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LGCYQ Legacy Reserves


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________
 Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2019
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from               to
Commission file number 1-38668
__________________
 Legacy Reserves Inc.
(Exact name of registrant as specified in its charter)
__________________
Delaware82-4919553
(State or other jurisdiction of(I.R.S. Employer
incorporation or organization)Identification No.)
  
303 W. Wall Street, Suite 180079701
Midland, Texas(Zip Code)
(Address of principal executive offices)
Registrant’s telephone number, including area code:
(432) 689-5200
Securities registered pursuant to Section 12(b) of the Act:
None.

Securities registered pursuant to 12(g) of the Act:
None.
______________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes      No☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes       No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes       No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☑     No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer  ☐
Non-accelerated filer ☑
Smaller reporting company  ☑

Emerging growth company  ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  No 
The aggregate market value of voting and non-voting stock held by non-affiliates of the registrant as of June 28, 2019 was approximately $2.1 million based upon the closing price as reported on the OTCPK of the registrant's common stock on that date.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐
61,062,850 shares of common stock, par value $0.01, of the registrant were outstanding as of April 27, 2020.




LEGACY RESERVES INC.

Table of Contents
 
  
PART I
  
ITEM 1.
ITEM 1A.
   
ITEM 1B.
   
ITEM 2.
   
ITEM 3.
   
ITEM 4.
   
PART II
  
ITEM 5.
 20
   
ITEM 6.
   
ITEM 7.
 22
   
ITEM 8.
   
ITEM 9.
 39
   
ITEM 9A.
   
ITEM 9B.
   
PART III
  
ITEM 10.
   
ITEM 11.
   
ITEM 12.
 49
   
ITEM 13.
   
ITEM 14.
   
PART IV
  
ITEM 15.
ITEM 16.

i

GLOSSARY OF TERMS
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet.
Boe. One barrel of oil equivalent determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Boe/d. Barrels of oil equivalent per day.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Hydrocarbons. Oil, NGLs and natural gas are all collectively considered hydrocarbons.
Liquids. Oil and NGLs. 
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet.
MGal. One thousand gallons of natural gas liquids or other liquid hydrocarbons.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX. New York Mercantile Exchange.
Oil. Crude oil and condensate.

PV-10. PV-10 is a compilation of the standardized measure on a pre-tax basis.
 
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Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Proved developed reserves or PDPs. Reserves that can be expected to be recovered through: (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Proved developed non-producing or PDNPs. Proved oil and natural gas reserves that are developed behind pipe or shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
 
Proved reserves. Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
 
Proved undeveloped reserves or PUDs. Proved undeveloped oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Proved reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Proved undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
 
R/P ratio (reserve life). The reserves as of the end of a period divided by the production volumes for the same period.
 
Reserve replacement. The replacement of oil and natural gas produced with reserve additions from acquisitions, reserve additions and reserve revisions.
 
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
 
Standardized measure. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission (using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price for each month) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Texas margin taxes and the federal income taxes associated with a corporate subsidiary have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure. Standardized measure does not give effect to commodity derivative transactions.
 
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
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Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and the right to a share of production.
 
Workover. Operations on a producing well to restore or increase production.
 
iv

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

the amount of oil and natural gas we produce;

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

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

our ability to replace reserves;

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

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

the level of our capital expenditures;

our future operating results;

national and global health crises, including outbreaks, epidemics, and pandemics such as coronavirus ("COVID-19"); and

our plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this document, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
 
The forward-looking statements contained in this document are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this document are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements. The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly.
 

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PART I

ITEM 1.BUSINESS
 
References in this annual report on Form 10-K to “Legacy Reserves,” “Legacy,” “we,” “our,” “us,” or like terms refer to Legacy Reserves Inc. and its subsidiaries for the periods after September 19, 2018, the date the Corporate Reorganization was consummated (as defined below). For the periods prior to September 20, 2018, unless the context requires otherwise or unless otherwise noted, all references to “Legacy Reserves,” “Legacy LP,” “Legacy,” the “Company,” “we,” “us,” “our” or like terms are to Legacy Reserves LP and its subsidiaries.
 
Legacy Reserves Inc.
 
Legacy Reserves Inc. is a Delaware corporation incorporated in 2018 in connection with the Corporate Reorganization, as defined below. We are an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Our current operations are focused on the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions, as well as horizontal development of unconventional plays in the Permian Basin, as market conditions allow.
 
Our oil and natural gas production and reserve data as of December 31, 2019 are as follows:

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

our proved reserves to production ratio was approximately 8.3 years based on the annualized production volumes for the three months ended December 31, 2019.

