	$	—	$	—	$	—

Rights Offering	27,705	277		256,300		—		256,577
Issuance of Successor common stock	33,358	334		149,259		—		149,593
Balance, December 10, 2019 (Successor)	61,063	$	611	$	405,559	$	—	$	406,170

Net income	—	—		—		3,050		3,050
Balance, December 31, 2019 (Successor)	61,063	$	611	$	405,559	$	3,050	$	409,220

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LEGACY RESERVES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017


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

Cash flows from operating activities:
Net income (loss)	$	3,050	$	173,876	$	43,833	$	(53,897)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation, amortization and accretion	6,259		156,935		159,998		126,938

Amortization of debt discount and issuance costs	123		28,775		20,604		7,657
Gain on extinguishment of debt	—		(13,105)		(66,066)		—
Impairment of long-lived assets	—		105,532		67,978		37,283
(Gain) loss on derivatives	6,292		52,337		(49,099)		(19,711)
Equity in income (loss) of equity method investees	2		35		19		(17)

Stock/Unit-based compensation	—		14,782		6,619		6,011
Reorganization items, net increase	—		(479,071)		—		—
Loss (gain) on disposal of assets	(565)		2,130		(23,803)		1,606
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, oil and natural gas	1,129		(7,057)		6,140		(19,563)
(Increase) decrease in accounts receivable, joint interest owners	(2,630)		2,167		12,039		(4,006)
(Increase) decrease in accounts receivable, other	—		(12)		12		—
(Increase) decrease in other assets	(335)		1,133		2,157		3
Increase (decrease) in accounts payable	3,794		(6,150)		(1,865)		4,001
Increase (decrease) in accrued oil and natural gas liabilities	(508)		(4,856)		9,540		1,891
Increase (decrease) in other liabilities	(16,722)		27,788		(12,165)		11,599
Total adjustments	(3,161)		(118,637)		132,108		153,692
Net cash provided by operating activities	(111)		55,239		175,941		99,795
Cash flows from investing activities:
Investment in oil and natural gas properties	(7,162)		(128,086)		(227,855)		(313,898)
Decrease in deposit on pending acquisition	—		(75)		—		—

Proceeds from sale of fixed assets	350		1,608		54,968		11,099
Investment in other equipment	150		(4,003)		(406)		(593)

Corporate Reorganization	—		—		(3,120)		—
Distribution from equity method investee	—		660		—		—
Net cash settlements on commodity derivatives	76		23,686		(11,715)		24,156
Net cash used in investing activities	(6,586)		(106,210)		(188,128)		(279,236)
Cash flows from financing activities:
Proceeds from long-term debt	17,000		626,758		659,626		538,000
Payments of long-term debt	(27,000)		(779,758)		(619,384)		(357,000)

Payments of debt issuance costs	—		(11,648)		(28,132)		(3,282)
Proceeds from equity offering	—		256,300		—		—

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Net cash provided by (used in) financing activities	(10,000)		91,652		12,110		177,718
Net (decrease) increase in cash	(16,697)		40,681		(77)		(1,723)
Cash and restricted cash, beginning of period (1)	45,042		4,361		4,438		6,161
Cash and restricted cash, end of period (1)	$	28,345	$	45,042	$	4,361	$	4,438

Supplemental cash flow information:
Cash paid for interest	$	1,383	$	69,294	$	101,315	$	83,160
Cash paid for reorganization items	14,307		27,969		—		—

Non-Cash Investing and Financing Activities:
Asset retirement obligation costs and liabilities	$	91	$	5,273	$	65	$	39
Asset retirement obligations associated with property acquisitions	$	—	$	30	$	226	$	62
Asset retirement obligations associated with properties sold	$	(244)	$	(243)	$	(27,673)	$	(8,464)
Debt exchange	$	—	$	—	$	23,849	$	—
Change in accrued capital expenditures	$	(2,281)	$	(30,066)	$	8,029	$	—
Units issued in exchange for Standstill Agreement	$	—	$	—	$	5,928

(1) Inclusive of $24.0 million, $28.5 million, $3.3 million, and $3.2 million of restricted cash for the period December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), and December 31, 2018 (Predecessor) and 2017 (Predecessor) respectively.

See accompanying notes to consolidated financial statements.

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LEGACY RESERVES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

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.

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.

Plan of Reorganization

Treatment of Claims and Interests under the Plan

The Plan provided the following treatment of claims against and interests in the Debtors:

•all holders of claims arising under the Senior Secured Superpriority Debtor-In-Possession Credit Agreement (the “DIP Credit Agreement”) dated as of June 21, 2019 among Legacy Reserves LP, as debtor, debtor-in-possession and borrower, the other loan parties party thereto, as debtors, debtors-in-possession and guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “RBL Lenders”), received, in full satisfaction of their respective claims (i) on account of claims under the new money revolving loan facility in an aggregate amount of up to $100.0 million, payment in full in cash, (ii) on account of claims under the refinancing term loan in the amount of $250.0 million, distribution of cash and commitments under the Successor Revolving Credit Facility and/or (iii) if the Successor Revolving Credit Facility had not been consummated, payment in full in cash. See Note 5, "Debt" for additional information about the Successor Revolving Credit Facility;

•all holders of claims arising under the Third Amended and Restated Credit Agreement dated as of April 1, 2014 (as amended, the “Prepetition RBL Credit Agreement”) among Legacy Reserves LP, as borrower, the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “Term Lenders”), received, in full satisfaction of their respective claims, (i) distribution of their pro rata share of commitments under the Successor Revolving Credit Facility in exchange for the claims arising under the Prepetition RBL Credit Agreement or (ii) if the Successor Revolving Credit Facility had not been consummated, payment in full in cash;

•all holders of claims arising under the 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”), received their pro rata share of approximately 52.25% of the new common stock (the “New Common Stock”) issued by Legacy, as reorganized pursuant to and under the Plan (“Reorganized Legacy”), subject to dilution;

•holders of claims arising under the indenture governing the 8% Senior Notes due 2020, the indenture governing the 6.25% Senior Notes due 2021 and the indenture governing the 8% Convertible Senior Notes due 2023 (the “Noteholders”) received their respective pro rata share of (i) approximately 2.46% of the New Common Stock, subject to dilution, and (ii) subscription rights to purchase approximately 10.82% of the New Common Stock pursuant to the Rights Offering (as defined below) to the extent that such Noteholders are “accredited investors” as defined under Regulation D promulgated under the Securities Act of 1933, as amended (“Securities Act”);

•all existing equity interests in Legacy did not receive any recovery under the Plan and were extinguished.

Capital Structure

As of the Effective Date, under the Plan, Reorganized Legacy issued New Common Stock to certain holders of claims against and interests in the Debtors, and Legacy’s shares of existing common stock outstanding immediately prior to the

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Effective Date were cancelled. As of the Effective Date, there were approximately 114,810,671 shares of Legacy’s existing common stock outstanding.

Exit Financing

The Plan was funded by the following exit financings:

•up to $500.0 million in aggregate principal amount under a new senior secured first lien reserved-based revolving credit facility funded by certain of the RBL Lenders;

•$189.8 million in proceeds from the purchase of approximately 30.88% of the New Common Stock, subject to dilution, backstopped pursuant to the Sponsor Backstop Commitment Agreement dated June 13, 2019, among Legacy and GSO Capital Partners LP and certain of its affiliates (the “Plan Sponsor”); and

•$66.5 million in proceeds from a rights offering (the “Rights Offering”), backstopped pursuant the Noteholder Backstop Commitment Agreement dated June 13, 2019, among Legacy and certain Noteholders (the “Noteholder Backstop Agreement”).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) Fresh-Start Accounting

Upon the Company’s emergence from the Chapter 11 Cases, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value (as defined below) of the Company's assets immediately before the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of existing voting shares immediately before confirmation received less than 50% of the voting shares of the emerging entity. 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. See Note 1, “Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” for additional information.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company allocated the fair value of the Successor Company’s total assets (the “Reorganization Value”) to its individual assets based on their estimated fair values.

Reorganization Value represents the fair value of the Successor Company's total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately before restructuring. Under fresh start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values.

Our reorganization value was derived from an estimate of "Enterprise Value," or the fair value of the Company’s long-term debt and stockholders’ equity. The estimated Enterprise Value at the Effective Date was a range of $725 - $925 million as established in the Plan and approved by the bankruptcy court. Based on the estimates and assumptions used in determining the Enterprise Value, as further discussed below, the Company estimated the Enterprise Value to be approximately $769.0 million. This estimate was derived from an independent valuation using an asset based methodology of proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches.

The Company’s principal assets are its oil and natural gas properties. Significant inputs used to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Reserves were categorized based on the probability of being able to extract the reserves from the ground. The two major categories being proved reserves and unproved reserves. Proved reserves are those with a 90% certainty of commercial extraction and consist of producing reserves ("PDP"), non-producing reserves ("PDNP"), and proved, undeveloped reserves ("PUD") . Unproved reserves were further broken into two categories: probable reserves and possible reserves. Probable reserves have a 50% certainty of commercial extraction and Possible reserves have a 10% certainty of commercial extraction.

For purposes of estimating the fair value of the Company’s proved, probable, and possible reserves, the Discounted Cash Flow ("DCF") method under the income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.4%.

Future commodity prices were estimated using market-based transactions for future delivery adjusted for transportation and differentials. For oil, futures prices published at close as of December 11, 2019 (the "Valuation Date") from the New York Mercantile Exchange for delivery of a barrel of West Texas Intermediate ("WTI") crude oil to Cushing, Oklahoma was used. For natural gas, the futures price published at close of the Valuation date from the New York Mercantile Exchange for delivery of one thousand cubic feet ("mcf") of natural gas to the Henry Hub in Erath, LA was used. The price for natural gas liquids ("NGLs") was based on 26% of WTI.

Future operating and development costs were estimated based on the Company's recent costs trends adjusted for inflation. Risk factors were determined separately depending on geographic location of the reserves.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In estimating the fair value of the Company's unproved acreage, that was not included in the valuation of probable and possible reserves, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s equity as of December 11, 2019 (in thousands):


	December 11, 2019
Enterprise Value	$	769,033
Plus: Cash and cash equivalents	16,563
Indicated invested capital value	785,596

Less: Post-Reorganization Debt	(379,426)
Concluded Equity Value	$	406,170

Upon issuance of the Successor Revolving Credit Facility on December 11, 2019, the Company received net proceeds of approximately $379.4 million and incurred debt issuance costs of approximately $8.6 million.