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

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

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

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

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On June 18, 2019, Legacy and certain of its subsidiaries (collectively with Legacy, the “Debtors”) commenced voluntary cases (the “Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On June 19, 2019, the Bankruptcy Court granted a motion seeking joint administration of the Chapter 11 Cases under the caption In re Legacy Reserves Inc., et al. On August 2, 2019, the Debtors filed the Joint Chapter 11 Plan of Reorganization for Legacy Reserves Inc. and its Debtor Affiliates (as amended, modified or supplemented from time to time, the “Plan”) with the Bankruptcy Court.


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

Operating Regions

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

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

Rocky Mountain. Our Rocky Mountain region was originally comprised by acquisitions in the Big Horn, Wind River and Powder River Basins in Wyoming largely consisting of mature oil wells with a natural water drive producing primarily from the Dinwoody-Phosphoria, Tensleep and Minnelusa formations. We expanded our footprint with our acquisition of oil properties in North Dakota and Montana in 2012 and our acquisition of non-operated natural gas properties in Colorado in 2014. The North Dakota properties produce primarily from the Madison and Bakken formations, while the Montana properties produce mostly from the Sawtooth and Bowes formations. The Colorado properties produce primarily from the Williams Fork formation.
 
Mid-Continent. Our properties in the Mid-Continent region are located in Oklahoma. These properties were acquired in 2007.
 
Our proved reserves by operating region as of December 31, 2019 are as follows:

Proved Reserves by Operating Region as of December 31, 2019
Operating RegionsOil (MBbls)Natural
Gas (MMcf)
 NGLs (MBbls)Total (MBoe)% Liquids% PDP% Total
Permian Basin36,407  90,078  825  52,245  71 %91 %41 %
East Texas66  220,586  138  36,969  %100 %29 %
Rocky Mountain5,167  153,118  5,177  35,864  29 %100 %28 %
Mid-Continent625  4,309  802  2,145  67 %91 %%
Total42,265  468,091  6,942  127,223  39 %100 %

Development Activities

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

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

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Gross LocationsNet LocationsNet Volume (MBoe)
Balance, December 31, 201832  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, 201926  17.0  4,568  
________________

(a)These PUD locations were removed from our PUD inventory because of non-consenting working interest owners. Due to their ownership level, their consent is required in order to develop the PUD.
(b) PUDs removed due to performance or added due to extensions and discoveries are those PUDs removed or added, as applicable, due to new or revised engineering, geologic and economic evaluations such as offset well production data, the drilling of offset wells, new geologic data or changes in projected capital costs or product prices. PUDs are removed or added depending on whether the technical criteria for the proved undeveloped reserve classification is satisfied and, in the case of additions due to performance, whether the well is scheduled to be drilled within five years after initial recognition as proved reserves.
The increases in PUDs due to extensions and discoveries were driven by offset drilling in connection with our drilling program in the Permian Basin, which includes the horizontal Spraberry, horizontal Wolfcamp and horizontal Bone Spring wells.
As of December 31, 2019, we identified 11 gross (9.5 net) recompletion and fracture stimulation projects.

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

A significant portion of our horizontal operated development activity in the Permian Basin has been pursued through our development agreement (as amended, the "Development Agreement") entered into in 2015 with Jupiter JV, LP ("Investor"), which was formed by certain of TPG Sixth Street Partners' investment funds. Our capital resources and liquidity have benefited from our interest in the development activity under the Development Agreement as described below.

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

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

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


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Oil and Natural Gas Derivative Activities
 
In order to mitigate price risk for a portion of our oil and natural gas production, we enter into oil and natural gas derivative contracts from time to time. At December 31, 2019, we had in place oil and natural gas derivatives covering portions of our estimated future oil and natural gas production. Our derivative contracts are in the form of fixed price swaps for NYMEX WTI oil; fixed price swaps for NYMEX Henry Hub; fixed price swaps for the Midland-to-Cushing oil differentials; fixed price swaps for WAHA basis differentials; and fixed price swaps for CIG-Rockies basis differentials.

Marketing and Major Purchasers
 
For the period December 11, 2019 to December 31, 2019 (Successor), the period of January 1, 2019 through December 10, 2019 (Predecessor), and the years ended December 31, 2018, and 2017 (Predecessor), Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to the purchasers as detailed in the table below.
SuccessorPredecessor
Period fromPeriod from
December 11, 2019January 1, 2019
to December 31,to December 10,Year Ended December 31,
 2019201920182017
Plains Marketing, LP15%19%20%10%
Trafigura21%19%9%1%
Rio Energy International Inc (1)—%2%13%9%
(1) Less than 1% for the period ended December 11, 2019 to December 31, 2019 (Successor).