The following table reconciles the Company's Debt as of December 11, 2019 (in thousands):


	12/11/2019
Successor Revolving Credit Facility	$	388,000
Less: Successor Revolving Credit Facility fees and debt issuance costs	(8,574)
Total Debt	$	379,426

The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of December 11, 2019 (in thousands):


	12/11/2019
Enterprise Value	$	769,033
Plus: Cash and cash equivalents	16,563
Plus: Current and Other Liabilities (Excluding Post-Reorg. Debt and ARO)	126,460
Plus: Asset Retirement Obligation	$	152,186
Reorganization Value of Successor Assets	$	1,064,242

Reorganization Value and Enterprise Value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh-start

accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets and liabilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	As of December 11, 2019
			Reorganization Adjustments			Fresh-Start Adjustments
(in thousands)	Predecessor										Successor
ASSETS
Current assets:
Cash	$	7,187	$	9,376	(1)	$	—		$	16,563
Restricted cash	3,450		23,936		(1)	—			27,386
Accounts receivable, net:
Oil and natural gas	63,672		—			—			63,672
Joint interest owners	13,213		—			—			13,213
Other	2		—			—			2
Fair value of derivatives	—		—			—			—
Prepaid expenses and other current assets	10,465		—			—			10,465
Total current assets	$	97,989	$	33,312		$	—		$	131,301
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting	3,565,631		—			(2,918,997)		(10)	646,634
Unproved properties	20,244		—			259,759		(10)	280,003
Accumulated depletion, depreciation, amortization and impairment	(2,424,454)		—			2,424,454		(10)	—
Total oil and natural gas properties, net	$	1,161,421	$	—		$	(234,784)		$	926,637
Other property and equipment, net of accumulated depreciation and amortization	5,949		—			235		(10)	6,184
Operating rights, net of amortization	574		—			(545)		(11)	29
Fair value of derivatives	91		—			—			91
Other assets	—		—			—			—
Investments in equity method investees	—		—			—			—
Total assets	$	1,266,024	$	33,312		$	(235,094)		$	1,064,242

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current debt, net	$	596,000	$	(596,000)	(2)	$	—		$	—
Accounts payable	5,350		2,875		(5)	—			8,225
Accrued oil and natural gas liabilities	63,965		—			—			63,965
Fair value of derivatives	4,749		—			—			4,749
Asset retirement obligation	3,938		—			801		(12)	4,739
Other	50,223		(4,916)		(3)	—			45,307
Total current liabilities	$	724,225	$	(598,041)		$	801		$	126,985
Long-term debt	—		379,426		(6)	—			379,426
Asset retirement obligation	257,984		—			(110,537)		(12)	147,447
Fair value of derivatives	2,118		—			—			2,118
Other long-term liabilities	2,096		—			—			2,096
Total liabilities not subject to compromise	986,423		(218,615)			(109,736)			658,072
Liabilities subject to compromise	789,802		(789,802)		(4)	—			—
Total liabilities	$	1,776,225	$	(1,008,417)		$	(109,736)		$	658,072

Stockholders' equity (deficit):
Common stock (Predecessor)	1,148		(1,148)		(7)	—			—
Common stock (Successor)	—		611		(8)	—			611
Additional paid-in capital (Predecessor)	43,197		(43,197)		(7)	—			—
Additional paid-in capital (Successor)	—		405,559		(8)	—			405,559
Accumulated deficit	(554,546)		679,904		(9)	(125,358)		(13)	—
Total stockholders’ deficit	(510,201)		1,041,729			(125,358)			406,170
Total liabilities and stockholders' equity	$	1,266,024	$	33,312		$	(235,094)		$	1,064,242

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Reorganization Adjustments

1.Reflects the net cash payments recorded as of the Effective Date from implementation of the Plan (in thousands):


Proceeds from Backstop Commitments and Rights Offering	$	256,300
Borrowings under Successor Revolving Credit Facility	388,000
Payment of Predecessor Credit Facility	(313,000)
Payment of Interest under Predecessor Credit Facility	(5,623)
Payment of Predecessor DIP Claims	(283,000)
Payment of Interest and Fees under Predecessor DIP Claims	(791)
Payment of Successor Revolving Credit Facility fees and debt issuance costs	(8,574)
Funding of Professional Fees Escrow Account	(23,936)
Changes in Cash	$	9,376

2.Reflects the repayment of outstanding borrowings under the Predecessor Credit Facility of approximately $313.0 million and the repayment of the DIP Credit Agreement balance of $283.0 million. See Note 5, "Debt" for more information about the DIP Credit Agreement.

3.Reflects payment of accrued interest under Predecessor Credit Facility of $4.9 million.

4.Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):


Debt	$	757,449
Accrued Interest Payable	29,478
Accounts Payable	2,875
Total Liabilities Subject to Compromise	789,802
Reinstatement of Liability for the General Unsecured Claims	(2,875)
Fair Value of Equity Issued to Former Holders of the Senior Notes, Bonds, and Second Lien	(149,870)
Gain on Settlement of Liabilities Subject to Compromise	$	637,057

5.Reflects reinstatement of payables for the general unsecured claims.

6.Reflects the $379.4 million in net new borrowings under the Successor Revolving Credit Facility.

7.Reflects the cancellation of the Predecessor company equity to accumulated deficit.

8.Represents backstop commitments and rights offering totaling $256.3 million and fair value of equity issue to former holders of the Senior Notes, Bonds, and Second Lien Term Loan totaling $149.9 million.

9.Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):


Gain on Settlement of Liabilities Subject to Compromise	$	637,057
Other Adjustments	(1,498)
Cancellation of Predecessor company equity	44,345
Net impact to accumulated deficit	$	679,904

Fresh Start Adjustments

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

10.The following table summarizes the fair value adjustment on our oil and gas properties and accumulated depletion, depreciation and amortization (in thousands):


			Fresh-Start Adjustments
	Predecessor						Successor
Oil and Gas Properties
Proved properties	$	3,565,631	$	(2,918,997)	$	646,634
Unproved properties	20,244		259,759		280,003
Total Oil and Gas Properties	3,585,875		(2,659,238)		926,637
Less - Accumulated depletion, depreciation and impairment	(2,424,454)		2,424,454		—
Net Oil and Gas Properties	1,161,421		(234,784)		926,637
Furniture, Fixtures, and other equipment	18,782		(12,598)		6,184
Less - Accumulated depreciation	(12,833)		12,833		—
Net Furniture, Fixtures and other equipment	5,949		235		6,184
Net Oil and Gas Properties, Furniture and fixtures and accumulated depreciation	$	1,167,370	$	(234,549)	$	932,821

11.Reflects the adjustment of operating rights to fair value.

12.Primarily reflects the fair value adjustment of asset retirement obligations ("ARO") to fair value of approximately $152.2 million, of which $147.4 million is reflected as long-term ARO and $4.7 million of current ARO. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plus and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. Refer to Note 14, "Asset Retirement Obligations" for further detail of the Company's asset retirement obligations.

13.Reflects the cumulative impact of fresh start adjustments as discussed above.

Reorganization Items

Reorganization items represent (i) expenses or income incurred subsequent to June 18, 2019 (the "Petition Date") as a direct result of the confirmed Plan, (ii) gain or losses from liabilities settled and (iii) fresh-start accounting adjustments and are recorded in "Reorganization items" in the Company's unaudited Consolidated Statement of Operations. The following table summarizes reorganization items (in thousands):


	Successor		Predecessor
	Period from December 11, 2019 to December 31, 2019		Period from January 1, 2019 to December 10, 2019


Gain on settlement of liabilities subject to compromise	$	—	$	(637,057)
Fresh start accounting adjustments	—		125,358
Reorganization legal and professional fees and expenses	—		63,798


Reorganization items	$	—	$	(447,901)

(3) Summary of Significant Accounting Policies

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

Unless the context requires otherwise or unless otherwise noted, all references to “Legacy Reserves,” “Legacy Inc.,” “Legacy,” the “Company,” “we,” “us,” “our” or like terms are to Legacy Reserves Inc. and its subsidiaries for the periods after

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.

(b) Corporate Reorganization

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

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

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

The Corporate Reorganization was accounted for under ASC 805 as a combination of entities under common control. As such, the assets and liabilities of the Partnership were recognized at their carrying values in Legacy Inc.

Accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 13, "Sales to Major Customers").

(d) Oil and Natural Gas Properties

Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.

Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer,

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LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 14, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates.

Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the period of January 1, 2019 through December 10, 2019 (Predecessor), Legacy recognized $105.5 million of impairment expense in 20 separate producing fields, due primarily to the further decline in oil and natural gas futures prices, increased expenses and well performance during the period ended December 10, 2019 (Predecessor), which decreased the expected future cash flows below the carrying value of the assets. For the year ended December 31, 2018 (Predecessor), Legacy recognized $58.7 million of impairment expense, in 50 separate producing fields, due primarily to the further decline in oil and natural gas futures prices, increased expenses and well performance during the year ended December 31, 2018 (Predecessor), which decreased the expected future cash flows below the carrying value of the assets. For the year ended December 31, 2017(Predecessor), Legacy recognized $37.3 million of impairment expense, in 47 separate producing fields, due primarily to further decline in oil and natural gas futures prices, increased expenses and well performance during the year ended December 31, 2017 (Predecessor), which decreased the expected future cash flows below the carrying value of the assets.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. NaN unproved impairment was recognized for the period December 11, 2019 through December 31, 2019 (Successor) or for the period of January 1, 2019 through December 10, 2019 (Predecessor). Legacy recognized $9.3 million of impairment of unproven properties during the year ended December 31, 2018 (Predecessor). Legacy did 0t recognize impairment expense on unproved properties during the years ended December 31, 2017 (Predecessor). We expect to recognize impairments to our oil and natural gas properties in 2020 as a result of the COVID-19 pandemic and the disruption to the oil market.

(e) Oil, NGLs and Natural Gas Reserve Quantities

Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with the Securities and Exchange Commission ("SEC") rules and accounting standards.

Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

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Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered.

(f) Income Taxes

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

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

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2019, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Please see Note 17, "Income Taxes" for more information on Legacy's accounting for income taxes.

(g) Derivative Instruments and Hedging Activities

Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Note 11, "Fair Value Measurements" and Note 12, "Derivative Financial Instruments").

(h) Use of Estimates

Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, impairment of oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues.

(i) Revenue Recognition

On January 1, 2018, Legacy adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition applied to all contracts. ASU 2014-09 created ASC 606, Revenue from Contracts with Customers (ASC 606).

Legacy enters into contracts with customers to sell its produced oil, natural gas and NGLs. Revenue attributable to these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when Legacy’s performance obligations under these contracts are satisfied, which generally occurs when control of the oil, natural gas and NGLs transfers to the purchaser and collectability is reasonably assured. Given the nature of Legacy’s products sold, Legacy has concluded that control transfers to its customers at a point in time. In accordance with ASC 606, Legacy considers the following indicators of the transfer of control to determine the point in time at which control transfers to its customers: (i) Legacy has a present right to payment for the asset; (ii) the customer has legal title to the asset;

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(iii) Legacy has transferred physical possession of the asset; and (iv) the customer has the significant risks and rewards of ownership.

Oil Sales

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

Natural Gas and NGL Sales

Under Legacy's gas processing contracts, Legacy delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to Legacy for the resulting sales of NGLs and residue gas. Under this contract structure, Legacy has determined that the midstream processing entity represents Legacy’s customer, and, consequently, Legacy recognizes revenue when control transfers to the midstream processing entity upon delivery. The amount of revenue recognized is based on the net amount of the proceeds received from the midstream processing entity, which is generally tied to the prevailing index prices for residue gas and NGLs less deductions for gathering, processing, transportation and other expenses.

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

Estimation

To the extent actual product volumes and related prices are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. See Note 6, "Revenue from Contracts with Customer" for additional information.

Imbalances

Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of the period December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the year ended December 31, 2018 (Predecessor), and the year ended December 31, 2017 (Predecessor).

(j) Investments

Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition.

(k) Environmental

Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.

(l) Earnings (Loss) Per Share

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Basic income (loss) per share amounts are calculated using the weighted average number of shares outstanding during each period. Diluted income (loss) per share also gives effect to dilutive unvested restricted shares (calculated based upon the treasury stock method) (see Note 15, "Stockholders' Deficit/Unitholders' Deficit"). In accordance with ASC 805, income (loss) per share amounts for historical periods have been recomputed to reflect shares issued in the Corporate Reorganization.

(m) Segment Reporting

Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes.

(n) Share-Based Compensation

Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“Legacy LP LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises unit appreciation rights ("UARs") and certain phantom unit awards, Legacy accounted for these awards under the liability method, which requires Legacy to recognize the fair value of each unit award at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounted for executive phantom unit and restricted unit awards under the equity method. Pursuant to the terms of the Corporate Reorganization, the Legacy LP LTIP was terminated. On September 19, 2018, the Legacy Inc. 2018 Omnibus Incentive Plan (the "Legacy Inc, LTIP") was approved by the former unitholders of Legacy LP in connection with the Corporate Reorganization.

(o) Accrued Oil and Natural Gas Liabilities

Below are the components of accrued oil and natural gas liabilities as of the period December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor).


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Year ended December 31,
(In thousands)	2019		2018
Revenue payable to joint interest	21,103		22,750
Accrued lease operating expense	20,713		41,227
Accrued capital expenditures	8,880		24,690
Accrued ad valorem tax	5,723		5,255
Other	4,757		4,964
	$	61,176	$	98,886

(p) Restricted Cash

Restricted cash of $24.0 million, $28.5 million and $3.3 million as of the period December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor) and December 31, 2018 (Predecessor), respectively, is recorded in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent funding of an escrow account for the payment of future professional fees incurred in our Chapter 11 bankruptcy reorganization process at December 10, 2019 (Predecessor) as well as various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business.

(q) Prior Year Financial Statement Presentation

Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in these consolidated financial statements.

(r) Recent Accounting Pronouncements

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In February 2016, the FASB issued ASU No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms at commencement longer than twelve months. The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized an ROU asset and a lease liability, with the cumulative-effect of adoption in retained earnings in the amount of $255,916, as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:

•Whether any expired or existing contracts were or contained leases;

•The lease classification for any expired or existing leases; and

•Initial direct costs for any existing leases.

Nature of Leases

Corporate and Field Offices

Compressors

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

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Drilling Rigs

Other Production Equipment

Fleet Vehicles

(4) Fair Values of Financial Instruments

The estimated fair values of Legacy’s financial instruments approximate the carrying amounts except as discussed below:

Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings.

Derivatives. See Note 12, "Derivative Financial Instrument" for discussion of process used in estimating the fair value of commodity price and interest rate derivatives.

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(5) Debt

Debt consists of the following at December 31, 2019 (Successor) and the year ended December 31, 2018 (Predecessor):


	Successor		Predecessor
	Year ended December 31,		Year ended December 31,
(In thousands)	2019		2018
Current debt
Credit Facility due 2019	$	—	$	541,000
Second Lien Term Loans due 2020	—		338,626
Unamortized debt issuance costs	—		(17,332)
Unamortized discount on Second Lien Term Loans	—		(5,648)
Total current debt, net	$	—	$	856,646

Long-term debt
Successor Revolving Credit Facility	$	378,000	$	—
8% Senior Notes due 2020	—		208,885
6.625% Senior Notes due 2021	—		131,279
8% Convertible Senior Notes due 2023	—		128,103
	$	378,000	$	468,267
Unamortized discount on Second Lien Term Loans and Senior Notes	—		(31,517)
Unamortized debt issuance costs	(8,451)		(3,827)
Total long-term debt, net	$	369,549	$	432,923
Total debt, net	$	369,549	$	1,289,569

Successor Credit Facility

On the Effective Date, Legacy entered into a credit agreement (the “Credit Agreement”) among Legacy, as borrower, the lenders from time to time party thereto, and Wells Fargo Bank, National Association, as the administrative agent, the collateral agent and the issuing bank. Pursuant to the Credit Agreement, the lenders party thereto agreed to provide a new reserves-based revolving credit facility (the “Successor Revolving Credit Facility”) with initial aggregate commitments in the amount of $1.5 billion, subject to a borrowing base. The initial borrowing base under the Credit Agreement is $460 million.

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The Credit Agreement contains customary representations and warranties and also customary affirmative and negative covenants, in each case for credit facilities of this nature, including restrictions on the incurrence of indebtedness, liens, fundamental changes, asset sales, investments, dividends, redemptions, repayments of other debt and hedge agreements. Additionally, Legacy is required as of the last day of any fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, to maintain (a) a maximum total net leverage ratio of 3.50 to 1.00 and (b) a minimum current ratio of 1.00 of 1.00. Additionally, the Credit Agreement contains customary events of default and remedies for credit facilities of this nature, including non-payment, breaches of representations and warranties, non-compliance with covenants or other agreements, bankruptcy, ERISA, failure of the loan documents to be in full force and effect, judgments and change of control. As of December 31, 2019 (Successor), Legacy was in compliance with all financial and other covenants of the Credit Agreement.

Predecessor DIP Credit Agreement

On June 21, 2019, in connection with the Chapter 11 Cases, Legacy LP entered into the DIP Credit Agreement. The DIP Credit Agreement provided for a senior secured priming superpriority debtor-in-possession revolving loan credit facility in an aggregate principal amount of up to $350 million, consisting of (i) a new money revolving loan facility in an aggregate amount of up to $100 million (the “New Money Facility”), and (ii) a refinancing term loan in the amount of $250 million (the “Refinancing Facility”). Borrowings under the (i) New Money Facility beared interest, at the option of the Company, at a rate per annum equal to the alternate base rate (the “ABR”) plus 4.25% or LIBOR plus 5.25% and (ii) the Refinancing Facility beared interest at a rate per annum equal to the ABR plus 3.50%. The Company was required to pay an unused commitment fee equal to 1.00% per annum to the lenders under the New Money Facility in respect of the unused commitments thereunder. Upon the occurrence of the Effective Date, the DIP Credit Agreement was terminated in accordance with the Plan. See Note 1 for more information regarding the termination of the DIP Credit Agreement.

Predecessor Credit Facility

On April 1, 2014, Legacy LP entered into a five years $1.5 billion Prepetition RBL Credit Agreement, which provided a reserves-based credit facility (the "Predecessor Credit Facility"). On March 21, 2019, the maturity of the Prepetition RBL Credit Agreement was extended from April 1, 2019 to May 31, 2019. Legacy's obligations under the Prepetition RBL Credit Agreement were secured by mortgages on over 95% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries and Legacy's ownership interests in the General Partner. Concurrently with the Corporate Reorganization, the General Partner and Legacy Inc. provided guarantees of Legacy LP's obligations under the Prepetition RBL Credit Agreement. The borrowing base was subject to semi-annual redeterminations on or about April 1 and October 1 of each year, and the Prepetition RBL Credit Agreement matured on May 31, 2019.Upon the occurrence of the Effective Date, the Prepetition RBL Credit Agreement was terminated in accordance with the Plan. See Note 1 for more information regarding the termination of the Prepetition RBL Credit Agreement.

Predecessor Second Lien Term Loans

On October 25, 2016, Legacy entered into the Term Loan Credit Agreement, initially providing for term loans up to an aggregate principal amount of $300 million (the “Second Lien Term Loans”). The Term Loan Credit Agreement was scheduled to mature on August 31, 2021; provided that, if on July 1, 2020, Legacy had greater than or equal to a face amount of $15.0 million of Senior Notes that were outstanding on the date the Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Term Loan Credit Agreement was to mature on August 1, 2020. The Second Lien Term Loans were secured on a second lien priority basis by the same collateral that secured the Predecessor Credit Agreement and were unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that were guarantors under the Credit Agreement. In addition, upon consummation of the Corporate Reorganization, the General Partner and Legacy Inc. became guarantors. On December 31, 2017, the Term Loan Credit Agreement was amended, which, among other things, increased the maximum amount available for borrowing under the Second Lien Term Loans to $400 million. Upon the occurrence of the Effective Date, the Term Loan Credit Agreement was terminated in accordance with the Plan. See Note 1 for more information regarding the termination of the Term Loan Credit Agreement.

Predecessor 8% Senior Notes Due 2020

On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of Legacy's 8% Senior Notes due 2020 (the "2020 Senior Notes" and, together with the 2021 Senior Notes, the “Senior Notes”), which were

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subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. Interest was payable on June 1 and December 1 of each year.

Legacy and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes were guaranteed by its 100% owned subsidiaries.

In connection with the exchange of approximately $21.0 million aggregate principal amount of 2020 Senior Notes for the same aggregate principal of the 2023 Convertible Notes and the issuance of 105,020 shares of Common Stock in September 2018, Legacy recognized a $1.4 million gain on extinguishment of debt, which consisted of the difference between (1) the face amount of the exchanged 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the new 2023 Convertible Notes.

During the year ended December 31, 2018 (Predecessor), Legacy exchanged 1,000,000 shares of Common Stock for $3.1 million of face amount of its outstanding 2020 Senior Notes. Legacy treated the exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on the date of exchange.

Upon the occurrence of the Effective Date, the 2020 Senior Notes were terminated in accordance with the Plan. See Note 1 for more information regarding the termination of the 2020 Senior Notes.

Predecessor 6.625% Senior Notes Due 2021

On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250.0 million of Legacy's 6.625% Senior Notes due 2021 (the "2021 Senior Notes"), which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par. Interest was payable on June 1 and December 1 of each year.

On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300.0 million of the 6.625% 2021 Senior Notes. These 2021 Senior Notes were issued at 99% of par.

The terms of the 2021 Senior Notes, including details related to Legacy's guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the maturity date, interest rate and redemption provisions Legacy and Legacy Reserves Finance Corporation's obligations under the 2021 Senior Notes were guaranteed by the same parties and on the same terms as Legacy's 2020 Senior Notes discussed above.

For the period of January 1, 2019 through December 10, 2019 (Predecessor), $1.75 million of 2021 Senior Notes were exchanged for 593,367 shares of common stock. Legacy treated the exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of shares issued in the exchange based on the closing price on the date of exchange.

On September 20, 2018, in connection with the exchange of approximately $109.0 million aggregate principal amount of 2021 Senior Notes for the same aggregate principal of the 2023 Convertible Notes, Legacy recognized a $10.7 million gain on extinguishment of debt, which consisted of the difference between (1) the face amount of the exchanged 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the new 2023 Convertible Notes.

During the year ended December 31, 2018 (Predecessor), Legacy exchanged 2,000,000 shares of Common Stock for $5.3 million of face amount of its outstanding 2020 Senior Notes. Legacy treated the exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on the date of exchange.

On December 31, 2017 (Predecessor), Legacy entered into an agreement to repurchase a face amount of $187.0 million of its 2021 Senior Notes from certain holders in a single transaction. The transaction was funded on January 5, 2018 and was therefore recognized in 2018. Legacy treated this repurchase as an extinguishment of debt. Accordingly, Legacy recognized

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a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.

Upon the occurrence of the Effective Date, the 2021 Senior Notes were terminated in accordance with the Plan. See Note 1 for more information regarding the termination of the 2021 Senior Notes.

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

On September 20, 2018, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation (together, the “Issuers”), completed private exchanges with certain holders of senior notes, pursuant to which the Issuers exchanged (i) $21.0 million aggregate principal amount of 2020 Senior Notes for $21.0 million aggregate principal amount of 2023 Convertible Notes and 105,020 shares of common stock and (ii) $109.0 million aggregate principal amount of 2021 Senior Notes for $109.0 million aggregate principal amount of 2023 Convertible Notes. The 2023 Convertible Notes were issued pursuant to an Indenture, dated as of September 20, 2018 (the “2023 Convertible Note Indenture”). Interest was payable on June 1 and December 1 of each year.

Upon issuance, the Company separately accounted for the liability and equity components in accordance with Accounting Standards Codification 470-20. The initial fair value of the 2023 Convertible Notes in its entirety (inclusive of the equity component related to the conversion option) was estimated using observable inputs such as trades that occurred on the day of the transaction. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the aggregate principal amount of the 2023 Convertible Notes and the fair value of the liability component was recorded as a debt discount and is being amortized to interest expense over the term of the notes using the effective interest method. The fair value of the liability component of the 2023 Convertible Notes was estimated at $101.0 million, resulting in a debt discount of $29.0 million The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial fair value of the 2023 Convertible Notes. The equity component was recorded in additional paid-in capital within stockholders’ equity.