Our oil sales prices are based on formula pricing and calculated either using a discount to NYMEX WTI oil or using the appropriate buyer’s posted price less a regional differential and transportation fee.
 
Although we believe we could identify a substitute purchaser if we were to lose any of our oil or natural gas purchasers, the loss could temporarily cause a loss or deferral of production and sale of our oil and natural gas in that particular purchaser’s service area. However, if one or more of our larger purchasers ceased purchasing oil or natural gas altogether, the loss of any such purchaser could have a detrimental impact on our short-term production volumes and our ability to find substitute purchasers for our production volumes in a timely manner, though we do not believe this would have a long-term material adverse effect on our operations.
 
Competition
 
We operate in a highly competitive environment for acquiring leases and properties, securing and retaining trained personnel and service providers and marketing oil and natural gas. Our competitors may be able to pay more for leases, productive oil and natural gas properties and development projects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
 
Seasonal Nature of Business
 
The demand for oil and natural gas can be seasonal based on motor vehicle driving patterns and heating and cooling demands related to weather. Our Rockies' oil prices suffer relative to WTI in the winter due to reduced demand for asphaltic crude. Refinery turnarounds in the Permian typically occur in the first quarter, and, historically, we have experienced wider oil differentials during this time.
 
Environmental Matters and Regulation
 
General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

require the acquisition of various permits before drilling commences;

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

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

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

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
 
The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.
 
Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
 
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, may impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
 
We currently own, lease, or operate numerous properties that have been used for oil and natural gas development and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, most of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed of substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
 
Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
 
The Oil Pollution Act of 1990, as amended or OPA, which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that cause a release of oil into waters of the United States. In addition, owners and operators of facilities that store oil above threshold amounts must develop and implement spill response plans.
 

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

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

Air Emissions. The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. In addition, more stringent federal, state and local regulations could result in increased costs and the need for operational changes. Finally, the EPA issued rules in May 2016 covering methane emissions from new oil and natural gas industry operations which could result in additional costs and restrictions on our operations. In September 2019, the EPA issued proposed amendments to the 2016 rule that would rescind methane emissions standards for the oil and gas industry.
 
OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.
 
In 2009, the EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources, including the oil and natural gas production industry. In May 2016, the EPA finalized regulations that establish new controls for emissions of methane and volatile organic compounds from oil and natural gas operations. In September 2019, EPA released proposed amendments to the new source performance standards (“NSPS”) for the oil and gas industry, which would remove all sources in the transmission and storage segments of the industry from regulation under the NSPS and would rescind the methane requirements in the 2016 NSPS that apply to sources in the production and processing segments of the industry. Additional regional, federal or state requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our products. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
 
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2019. Additionally, as of the date of this document, we are not aware of any environmental issues or claims that require material capital expenditures during 2020. However, we cannot assure investors that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.

6


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

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

Other Regulation of the Oil and Natural Gas Industry
 
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.
 
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
 
Drilling and Production. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

the location of wells; 
the method of drilling and casing wells;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally regulate and seek to restrict the venting or flaring of natural gas and impose requirements regarding the ratability of production. As of April 2020, some states, including Texas and Oklahoma, have considered proration of oil production in response to market conditions. These laws and regulations, and any future laws or regulations, may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
 
Natural gas regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale or resale of natural gas is subject to federal regulation, including regulation of the terms,

7

conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or the FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.
 
Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.
 
State regulation. The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. New Mexico currently imposes a 3.75% severance tax on both oil and natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
 
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
 
Employees
 
As of December 31, 2019, we had 317 employees, none of whom are subject to collective bargaining agreements. We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed. We believe that we have a favorable relationship with our employees.
 
Offices
 
Our principal offices are located in Midland, Texas at 303 W. Wall Street. In addition to our principal offices, we have regional offices located in Cody, Wyoming, and in The Woodlands, Texas.

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



8

ITEM 1A.RISK FACTORS

None.

ITEM 1B.UNRESOLVED STAFF COMMENTS
 
    None.