The 2023 Convertible Notes were to mature September 20, 2023, unless earlier repurchased or redeemed by the Issuers or converted. The 2023 Convertible Notes were subject to redemption for cash, in whole or in part, at the Issuers’ option at a redemption price equal to 100% of the 2023 Convertible Notes to be redeemed, plus any accrued and unpaid interest. In addition, the Issuers would have been required to make an offer to holders of the 2023 Convertible Notes upon a change of control at a price equal to 101%, plus any accrued and unpaid interest, and an offer to holders of the 2023 Convertible Notes upon consummation by the Issuers or any restricted subsidiaries of certain asset sales at a price equal to 100%, plus any accrued and unpaid interest.

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

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


Early Conversion Date						Early Conversion Payment
December 1, 2018 through May 31, 2019..............................................................................................................						$64.22
June 1, 2019 through September 19, 2019..............................................................................................................						$24.22

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

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

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

For the period of January 1, 2019 through December 10, 2019 (Predecessor), certain holders of the 2023 Convertible Notes exercised their option to convert $6.5 million of 2023 Convertible Notes in exchange for 2.4 million shares of common stock and $14.1 million of face amount of 2023 Convertible Notes in exchange for 2.3 million shares of common stock. Upon the occurrence of the Effective Date, the 2023 Convertible Notes were terminated in accordance with the Plan. See Note 1, "Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code" for more information regarding the termination of the 2023 Convertible Notes.

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(6) Revenue from Contracts with Customers

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

Oil Sales

NGL and Natural Gas Sales

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

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

Imbalances

Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions for the period December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the year ended December 31, 2018 (Predecessor), and the year ended December 31, 2017 (Predecessor).

Disaggregation of Revenue

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


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,
(In thousands)	2019		2019
Revenues:
Oil sales	$	23,232	$	300,905
Natural gas liquids (NGL) sales	916		14,082
Natural gas sales	6,016		101,488
Total revenues	$	30,164	$	416,475

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Significant Judgments

Principal versus agent

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

Transaction price allocated to remaining performance obligations

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

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

Contract balances

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

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

Prior-period performance obligations

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

Legacy records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Legacy has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the period December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), revenue recognized related to performance obligations satisfied in prior reporting periods was 0t material.

(7) Asset Acquisitions and Dispositions

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

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During the year ended December 31, 2018 (Predecessor), Legacy divested certain individually immaterial oil and natural gas assets for net cash proceeds of $55.0 million. These dispositions were treated as asset sales and resulted in a gain on disposition of assets of $23.8 million during the period.

(8) Related Party Transactions

Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which former Legacy director Cary D. Brown is a principal. Legacy has contracted with Blue Quail to provide water transfer services and paid $18,157, $37,008, $169,949 and $9,758 for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the year ended December 31, 2018 (Predecessor) and the year ended December 31, 2017 (Predecessor), respectively, to Blue Quail for such services.

(9) Commitments and Contingencies

From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows.

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

Legacy has employment agreements with its officers. The employment agreements with its officers specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 12 to 36 months' salary plus bonus and COBRA benefits, respectively.

(10) Business and Credit Concentrations

Cash

Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash.

Revenue and Accounts Receivable

Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. NaN bad debt expense was recorded for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the year ended December 31, 2018 (Predecessor) and the year ended December 31, 2017 (Predecessor). Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 13, "Sales to Major Customers".

Commodity Derivatives

Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, collars and enhanced swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. Legacy values these transactions at fair value on a recurring basis (Note 12, "Derivative Financial Instrument"). As of December 31, 2019 (Successor), Legacy’s commodity derivative transactions have a fair value unfavorable to the Company of $(13.1) million, collectively. Legacy enters into commodity derivative transactions with entities which Legacy's management believes are creditworthy. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis.

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(11) Fair Value Measurements

Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:


Level 1:			Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:			Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and collars and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date.
Level 3:			Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 (Successor) and 2018 (Predecessor):


	December 31, 2019 (Successor)
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair Value		Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts Presented in the Consolidated Balance Sheets
Description	(Level 1)		(Level 2)		(Level 3)
	(In thousands)
Assets:
Current
Commodity derivatives	$	—	$	3,006	$	—	$	3,006	$	(2,438)	$	569

Noncurrent
Commodity derivatives	—		1,851		—		1,851		(1,851)		—


Liabilities:
Current
Commodity derivatives	—		(12,660)		—		(12,660)		2,438		(10,223)
Noncurrent
Commodity derivatives	—		(5,342)		—		(5,342)		1,851		(3,491)
	$	—	$	(13,145)	$	—	$	(13,145)	$	—	$	(13,145)

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	December 31, 2018 (Predecessor)
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair Value		Gross Amounts Offset in the Consolidated Balance Sheets		Net Amounts Presented in the Consolidated Balance Sheets
Description	(Level 1)		(Level 2)		(Level 3)
	(In thousands)
Assets:
Current
Commodity derivatives	$	—	$	69,288	$	—	$	69,288	$	(4,670)	$	64,618
Interest rate derivatives	—		2,044		—		2,044		—		2,044
Noncurrent
Commodity derivatives	—		3,473		—		3,473		(338)		3,135
Interest rate derivatives	—		—		—		—				—

Liabilities:
Current
Commodity derivatives	—		(4,670)		—		(4,670)		4,670		—
Interest rate derivatives	—		—				—		—		—
LTIP liability	—		—		—		—				—
Noncurrent
Commodity derivatives	—		(888)		—		(888)		338		(550)
Interest rate derivatives	—						—				—
	$	—	$	69,247	$	—	$	69,247	$	—	$	69,247

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

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


	Significant Unobservable Inputs (Level 3)
	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,		December 31,
(In thousands)	2019		2019		2018			2017
Beginning balance	$	—	$	—	$	(5,088)		$	8
Total gains (losses)	—		—		30,571			(5073)
Settlements	—		—		(22,379)			(23)
Transfers	—		—		(3,104)		(a)	—
Ending balance	$	—	$	—	$	—		$	(5,088)
Gains (losses) included in earnings relating to derivatives	$	—	$	—	$	—		$	(5,088)

____________________

(a)Due to the lack of a historical market, we have historically accounted for our Midland-to-Cushing crude oil differential swaps as Level 3. However, with recent widening differentials, an active market has been created in which quoted prices are readily observable. As such, we determined that the inputs used to value these derivatives classify as Level 2 and transferred the value of the derivatives into Level 2 during 2018.

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

Fair Value on a Non-Recurring Basis

On the Effective Date, the Company emerged from the Chapter 11 Cases and adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date, December 11, 2019. See Note 2, “Fresh-start Accounting,” for a detailed discussion of the fair value approaches used by the Company.

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These ARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these measurements as Level 3. A reconciliation of the beginning and ending balances of Legacy’s ARO is presented in Note 14, "Asset Retirement Obligation."

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Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2019 (Successor) and 2018 (Predecessor) consist of impairment of the carrying value oil and natural gas properties to their fair value of $148.5 million and $43.9 million, respectively. Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. For the period December 11, 2019 through December 31, 2019 (Successor), Legacy did 0t recognize any impairment. During the period January 1, 2019 through December 10, 2019 (Predecessor), Legacy incurred impairment charges of $105.5 million as oil and natural gas properties with a net cost basis of $254.0 million were written down to their fair value of $148.5 million. During the year ended December 31, 2018 (Predecessor), Legacy incurred impairment charges of $58.7 million as oil and natural gas properties with a net cost basis of $102.6 million were written down to their fair value of $43.9 million. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

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(12) Derivative Financial Instruments

Commodity derivative transactions

Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps and enhanced swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.

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

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

The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), for the years ended December 31, 2018 (Predecessor), and 2017 (Predecessor).


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,		December 31,
	2019		2019		2018		2017
(In thousands)
Beginning fair value of commodity derivatives	$	(6,776)	$	67,205	$	6,318	$	12,698
Total gain (loss) crude oil derivatives	(7,477)		(48,146)		54,380		(15,325)
Total gain (loss) natural gas derivatives	1,185		(2,148)		(5,208)		33,101
Crude 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)
Ending fair value of commodity derivatives	$	(13,144)	$	(6,776)	$	67,205	$	6,318

As of December 31, 2019, Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:


Calendar Year	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
2020	3,660,000	$55.62	$54.10	-	$56.00
2021	2,555,000	$52.80	$52.40	-	$53.22

As of December 31, 2019, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:


Calendar Year	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
2020	732,000	$0.90	$0.90
2021	730,000	$1.05	$1.05

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As of December 31, 2019, Legacy had the following NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:


		Average	Price Range
Calendar Year	Volumes (MMBtu)	Price per MMBtu	per MMBtu
2020	32,940,000	$2.35	$2.32	-	$2.40
2021	29,200,000	$2.41	$2.37	-	$2.44

Interest rate derivative transactions

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

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


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,		Years Ended December 31,
	2019		2019		2018		2017
(In thousands)
Beginning fair value of interest rate swaps	$	—	$	2,044	$	2,117	$	183
Total gain (loss) loss on interest rate swaps	—		(119)		1,213		1,168
Cash settlements paid	—		(1,925)		(1,286)		766
Ending fair value of interest rate swaps	$	—	$	—	$	2,044	$	2,117

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(13) Sales to Major Customers

For the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the years ended December 31, 2018 (Predecessor), 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 December 11, 2019 to December 31, 2019 (Successor).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(14) Asset Retirement Obligation

An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period in which it is incurred and becomes determinable. When liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the additions to the ARO asset and liability is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by Legacy's management at the time of the valuation and are the most sensitive and subject to change. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon Legacy’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using Legacy’s credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. When obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from Legacy's balance sheet. Any difference in the cost to plug and the related liability is recorded as a gain or loss on Legacy's statement of operations in the disposal of assets line item. Upon the Company's emergence from bankruptcy on December 11, 2019, as discussed in Note 1, "Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code," the Company applied fresh-start accounting. This included adjusting the Asset Retirement Obligations based on the estimated fair values at the Effective Date.

The following table reflects the changes in the ARO during the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the years ended December 31, 2018 (Predecessor) 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
(In thousands)
Asset retirement obligation — beginning of period	$	152,186	$	252,734	$	274,686	$	272,148
Liabilities incurred with properties acquired	—		—		226		62
Liabilities incurred with properties drilled	—		30		65		39
Liabilities settled during the period	(79)		(2,891)		(2,258)		(1,891)
Liabilities associated with properties sold	(244)		(243)		(27,673)		(8,464)
Current period accretion	630		12,292		12,568		12,792
Current period revisions to previous estimates	—		—		(4,880)		—
Fresh-start adjustment	$	—	(109,736)		—		—
Asset retirement obligation — end of period	$	152,493	$	152,186	$	252,734	$	274,686

Each year Legacy reviews and, to the extent necessary, revises its ARO estimates. For the year ended December 31, 2019 (Successor), no revision of previous estimates were necessary due to adjusting the Asset Retirement Obligation based on the estimated fair values. For the year ended December 31, 2018 (Predecessor), Legacy decreased its estimate of future asset retirement obligations by $4.9 million. For the year ended December 31, 2017 (Predecessor), 0 revision of previous estimates were deemed necessary.

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(15) Stockholders' Deficit / Unitholders' Deficit

Preferred Units

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

Incentive Distribution Units

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

Earnings/(loss) per share / unit

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


	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
(In thousands)
Net Income/(loss)	$	3,050	$	173,876	$	43,833	$	(53,897)
Income/(loss) attributable to shareholders	$	3,050	$	173,876	$	43,833	$	(53,897)
Weighted average number of shares outstanding	61,063		114,811		105,087		100,049
Effect of dilutive securities:
Restricted and phantom units	—		—		—		—
Weighted average units and potential units outstanding	61,063		114,811		105,087		100,049
Basic and diluted income/(loss) per share	$	0.05	$	1.51	$	0.42	$	(0.54)

For the period of December 11, 2019 through December 31, 2019 (Successor) no restricted stock units were excluded from the calculation of diluted earnings per share due to their anti-dilutive effect, as all then existing equity was extinguished on the Effective Date in accordance with the Plan. For the period of January 1, 2019 through December 10, 2019 (Predecessor), 7,647,191 restricted stock units were excluded from the calculation of diluted earnings per share due to their anti-dilutive effect. As of December 31, 2018 (Predecessor), 7,302,809 restricted units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. As of December 31, 2017 (Predecessor), 241,373 restricted units and 1,389,773 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.

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(16) Stock-Based Compensation

Legacy LP Long Term Incentive Plan

On March 15, 2006, a Long-Term Incentive Plan (as amended, “LTIP”) for Legacy was created and Legacy adopted the LTIP for its employees, consultants and directors, its affiliates and its general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights (“UARs”). The LTIP permits the grant of awards that may be made or settled in units up to an aggregate of 5,000,000 units. As of September, 2018 grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 3,459,197 units had been made, comprised of 266,014 unit option awards, 988,207 restricted unit awards, 1,424,114 phantom unit awards and 780,862 unit awards. Pursuant to the terms of the Corporate Reorganization, the Legacy LP long-term incentive plan ("Legacy LP LTIP") was terminated.

Unit Appreciation Rights

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

Legacy did not issue UARs to employees during the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor) or the year ended December 31, 2018 (Predecessor). All outstanding UARs vested on September 20, 2018 in connection with the Corporate Reorganization and were subsequently exercised or forfeited.

As a result of all UARs vesting on September 20, 2018 and no new UARs being issued for the period of December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor), Legacy did not record any compensation (benefit) expense. For the year ended December 31, 2018 (Predecessor), Legacy recorded compensation (benefit) expense of $(169,024), due to the changes in the compensation liability related to the above awards based on its use of the Black-Scholes model to estimate the December 31, 2018 (Predecessor) fair value of these UARs.

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

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A summary of UAR activity for the year ended December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor) is as follows:


	Units	Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding at January 1, 2017 (Predecessor)	884,546	$	20.75
Expired	(147,024)	$	24.50

Forfeited	(15,501)	$	13.91
Outstanding at December 31, 2017 (Predecessor)	722,021	$	20.13	3.29	$	—
UARs exercisable at
December 31, 2017 (Predecessor)	592,522	$	23.23	2.99	$	—
Outstanding at January 1, 2018 (Predecessor)	722,021	$	20.13

Expired	(90,844)	$	4.69
Forfeited	(631,177)	$	22.35
Outstanding at December 31, 2018 (Predecessor)	—	$	—		$	—

Phantom Units

Legacy previously issued phantom units under the Legacy LP LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either 1 Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy accounted for the phantom units settled in Partnership units by utilizing the equity method. Legacy accounted for the phantom units settled in cash by utilizing the liability method. 391,674 Phantom units that settle in cash and 1,032,440 phantom units that settle in units vested on September 20, 2018 in connection with the Corporate Reorganization. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

Compensation expense related to the phantom units was $22.9 million and $4.6 million for the years ended December 31, 2018 (Predecessor) and 2017 (Predecessor), respectively.

Restricted Units

Legacy LP previously issued restricted units to certain employees and members of management. All restricted units vested on September 20, 2018 in connection with the Corporate Reorganization. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

As a result of all restricted units vesting on September 20, 2018, there was no compensation expense related to restricted units for the period of December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor). For the years ended December 31, 2018 (Predecessor) and 2017 (Predecessor), compensation expense related to restricted units was $0.8 million and $1.5 million, respectively.

Board Units

On May 16, 2017, Legacy granted and issued 47,847 units to each of its 6 non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $2.04 at the time of issuance. On May 15, 2018, Legacy granted and issued 12,019 units to 4 non-employee directors who serve on the Board of Directors of Legacy and 6,010 units to 2 non-employee directors of Legacy LP who do not serve on the Board of Directors of Legacy Inc. The value of each unit was $8.69 at the time of issuance. No units were issued in 2019. None of these units were subject to vesting. Legacy recognized the expense associated with the unit grants on the date of grant. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

Legacy Reserves Inc. 2018 Omnibus Incentive Plan

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On September 19, 2018, the Legacy Inc. 2018 Omnibus Incentive Plan (the "Legacy Inc. LTIP") was approved by the former unitholders of Legacy LP in connection with the Corporate Reorganization for it and its affiliates' employees, consultants and directors. The Legacy Inc. LTIP provides for up to 10,500,000 shares (the "Share Reserve") to be used for awards, and that the Share Reserve will increase proportionately by 10% of all shares of common stock issued by Legacy Inc. after the effective date of the Legacy Inc. LTIP and before the first anniversary of the effective date. The awards under the Legacy Inc. LTIP may include stock grants, restricted stock, restricted stock units and stock options. For the period of January 1, 2019 through December 10, 2019 (Predecessor), grants of awards net of forfeitures covering 549,164 shares had been made, compromised of 516,594 restricted stock units and 32,570 stock awards. Upon the occurrence of the Effective Date, the Legacy Inc. LTIP was terminated and all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

Restricted Stock Units

For the period of December 11, 2019 through December 31, 2019 (Successor), no restricted stock units ("RSUs") were issued to either executive or non-executive employees. For the period of January 1, 2019 through December 10, 2019 (Predecessor), Legacy issued an aggregate 516,594 RSUs to both executive and non-executive employees. The RSUs vest generally over a three or four-year period. Compensation expense related to the RSUs was $14.8 million for the period of January 1, 2019 through December 10, 2019 (Predecessor). There was no compensation expense related to RSUs for the period of December 11, 2019 through December 31, 2019 (Successor). RSUs are accounted for under the equity method. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

A summary of RSU activity for the period of December 11, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through December 10, 2019 (Predecessor) is as follows:


	Number of Restricted Stock Units	Weighted Average Grant Date Fair Value
Outstanding at January 1, 2019 (Predecessor)	7,302,809	$	4.88
Granted	516,594	$	1.32
Expired	—	$	—
Canceled at December 10, 2019 (Predecessor)	(7,819,403)	$	4.65
Outstanding at December 31, 2019 (Successor)	—	$	—

Board Shares

On September 25, 2018, Legacy granted and issued 5,030 shares to 4 non-employee directors who serve on the Board of Directors of Legacy in accordance with Legacy's director compensation policy. The value of each share was $4.97 at the time of issuance. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

On October 16, 2018, Legacy granted and issued 12,450 shares to 1 non-employee director who serves on the Board of Directors of Legacy in accordance with Legacy's director compensation policy. The value of each share was $5.02 at the time of issuance. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan. See Note 1 for more information.

(17) Income Taxes

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) was enacted into law. The provisions of the Tax Act that impact Legacy include, but are not limited to, (1) reducing the U.S. federal corporate income tax rate from 35.0% to 21.0%, (2) full expensing of certain qualified property acquired after September 27, 2017, (3) limitations on the maximum deduction for net operating loss (NOL) as well as indefinite life carryforwards for tax years beginning after December 31, 2017 and (4) limitations on the maximum deduction for net business interest expense in tax years beginning after December 31, 2017. Legacy has previously recorded all amounts for the income effects of the Tax Act as of December 31, 2017.

On June 18, 2019, Legacy and certain of its subsidiaries commenced voluntary cases under chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. On November 15, 2019, the Bankruptcy Court entered an order confirming the Plan, and on December 11, 2019 the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.Pursuant to the Plan, certain obligations of the Debtors were extinguished. Absent an exception, a debtor recognizes CODI upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Tax Code provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the Plan. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from the Chapter 11 Cases, the amount of CODI realized was approximately $640 million, which reduced the Company’s U.S. NOL carryovers of $195 million to 0, and further reduced the Company’s tax basis in producing properties (subject to future recovery through tax DD&A deductions) by $445 million.

For the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the years ended December 31, 2018, and 2017 (Predecessor) the effective income tax rates were 0.21%, 0.06%, 6.3% and (2.7)%, respectively. For the year ended December 31, 2019 (Successor), our effective tax rate differed from the statutory rate primarily due to non-deductible executive compensation and the valuation allowance. For the period of January 1, 2019 through December 10, 2019 (Predecessor), our effective rate differed from the statutory rate primarily due to non-deductible debt restructuring expenses and the valuation allowance. For the twelve months ended December 31, 2018 (Predecessor), our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax, the 2023 Convertible Notes issuance, Texas margins tax, and the valuation allowance. For the year ended December 31, 2017 (Predecessor), our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax and Texas margins tax.

For the period of December 11, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), the years ended December 31, 2018, and 2017 (Predecessor), we recorded income/(loss) before income taxes of $3.1 million, $174.0 million, $46.8 million and $(52.5) million, respectively. All of Legacy's income is sourced within the United States.

The income tax expense (benefit) consists of:


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

Current:
Federal	$	—	$	1	$	140	$	1,911
State	3		104		(147)		(52)
Total current income tax expense (benefit)	3		105		(7)		1,859
Deferred:
Federal	$	—	$	—	$	1,270	$	(464)
State	—		—		1,705		3
Total deferred income tax expense (benefit)	—		—		2,975		(461)
Total income tax expense	$	3	$	105	$	2,968	$	1,398

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,		Years Ended December 31,
	2019		2019		2018		2017

Tax at federal statutory rate	21.00	%	21.00	%	21.0	%	35.0	%
Partnership loss not subject to federal tax	—	%	—	%	16.6	%	(36.1)	%

Federal rate change	—	%	—	%	—	%	(1.6)	%
Non-Deductible Debt Restructuring Expenses	—	%	8.51	%	—	%	—	%
2023 Convertible Notes issuance	—	%	—	%	7.4	%	—	%
162(m) - Executive Compensation	2.32	%	0.72	%	—	%	—	%
Valuation allowance adjustment	(23.38)	%	(30.98)	%	(44.1)	%	—	%
Texas margins tax	0.21	%	0.06	%	6.1	%	(1.6)	%

Other	0.06	%	0.75	%	(0.7)	%	1.6	%
Effective tax rate	0.21	%	0.06	%	6.3	%	(2.7)	%

Deferred income tax balances representing the tax effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities are as follows:


	Successor		Predecessor
	Year Ended December 31,		Year Ended December 31,
	2019		2018
(In thousands)
Deferred tax assets:
Oil and natural gas properties	$	19,660	$	91,948
Net operating losses	—		12,961
Interest expense	19,074		6,668
Hedging	3,000		—
Other	1,537		—
Total deferred tax assets	43,271		111,577
Deferred tax liabilities
Hedging activities	—		(15,934)
Other	—		(1,585)
Total deferred tax liabilities	—		(17,519)

Valuation allowance	(43,271)		(94,058)

Net deferred tax assets	$	—	$	—

At December 31, 2019, Legacy had a net interest expense carryover of $85 million under Section 163(j) of the Code subject to indefinite carryover. Legacy has recorded a full valuation allowance against the net interest expense carryover and other deferred tax assets because it is probable that these attributes will not be realized.

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In assessing the realizability of net deferred tax assets, Legacy's management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax assets. On the basis of this evaluation, as of December 31, 2019, a full valuation allowance has been recorded as management has determined that it is more likely than not that the net deferred tax asset will not be realized. The full valuation allowance could be adjusted in future periods if objective negative evidence is no longer present and additional weight is given to subjective evidence.

In accordance with the applicable accounting standards, Legacy recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions to identify any material uncertain tax positions, Legacy developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is Legacy’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2019. The tax years 2015 through 2019 remain subject to examination by the major tax jurisdictions.

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(18) Guarantors

Legacy LP's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. Legacy LP's 2021 Senior Notes were issued in 2 separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of Legacy's 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. Legacy LP's 2023 Convertible Notes were issued in exchange for portions of the 2020 Senior Notes and 2021 Senior Notes on September 20, 2018. The 2020 Senior Notes, the 2021 Senior Notes and the 2023 Convertible Notes were guaranteed by Legacy LP's 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services LLC, Legacy Reserves Energy Services LLC, Legacy Marketing LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes, 2021 Senior Notes and the 2023 Convertible Notes, the “Subsidiaries”) as well as Legacy Inc. and the General Partner, as parent guarantors (the "Parent Guarantors"). The Subsidiaries are 100% owned, directly or indirectly, by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions. Legacy LP is 100% owned, directly or indirectly, by the Parent Guarantors and the guarantees by the Parent Guarantors were full and unconditional, except for customary release provisions. Legacy LP has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constituted joint and several obligations of the Guarantors and Parent Guarantors. Upon the occurrence of the Effective Date, the 2020 Senior Notes, 2021 Senior Notes and 2023 Convertible Notes were terminated in accordance with the Plan. See Note 1, “Emergence from Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” for more information regarding the termination of the 2020 Senior Notes, 2021 Senior Notes and 2023 Convertible Notes.

(19) ASC 842 Adoption

As previously described in Note 3 – Summary of Significant Accounting Policies, we lease certain office space, office equipment, production field offices, compressors, drilling rigs, vehicles and other production equipment under cancellable and non-cancelable leases to support our operations.

The components of our total lease cost were as follows:


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,
	2019		2019
(In thousands)
Operating lease cost	$	243	$	4,607
Finance lease cost:
Amortization of right-of-use assets	35		420
Interest on lease liabilities	24		332
Total finance lease costs	$	59	$	752
Short-term lease cost	$	1,504	$	13,302
Total	$	1,806	$	18,661

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Supplemental cash flow information related to our leases is included in the table below:


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,
	2019		2019
(In thousands)
Cash paid for amounts included in lease liabilities:
Operating cash flows from operating leases	$	1,504	$	15,711
Operating cash flows from finance leases	59		752
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	—	$	4,573
Finance leases	75		1,332

Supplemental balance sheet information related to our leases is included in the table below:


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,
	2019		2019
(In thousands)
Operating Leases
Operating lease right-of-use assets	$	2,283	$	2,466

Other current liabilities	(1,773)		(1,910)
Other long-term liabilities	(731)		(782)
Total operating lease liabilities	$	(2,504)	$	(2,692)
Finance Leases
Other property and equipment	1,407		1,332
Accumulated depreciation and amortization	(315)		(272)
Other property and equipment, net	$	1,092	$	1,060
Other current liabilities	(481)		(451)
Other long-term liabilities	(681)		(671)
Total finance lease liabilities	$	(1,162)	$	(1,122)

Our weighted average remaining lease term and weighted average discount rate by lease classification were as follows:

F-50

Table of Contents


	Successor		Predecessor
	Period from December 11, 2019 to December 31,		Period from January 1, 2019 to December 10,
	2019		2019
Weighted Average Remaining Lease Term (Years)
Operating leases	1.60		1.60
Finance leases	2.33		2.35
Weighted Average Discount Rate
Operating leases	8.00	%	24.44	%
Finance leases	8.00	%	24.46	%

As of December 31, 2019 (Successor), our lease liabilities with enforceable contract terms that are greater than one year mature as follows:


	Operating Leases		Finance Leases
	(in thousands)
Year 1	$	2,148	$	714
Year 2	517		572
Year 3	235		227
Year 4	180		17
Year 5	12		—
Thereafter	—		—
Total lease payments	$	3,092	$	1,530
Less imputed interest	(588)		(368)
Total	$	2,504	$	1,162

F-51

Table of Contents

(20) Subsequent Events

On January 30, 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new

strain of coronavirus originating in Wuhan, China (“COVID-19”) and the risks to the international community as

the virus spread globally beyond its point of origin. In March 2020, the WHO classified the COVID-19 outbreak as a

pandemic, based on the rapid increase in exposure globally.

In addition, crude oil prices have recently experienced a severe decrease due to increased supply by Organization of the

Petroleum Exporting Countries (“OPEC”) nations and general economic downturn, 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 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. The COVID-19 pandemic and the disruption in the oil market is expected to lead to a significant reduction in the borrowing base under our Successor Revolving Credit Facility, a reduction in our reserves and may result in the recognition of impairment of our oil and natural gas properties. The COVID-19 pandemic may also impact the ability of our customers to continue to purchase our produced oil and natural gas at current levels due to increased supply and storage capacity shortages, which would reduce our future expected revenues and may have a material adverse effect on our financial position, results of operations and liquidity. As the majority of our capital budget is comprised of operated properties in which we control the timing of capital expenditure activity, if the borrowing base reduction under our Successor Revolving Credit Facility is larger than expected we can and will defer a portion or all of our planned capital expenditures to a future date. Further, we have enacted cost reduction efforts and initiatives in both our operational activities as well as our general and administrative expenses in an attempt to improve our financial position, results of operations and liquidity. We continue to monitor and evaluate these and other 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.

On March 27, 2020, President Trump signed into law the "Coronavirus Aid, Relief, and Economic Security Act" ("CARES ACT"). The Company is evaluating the impact, if any, that the CARES Act may have on the Company's future operations, financial position, and liquidity in fiscal year 2020.

F-52

Table of Contents LEGACY RESERVES INC.

SUPPLEMENTARY INFORMATION

Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities (Unaudited)

Costs incurred by Legacy in oil and natural gas property acquisition and development are presented below:


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

Development costs	$	4,634	$	97,504	$	229,556	$	176,827
Exploration costs	—		—		—		—
Acquisition costs:
Proved properties	—		1		7,456		148,776
Unproved properties	—		880		6,007		14,575
Total acquisition, development and exploration costs	$	4,634	$	98,385	$	243,019	$	340,178

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Please see page F-3 for total capitalized costs and associated accumulated depletion.

F-53

Table of Contents LEGACY RESERVES INC.

SUPPLEMENTARY INFORMATION — (Continued)

Net Proved Oil, NGL and Natural Gas Reserves (Unaudited)

The proved oil, NGL and natural gas reserves of Legacy have been estimated by an independent petroleum engineer, LaRoche, as of December 31, 2019, 2018 and 2017. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month unweighted first-day-of-the-month average price for December 31, 2019, 2018 and 2017.

An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:


	Oil (MBbls)	NGL (MBbls)(a)	Natural Gas (MMcf)(a)	Total (MBoe)
Total Proved Reserves:
Balance, December 31, 2016 (Predecessor)	32,458	7,843	627,020	144,805
Purchases of minerals-in-place	6,363	—	9,971	8,025
Sales of minerals-in-place	(442)	—	(1,121)	(629)
Revisions from ownership changes	998	15	1,751	1,305
Extensions and discoveries	10,219	339	16,647	13,333

Revisions of previous estimates due to price	5,387	672	51,975	14,722
Revisions of previous estimates due to performance	1,195	1,490	72,722	14,805
Production	(5,032)	(909)	(62,833)	(16,414)
Balance, December 31, 2017 (Predecessor)	51,146	9,450	716,132	179,952
Purchases of minerals-in-place	68	1	665	180
Sales of minerals-in-place	(1,801)	(1,975)	(22,717)	(7,562)
Revisions from ownership changes	178	39	522	304
Extensions and discoveries	12,672	45	22,100	16,399

Revisions of previous estimates due to price	3,079	(276)	(19,769)	(492)
Revisions of previous estimates due to performance	(6,637)	2,916	(16,756)	(6,512)
Production	(6,628)	(989)	(58,457)	(17,360)
Balance, December 31, 2018 (Predecessor)	52,077	9,211	621,720	164,909

Sales of minerals-in-place	(126)	(2)	(45)	(136)

Revisions from drilling and recompletions	4,566	224	10,499	6,540

Revisions of previous estimates due to performance	(8,158)	(1,668)	(109,436)	(28,065)
Production	(6,093)	(824)	(54,647)	(16,025)
Balance, December 31, 2019 (Successor)	42,266	6,941	468,091	127,223
Proved Developed Reserves:
12/31/2016 (Predecessor)	28,092	7,743	619,959	139,162
12/31/2017 (Predecessor)	45,045	9,333	705,679	171,991
12/31/2018 (Predecessor)	47,407	9,094	613,284	158,715
12/31/2019 (Successor)	38,687	6,886	462,492	122,655
Proved Undeveloped Reserves:
12/31/2016 (Predecessor)	4,366	100	7,061	5,643
12/31/2017 (Predecessor)	6,101	117	10,453	7,960
12/31/2018 (Predecessor)	4,670	117	8,436	6,192
12/31/2019 (Successor)	3,579	55	5,599	4,570

____________________

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

F-54

Table of Contents LEGACY RESERVES INC.

SUPPLEMENTARY INFORMATION — (Continued)

The primary drivers behind the changes to our proved reserves in each of 2017, 2018 and 2019 are described in more detail below.

2017: The increase in proved reserve quantities for the year ended December 31, 2017 was due primarily to the development of our unproved assets, the increase in average NYMEX-WTI oil and Henry Hub natural gas prices during 2017 which increased the economic life of our properties and the acquisition of producing oil and natural gas properties.

2018: The decrease in proved reserve quantities for the year ended December 31, 2018 was due primarily to production of the assets and sales of oil and natural gas properties partially offset by the development of our unproved assets during 2018.

2019: The decrease in proved reserve quantities for the year ended December 31, 2019 was due primarily to production of the assets, and the decrease in average NYMEX-WTI oil and Henry Hub natural gas prices during 2019 which decreased the economic life of our properties. This decrease was partially offset by the development of our unproved assets during 2019.

F-55

Table of Contents LEGACY RESERVES INC.

SUPPLEMENTARY INFORMATION — (Continued)

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)

Summarized in the following table is information for Legacy with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying the 12-month unweighted first-day-of-the-month average price for the years ended December 31, 2019, 2018 and 2017. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.


	December 31,
	2019		2018		2017
	(In thousands)
Future production revenues	$	3,330,687	$	5,093,812	$	4,657,406
Future costs:
Production	(1,743,636)		(2,453,520)		(2,347,759)
Development	(194,401)		(190,126)		(148,936)
Future income tax expense (a)	(133,394)		(238,940)		—
Future net cash flows before income taxes	1,259,256		2,211,226		2,160,711
10% annual discount for estimated timing of cash flows	(542,522)		(1,013,613)		(988,563)
Standardized measure of discounted net cash flows	$	716,734	$	1,197,613	$	1,172,148

____________________

(a)For the year ended December 31, 2017, federal income taxes were not deducted from future production revenues in the calculation of standardized measure as each partner was separately taxed on their share of Legacy's taxable income.

The standardized measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:


	December 31,
	2019		2018		2017
Oil (per Bbl) (a)	$	55.69	$	65.56	$	47.79
Natural Gas (per MMBtu) (b)	$	2.58	$	3.10	$	2.98

____________________

(a)The quoted oil price for all fiscal years is the 12-month unweighted average first-day-of-the-month West Texas Intermediate price, as posted by Plains Marketing, L.P., for each month of 2019, 2018 and 2017.

(a)The quoted gas price for all fiscal years is the 12-month unweighted average first-day-of-the-month Henry Hub price, as posted by Platts Gas Daily, for each month of 2019, 2018 and 2017.

F-56

Table of Contents LEGACY RESERVES INC.

SUPPLEMENTARY INFORMATION — (Continued)

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:


	Year ended December 31,
	2019		2018		2017
	(In thousands)
Increase (decrease):
Sales, net of production costs	$	(239,692)	$	(325,044)	$	(233,257)
Net change in sales prices, net of production costs	(328,698)		194,100		310,206
Changes in estimated future development costs	(737)		(8,109)		(591)


Revisions of previous estimates due to infill drilling,
recompletions and stimulations	—		284,354		135,700
Revisions of previous quantity estimates due to performance	(199,292)		(81,337)		89,941
Previously estimated development costs incurred	—		43,061		16,328
Purchases of minerals-in-place	—		1,315		206,038
Sales of minerals-in-place	(1,850)		(43,657)		(2,861)
Ownership interest changes	88,103		2,492		14,533
Other	3,389		(776)		5,534
Accretion of discount	134,997		111,427		54,951
Future income tax expense	62,901		(152,361)		—
Net increase (decrease)	(480,879)		25,465		596,522
Standardized measure of discounted future net cash flows:
Beginning of year	1,197,613		1,172,148		575,626
End of year	$	716,734	$	1,197,613	$	1,172,148

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.

F-57

☑
☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the fiscal year ended December 31, ~~2018~~ 2019
o ☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the transition period from to


Delaware			82-4919553
(State or other jurisdiction of			(I.R.S. Employer
incorporation or organization)			~~82-4919553~~ ~~(I.R.S. Employer~~ Identification No.)

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


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

~~PART III~~		1

~~ITEM 10.~~	~~DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE~~	1

~~ITEM 11.~~	~~EXECUTIVE COMPENSATION~~	6

~~ITEM 12.~~	~~SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND~~ ~~MANAGEMENT AND RELATED STOCKHOLDER MATTERS~~	30

~~ITEM 13.~~	~~CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR~~ ~~INDEPENDENCE~~	32

~~ITEM 14.~~	~~PRINCIPAL ACCOUNTING FEES AND SERVICES~~	33

~~PART IV~~		34

~~ITEM 15.~~	~~EXHIBITS, FINANCIAL STATEMENT SCHEDULES~~	34

~~SIGNATURES~~		35


Gary Gould	Gary Gould was appointed to the Board in December 2019 and is currently a Senior Advisor to GSO Capital Partners LP ("GSO"). Prior to his appointment, Mr. ~~Granberry invested in and became a board member of Just4Biz.com, a start-up internet company engaged in online office supply, and~~Gould served as ~~Interim CEO for brief periods in 2000 and 2001. Just4Biz.com filed for bankruptcy in May 2001. From January 1996 to May 1999, Mr. Granberry was President and~~the Chief Operating Officer (COO) of ~~Tom Brown,~~EQT Corporation (EQT) and as President of EQT Production Company from April to August, 2019.From November 2015 until his announcement as COO at EQT in March 2019, Mr. Gould served as Senior Vice President of Production and Resource Development for Continental Resources, Inc.~~, a public oil~~ (“Continental”). From April 2015 to November 2015, Mr. Gould served as Senior Vice President of Operations for Continental and, ~~gas company with exploration, development, acquisition~~prior to that, as Senior Vice President of Operations and ~~production activities throughout the central United States.~~Resource Development of Continental from May 2014 to April 2015.In prior roles, Mr. ~~Granberry~~Gould served as Vice President of Resource Development at Continental Resources and as Vice President/Director of Reservoir Technology for Chesapeake Energy. Mr. Gould earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of ~~Texas and upon graduation, worked for Amoco Production Company for 16 years.~~Kansas.	76 55	~~January 2008~~ December 2019

~~G. Larry Lawrence~~	The Board determined that Mr. ~~Lawrence has been a member of~~Gould is qualified to serve on our Board of Directors ~~since May 2006. Mr. Lawrence is Chief Financial Officer~~due to his pertinent experience, qualifications, attributes and ~~Vice President - Finance of Natural Gas Services Group (NGSG), a public company that provides small to medium horsepower compression equipment to~~skills, which include expertise in the natural gas industry, and has served in this position since July 2011. Previously, Mr. Lawrence served as Controller of NGSG from September 2010 to January 2011 before being promoted to Treasurer, Manager of Accounting and Principal Accounting Officer of NGSG in January 2011. From June 2006 to September 2010, Mr. Lawrence was self-employed as a management consultant doing business as Crescent Consulting. From September 2006 to August 2009, Mr. Lawrence served as Chief Financial Officer on a contract basis for Lynx Operating Company, a private company engaged in oil and gas ~~operations~~industry that was attained through his 32 years of service in engineering and executive positions with various oil and gas companies.

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

	The Board determined that Mr. Horn is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas ~~processing. From May 2004 through~~industry, including expertise in managing oil and gas investments and for his prior directorship experience serving various oil and gas companies.


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


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	%


	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


Douglas W. York			Douglas W. York was appointed to the Board in April ~~2006,~~2020. Mr. ~~Lawrence~~York previously served on our Board from October 2018 to December 2019. Mr. York is a Co-Founder and Managing Director of Sequel Energy Group LLC. Since 2016, Mr. York has also served as ~~Controller~~Managing Member for Halflight Land & Minerals LLC. Previously, Mr. York served as Co-Founder and Managing Member of ~~Pure Resources, an exploration~~privately held Sequel Energy, LLC during September 2006 through July 2014. Sequel Energy, LLC was formed in September 2006 and ~~production~~was focused on the acquisition and development of operated and non-operated interests in Louisiana, Oklahoma and North Dakota prior to divesting its assets in late 2013 and early 2014. Before co-founding Sequel, Mr. York spent ten years during August 1996 through March 2006 with St. Mary Land and Exploration Company (NYSE - SM), a publicly-traded company with operations in multiple U.S. basins, where he served as VP, Engineering and Acquisitions and later as EVP and COO. Mr. York served as Regional Engineer for the Northern Business Unit of the Rockies Region for three years during December 1993 through July 1996 with Meridian Oil Company. Mr. York began his career with ARCO Oil and Gas Company from November 1993 through January 1984, where his roles included Drilling Engineering, Reservoir Engineering and Planning. Mr. York holds a ~~wholly owned subsidiary~~B.S. Degree in Petroleum Engineering from the University of ~~Unocal Corporation which was~~Tulsa. He has served on the Boards of the Independent Petroleum Association of the Mountain States, Montana Petroleum Association, Petroleum Engineering Advisory Board at the University of Tulsa, KLR Energy Acquisition Corp. and the Development Board of Colorado UpLift.			67 59			~~May 2006~~


James Daniel Westcott	James Daniel Westcott was promoted to Chief Executive Officer of Legacy in March 2019 and was appointed to the Board in March 2019. Prior to Mr. Westcott’s promotion, he served as President of Legacy since March 2018 and as Chief Financial Officer since September 2012. From July 2006 to his appointment at Legacy, Mr. Westcott served as a Principal at GSO, ~~Capital Partners LP,~~ a division of The Blackstone Group L.P., where he was involved in the sourcing, structuring, evaluation and management of debt and equity investments for public and private companies in the energy and power industries. From August 2004 to July 2006, Mr. Westcott worked as an investment banker at J.P. Morgan’s Global Energy Group. Mr. Westcott is currently a Director of Peace Gospel International, a nonprofit organization with charitable programs in Asia and Africa. Mr. Westcott received a Bachelor of Arts degree in Science Technology & Society and a Master of Science degree in Management Science, both from Stanford University.	38 39	March 2019

~~Douglas W. York~~	~~Douglas W. York has been a member of~~The Board determined that Mr. Westcott is qualified to serve on our Board of Directors ~~since October 2018. Mr. York is a Co-Founder~~due to his service as our Chief Executive Officer and ~~Managing Director of Sequel Energy Group LLC. Sequel Energy Group was formed in November, 2016 to pursue~~prior service as our Chief Financial Officer, and his pertinent experience, qualifications, attributes and skills, which include: sourcing and structuring investments in ~~drilling joint ventures in North American resource plays. Doug has served in a number of managerial~~oil and ~~executive roles during his tenure in the E&P sector, most recently as Co-Founder~~gas companies and Managing Member of privately held Sequel Energy, LLC (September 2006-July 2014). Sequel Energy, LLC was formed in September 2006 and was focused on the acquisition and development of operated and non-operated interests in Louisiana, Oklahoma and North Dakota prior to divesting its assets in late 2013 and early 2014. Before co-founding Sequel, Doug spent ten years (August 1996-March 2006)familiarity with St. Mary Land and Exploration Company (NYSE - SM), a publicly-traded company with operations in multiple U.S. basins, where he served as VP, Engineering and Acquisitions and later as EVP and COO. Mr. York served as Regional Engineer for the Northern Business Unit of the Rockies Region during three years (December 1993-July 1996) with Meridian Oil Company. Doug began his career with ARCO Oil and Gas Company (January 1984-November 1993) where his roles our operations.	57	~~October 2018~~

~~Name~~	~~Age~~	~~Position~~
Name				Age	Position
James Daniel Westcott			38	39	Chief Executive Officer
Kyle M. Hammond			58	59	President and Chief Operating Officer
Robert L. Norris			39	40	Chief Financial Officer
Albert E. Ferrara, III			34	35	General Counsel and Corporate Secretary
Cory J. Elliott			41	42	Chief Information Officer
Micah C. Foster			38	40	Chief Accounting Officer and Controller




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

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

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

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

~~Name~~	~~Title as of 12/31/18~~	~~Current Title~~⁽⁶⁾
~~Paul T. Horne~~⁽¹⁾	~~Chief Executive Officer and Chairman of the Board~~	~~Chairman of the Board~~
~~James D. Westcott~~⁽²⁾	~~President and Chief Financial Officer~~	~~Chief Executive Officer~~
~~Kyle M. Hammond~~⁽³⁾	~~Executive Vice President and Chief Operating Officer~~	~~President and Chief Operating Officer~~
~~Kyle A. McGraw~~⁽⁴⁾	~~Executive Vice President and Chief Development Officer~~	~~N/A~~
~~Dan G. LeRoy~~⁽⁵⁾	~~Vice President, General Counsel and Secretary~~	~~Senior Legal Advisor~~

Performance Measure	Weight	Performance Level/Percent Earned
EBITDA	50%	75% of Target	100% of Target	125% of Target
		0%	100%	200%
Ratio of Total Debt to EBITDA	50%	125% of Target	Target	75% of Target
		0%	100%	200%

	Target Cash Bonus as a Percentage of 2018 Annual Salary
Named Executive Officer	Subjective	Objective	Total
Paul T. Horne	55%	55%	110%
James Daniel Westcott	45%	45%	90%
Kyle M. Hammond	40%	40%	80%
Kyle A. McGraw	40%	40%	80%
Dan G. LeRoy	37.5%	37.5%	75%

	Target Value of Phantom Units as a Percentage of 2018 Annual Salary
Named Executive Officer	Subjective	Objective	Total
Paul T. Horne	240%	160%	400%
James Daniel Westcott	180%	120%	300%
Kyle M. Hammond	180%	120%	300%
Kyle A. McGraw	105%	70%	175%
Dan G. LeRoy	100%	50%	150%

	Target Cash Bonus as a Percentage of 2018 Annual Salary
Named Executive Officer	Subjective			Objective			Total
Paul T. Horne		55	%		55	%		110	%
James Daniel Westcott		45	%		45	%		90	%
Kyle M. Hammond		40	%		40	%		80	%
Kyle A. McGraw⁽¹⁾		40	%		40	%		80	%
Dan G. LeRoy		37.5	%		37.5	%		75	%

			Subjective								Objective
Named Executive Officer	2018 Salary		Subjective Factor			% of Subjective Factor Earned			Bonus Amount		Objective Factor			% of Objective Factor Earned			Cash Incentive Amount (a)		Total Cash Incentive
Paul T. Horne	$	675,000		55	%		150	%	$	556,875		55	%		12.71	%	$	47,186	$	604,061
James Daniel Westcott	$	500,000		45	%		150	%	$	337,500		45	%		12.71	%	$	28,598	$	366,098
Kyle M. Hammond	$	450,000		40	%		125	%	$	225,000		40	%		12.71	%	$	22,878	$	247,878
Kyle A. McGraw	$	380,000		40	%		0	%	$	0		40	%		0	%	$	0	$	0
Dan G. LeRoy	$	320,000		37.5	%		100	%	$	120,000		37.5	%		12.71	%	$	15,252	$	135,252

	Target Value of Phantom Units as a Percentage of 2018 Annual Salary
Named Executive Officer	Subjective	Objective	Total
Paul T. Horne	240%	160%	400%
James Daniel Westcott	180%	120%	300%
Kyle M. Hammond	180%	120%	300%
Kyle A. McGraw	105%	70%	175%
Dan G. LeRoy	100%	50%	150%

Name and Principal Position	Year		Salary ($)^(a)		Bonus ($)^(b)		Unit Awards ($)^(c)		Stock Awards ($)^(d)(e)		All Other Compensation ($)			Total ($)
Paul T. Horne		2018	$	666,667	$	604,061	$	6,423,085	$	4,030,984	$	838,621	^(f)	$	12,563,418
Chairman of the Board and		2017	$	612,500	$	1,436,581	$	2,125,125	$	—	$	87,807	^(f)	$	4,262,013
Chief Executive Officer⁽¹⁾		2016	$	550,000	$	1,131,250	$	1,834,085	$	—	$	38,217	^(f)	$	3,553,552
James Daniel Westcott		2018	$	491,667	$	366,098	$	3,468,466	$	11,197,183	$	481,971	^(g)	$	16,005,385
President and		2017	$	438,333	$	951,732	$	1,129,437	$	—	$	84,207	^(g)	$	2,603,709
Chief Financial Officer⁽²⁾		2016	$	380,000	$	727,500	$	874,060	$	—	$	31,368	^(g)	$	2,012,928
Kyle M. Hammond		2018	$	445,833	$	247,878	$	3,275,773	$	6,718,312	$	689,907	^(h)	$	11,377,703
Executive Vice President		2017	$	417,500	$	863,182	$	903,550	$	—	$	21,600	^(h)	$	2,205,832
and Chief Operating Officer⁽³⁾		2016	$	380,000	$	680,000	$	639,247	$	—	$	21,200	^(h)	$	1,720,447
Kyle A. McGraw		2018	$	380,000	$	—	$	1,708,540	$	992,817	$	2,655,264	⁽ⁱ⁾	$	5,736,621
Executive Vice President and		2017	$	376,667	$	538,139	$	748,995	$	—	$	83,393	⁽ⁱ⁾	$	1,747,194
Chief Development Officer⁽⁴⁾		2016	$	360,000	$	474,000	$	628,587	$	—	$	38,217	⁽ⁱ⁾	$	1,500,804
Dan G. LeRoy		2018	$	316,667	$	135,252	$	770,774	$	716,618	$	125,113	^(j)	$	2,064,424
Vice President, General		2017	$	293,333	$	378,393	$	247,287	$	—	$	40,516	^(j)	$	959,529
Counsel and Secretary⁽⁵⁾		2016	$	260,000	$	250,500	$	182,058	$	—	$	26,788	^(j)	$	719,346

					Estimated Future Payouts Under Objective Component of Equity Incentive Plan Awards (in Units) (c)							All Other Unit Awards: Number of Units^(d)		All Other Option Awards: Number of Securities Underlying Options		Exercise or Base Price of Option Awards ($/Unit)		All Other Awards^(e)		Grant Date Fair Value of Unit and Option Awards^(f)
Name	Grant Date^(a)		Approval Date(b)		Threshold			Target		Maximum								All Other Awards^(e)
Paul T. Horne		02/16/2018		02/16/2018			%		751,880		1,503,760		—	$	—	$	—			$	5,035,867
		02/16/2018		02/16/2018		100	%		—		—		250,627	$	—	$	—			$	924,814
		02/16/2018		02/16/2018		100	%		—		—		125,313	$	—	$	—			$	462,405
		09/20/2018		03/23/2018															760,563
James Daniel Westcott		02/16/2018		02/16/2018			%		406,015		812,030		—	$	—	$	—			$	2,719,367
		02/16/2018		02/16/2018		100	%		—		—		135,339	$	—	$	—			$	499,401
		02/16/2018		02/16/2018		100	%		—		—		67,669	$	—	$	—			$	249,699
		09/20/2018		03/23/2018															2,112,676
Kyle M. Hammond		02/16/2018		02/16/2018			%		383,459		766,918		—	$	—	$	—			$	2,568,293
		02/16/2018		02/16/2018		100	%		—		—		127,819	$	—	$	—			$	471,652
		02/16/2018		02/16/2018		100	%		—		—		63,910	$	—	$	—			$	235,828
		09/20/2018		03/23/2018															1,267,606
Kyle A. McGraw		02/16/2018		02/16/2018			%		200,000		400,000		—	$	—	$	—			$	1,339,540
		02/16/2018		02/16/2018		100	%		—		—		66,667	$	—	$	—			$	246,001
		02/16/2018		02/16/2018		100	%		—		—		33,333	$	—	$	—			$	122,999
		09/20/2018		03/23/2018															187,324
Dan G. LeRoy		02/16/2018		02/16/2018			%		90,226		180,452		—	$	—	$	—			$	604,307
		02/16/2018		02/16/2018		100	%		—		—		30,075	$	—	$	—			$	110,977
		02/16/2018		02/16/2018		100	%		—		—		15,038	$	—	$	—			$	55,490
		09/20/2018		03/23/2018															135,211

	Equity Incentive Plan Awards
Name	Number of Restricted Stock Units That Have Not Vested (#)^(a)	Market value of Restricted Stock Units That Have Not Vested ($)^(b)	Number of Unearned Units That Have Not Vested (#)	Market Value of Unearned Units That Have Not Vested ($)
Paul T. Horne^(c)	760,503	$1,171,267
James Daniel Westcott	2,112,676	$3,253,521
Kyle M. Hammond	1,267,606	$1,952,113
Kyle A. McGraw^(d)	187,324	$288,479
Dan G. LeRoy	135,211	$208,225

	Unit Awards
Name	Number of Units Acquired On Vesting (#)	Value Realized On Vesting ($)^(a)
Paul T. Horne	2,461,963	$11,146,940
James Daniel Westcott	1,315,940	$5,887,561
Kyle M. Hammond	1,121,174	$5,486,478
Kyle A. McGraw	791,881	$3,543,089
Dan G. LeRoy	289,674	$1,289,895

Named Executive Officer	Benefit	Before Change in Control w/o Cause or for Good Reason		After Change in Control w/o Cause or for Good Reason
Paul T. Horne	Severance^(a)	$	1,350,000	$	2,025,000
	Bonus^(b)	$	2,040,642	$	3,060,963
	Benefits^(c)	$	44,160	$	66,240
	Restricted Stock
	Units^(d)	$	1,171,267	$	1,171,267
James Daniel Westcott	Severance^(a)	$	1,000,000	$	1,500,000
	Bonus^(b)	$	1,317,830	$	1,976,745
	Benefits^(c)	$	44,160	$	66,240
	Restricted Stock
	Units^(d)	$	3,253,521	$	3,253,521
Kyle M. Hammond	Severance^(a)	$	900,000	$	1,350,000
	Bonus^(b)	$	1,111,060	$	1,666,590
	Benefits^(c)	$	44,160	$	66,240
	Restricted Stock
	Units^(d)	$	1,952,113	$	1,952,113
Kyle A. McGraw^(e)	Severance	$	2,133,210	$	2,133,210
Dan G. LeRoy^(f)	Equity	$	208,225	$	208,225

	Year		Fees Earned ($)⁽¹⁾		Share and Unit Awards ($)⁽²⁾		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation ($)		Total ($)
Paul T. Horne		2018		—		—		—		—		—		—		—
Cary D. Brown		2018	$	61,000	$	125,000		—		—		—		—	$	186,000
William R. Granberry		2018	$	106,000	$	125,000		—		—		—		—	$	231,000
G. Larry Lawrence		2018	$	108,000	$	125,000		—		—		—		—	$	233,000
Kyle D. Vann		2018	$	141,000	$	125,000		—		—		—		—	$	265,000
D. Dwight Scott⁽³⁾		2018		—		—		—		—		—		—		—
Douglas W. York⁽⁴⁾		2018	$	23,500	$	62,500									$	86,000
William D. Sullivan		2018	$	70,500	$	50,000									$	120,500


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


Paul T. Horne	2019	$	265,750	$	125,000	$	—	$	—	$	—	$	—	$	390,750
James Daniel Westcott	2019	$	—	$	—	$	—	$	—	$	—	$	—	$	—
William R. Granberry	2019	$	232,750	$	125,000	$	—	$	—	$	—	$	—	$	357,750
G. Larry Lawrence	2019	$	255,500	$	125,000	$	—	$	—	$	—	$	—	$	380,500
Kyle D. Vann	2019	$	238,500	$	125,000	$	—	$	—	$	—	$	—	$	363,500
Douglas W. York	2019	$	215,250	$	125,000	$	—	$	—	$	—	$	—	$	340,250

	Shares Beneficially Owned
Owner	Number		Percentage
Directors, Named Executive Officers and Executive Officers
Kyle A. McGraw^(a)		1,072,604			*
Kyle D. Vann		209,756			*
Paul T. Horne^(b)(c)		192,000			*
William R. Granberry		149,889			*
G. Larry Lawrence		132,756			*
James Daniel Westcott^(b)		102,440			*
Kyle M. Hammond^(b)(d)		89,530			*
Dan G. LeRoy^(b)		24,639			*
Micah C. Foster^(b)		23,832			*
Douglas W. York		12,450			*
Albert E. Ferrara, III^(b)		2,903			*
Cory J. Elliott^(b)		2,461			*
Robert L. Norris^(b)		0			*
All directors and executive officers as a group (11 persons)^(e)		918,017			*

Greater than 5% Stockholder
Baines Creek Capital, LLC^(f)		26,403,289		23.0	%
FMR LLC^(g)		11,898,343		10.4	%


	Shares Beneficially Owned
Owner	Number	Percentage
Directors, Named Executive Officers and Executive Officers
Richard Betz	0	*
David Coppé	0	*
Gary Gould	0	*
Robert Horn	0	*
Douglas W. York	0	*
James Daniel Westcott	0	*
Kyle M. Hammond	0	*
Robert L. Norris	0	*
Paul T. Horne	0	*
All directors and executive officers as a group (12 persons)	0	*

Greater than 5% Stockholder
GSO Entities (1)	53,450,115	88	%
Canyon Capital Advisors LLC (2)	4,307,397	7	%
^* Percentage of shares beneficially owned does not exceed 1%

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Right		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan
Equity compensation plans approved by security holders		7,302,809	$	—		3,396,304
Equity compensation plans not approved by security holders		—		—		—
Total		7,302,809	$	—		3,396,304


	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Right	Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan




Plan Category
Equity compensation plans approved by security holders	—	$	—	6,804,282
Equity compensation plans not approved by security holders	—	$	—	0
Total	—	$	—	6,804,282

	Year ended December 31
	2018		2017
Audit Fees⁽¹⁾	$	1,069,208	$	654,945
Audit-Related Fees⁽¹⁾	$	8,500	$	58,465
Tax Fees	$	—	$	—
All Other Fees (Executive compensation)⁽²⁾	$	—	$	30,640
Total	$	1,077,708	$	744,050