9

ITEM 2.PROPERTIES
 
As of December 31, 2019, we owned interests in producing oil and natural gas properties in 530 fields in the Permian Basin, East Texas, Piceance Basin of Colorado, Wyoming, North Dakota, Montana, Oklahoma and several other states, from 8,952 gross productive wells of which 2,770 are operated and 6,182 are non-operated. The following table sets forth information about our proved oil and natural gas reserves as of December 31, 2019. The PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. For a definition of “standardized measure,” please see the glossary of terms at the beginning of this annual report on Form 10-K.
 As of December 31, 2019
 Proved ReservesPV-10 (b)
Field or RegionMMBoeR/P (a)% Oil and NGLsAmount% of Total
    ($ in Millions) 
Spraberry Field (c)24.2  7.4  70 %$308.8  38 %
Lea Field7.7  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   
Total — Top 499.4  8.7  28 %$562.6  70 %
All others27.8  7.0  76  243.6  30  
Total127.2  8.3  39 %$806.2  100 %
__________________
(a)Reserves as of December 31, 2019 divided by annualized fourth quarter production volumes.
(b)PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. The below table provides a reconciliation of the GAAP standardized measure to PV-10 (non-GAAP) at December 31, 2019.
December 31,
2019
(In millions)
Standardized measure of discounted net cash flows$716,734  
Present value of future income taxes discounted at 10%89,460  
PV-10806,194  
(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.

10

SuccessorPredecessor
Period fromPeriod from
December 11, 2019January 1, 2019
to December 31,to December 10,Year Ended December 31,
(In thousands, except daily production)2019201920182017
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.
SuccessorPredecessor
Period fromPeriod from
December 11, 2019January 1, 2019
to December 31,to December 10,Year Ended December 31,
(In thousands, except daily production)2019201920182017
Oil (MBbls) 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.
SuccessorPredecessor
Period fromPeriod from
 December 11, 2019January 1, 2019
to December 31,to December 10,Year Ended December 31,
(In thousands, except daily production)2019201920182017
Oil (MBbls) 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.

12


 As of December 31,
 201920182017
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 reserves96 %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.
 

13

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.


14

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):
 
SuccessorPredecessor
Period fromPeriod from
December 11, 2019January 1, 2019
 to December 31,to December 10,Year Ended December 31,
 2019201920182017(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. 

15

 OilNatural GasTotal
 GrossNetGrossNetGrossNet
Operated1,659  1,185  1,111  994  2,770  2,179  
Non-operated2,316  233  3,866  1,164  6,182  1,397  
Total3,975  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)
Total852,851431,767197,26860,7521,050,119492,519
____________________
(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,
 201920182017
Gross:   
Development   
Productive29  54  42  
Dry—  —  —  
Total29  54  42  
Exploratory   
Productive—  —  —  
Dry—  —  —  
Total—  —  —  
Net:   
Development   
Productive12.4  27.6  27.4  
Dry—  —  —  
Total12.4  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.    
SuccessorPredecessor
 Period fromPeriod fromYear Ended December 31,
December 11, 2019January 1, 2019
to December 31,to December 10,
 2019201920182017(b)
(In thousands, except per unit data and production)
Revenues   
Oil sales$23,232  $300,905  $375,444  $239,448  
Natural gas liquids sales916  14,082  27,750  24,796  
Natural gas sales6,016  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 taxes94  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)/received67  8,773  (16,845) 11,840  
Natural gas derivative cash settlements received 14,914  5,130  12,316  
Total commodity derivative cash settlements76  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

26

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):
SuccessorPredecessor
Period fromPeriod from
December 11, 2019January 1, 2019
 to December 31,to December 10,Year Ended December 31,
(In thousands)2019201920182017
Net income (loss)$3,050  $173,876  $43,833  $(53,897) 
      Plus: 
Interest expense1,607  115,660  117,008  89,206  
Gain on extinguishment of debt—  (13,105) (66,066) —  
Income tax expense (benefit) 105  2,968  1,398  
Depletion, depreciation, amortization and accretion6,259  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 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 derivatives6,292  50,294  (49,172) (17,776) 
Net cash settlements received on commodity derivatives77  23,687  (11,715) 24,156  
Exploration expense750  —  —  —  
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 YearVolumes (Bbls)Average Price per BblPrice Range per Bbl
20203,660,000$55.62$54.10-$56.00
20212,555,000$52.80$52.40-$53.22
20222,190,000$51.03$49.95-$51.95
20231,898,000$50.51$49.40-$50.90

Natural Gas Swaps:
 AveragePrice Range per
Calendar YearVolumes (MMBtu)Price per MMBtuMMBtu
202039,640,000$2.33$2.28-$2.40
202134,675,000$2.41$2.37-$2.44
202232,850,000$2.41$2.41-$2.42
202329,200,000$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 YearVolumes (Bbls)Average Price per BblPrice Range per Bbl
20203,170,000$0.95$0.90-$1.00
20212,555,000$1.06$1.05-$1.10
20221,825,000$1.14$1.07-$1.20
20231,825,000$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:

AveragePrice Range per
Calendar YearVolumes (Bbls)Price per MMBtuMMBtu
20206,410,000$(1.85)$(1.74)-$(1.98)
20217,300,000$(1.14)$(1.14)-$(1.15)
20227,300,000$(0.77)$(0.74)-$(0.80)
20237,300,000$(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: 
 AveragePrice Range per
Calendar YearVolumes (MMBtu)Price per MMBtuMMBtu
20209,470,000$(0.56)$(0.55)-$(0.58)
20217,300,000$(0.56)$(0.56)
20227,300,000$(0.54)$(0.54)
20237,300,000$(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.

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 to 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.

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 then to serve on the Board.

NamePrincipal OccupationAgeDirector Since
Richard BetzRichard F. Betz was appointed to the Board in December 2019 and is currently the Chief Executive Officer of Lithos Resources since February 2020. Prior to Mr. Betz’ appointment to the Board, he served as Chief Executive Officer and as a director of Resolute Energy Corporation (“Resolute”) from January 2017 until March 2019. From March 2012 until his appointment as Chief Executive Officer of Resolute, Mr. Betz served as Executive Vice President and Chief Operating Officer of Resolute. From September 2009 to March 2012, Mr. Betz served as Senior Vice President, Strategy and Planning of Resolute and was Vice President, Business Development from July 2009 to September 2009. Prior to that, Mr. Betz served as Vice President, Business Development of a predecessor of Resolute since its founding in 2004. Prior to 2004, Mr. Betz worked as a Managing Director of Chase Securities and successor companies in the oil and gas investment banking coverage group with primary responsibility for mid-cap exploration and production companies as well as leveraged finance and private equity. Mr. Betz received an MBA from the Wharton School of the University of Pennsylvania and an undergraduate degree from Villanova University.58December 2019
The Board determined that Mr. Betz should be nominated to our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas industry, including 15 years of service in executive positions.
David Coppé
David Coppé was appointed to the Board in December 2019. Prior to his current role, Mr. Coppé served as Director and Head of Energy, Private Equity of Caisse de Depot et Placement du Québec from March 2017 until March 2019. From November 2012 until his appointment as Director and Head of Energy, Private Equity, Mr. Coppé served as President and Chief Executive Officer of Probe Holdings, Inc. Mr. Coppé served on the board of directors of Logan International, Inc. from 2006 until 2016, and also served on a number of other private company boards. He started his career as a field engineer for Schlumberger and also worked for Goldman Sachs and Cadent Energy Partners, a private equity firm. He currently serves on the board of RDV Resources (f/k/a Sheridan I). Mr. Coppé received an MBA from Massachusetts Institute of Technology and a Mechanical Engineering degree from the University of Louvain, Belgium.
48December 2019
The Board determined that Mr. Coppé is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas industry that was attained through his 22 years of service in the oil and gas industry, including 14 years serving in directorship or executive positions.

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Gary Gould
Gary Gould was appointed to the Board in December 2019 and is currently a Senior Advisor to GSO Capital Partners LP ("GSO"). Prior to his appointment, Mr. Gould served as the Chief Operating Officer (COO) of EQT Corporation (EQT) and as President of EQT Production Company from April to August, 2019. From November 2015 until his announcement as COO at EQT in March 2019, Mr. Gould served as Senior Vice President of Production and Resource Development for Continental Resources, Inc. (“Continental”). From April 2015 to November 2015, Mr. Gould served as Senior Vice President of Operations for Continental and, prior to that, as Senior Vice President of Operations and Resource Development of Continental from May 2014 to April 2015. In prior roles, Mr. Gould served as Vice President of Resource Development at Continental Resources and as Vice President/Director of Reservoir Technology for Chesapeake Energy. Mr. Gould earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Kansas.
55December 2019
The Board determined that Mr. Gould is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include expertise in the oil and gas industry that was attained through his 32 years of service in engineering and executive positions with various oil and gas companies.
Robert HornRobert Horn was appointed to the Board in December 2019 and is currently a Senior Managing Director of Blackstone and is Co-Head of Energy Investing for GSO Capital Partners. Mr. Horn sits on the investment committees for GSO’s energy funds, performing credit funds, distressed funds and structured credit funds. Prior to joining GSO, Mr. Horn worked in Credit Suisse’s Global Energy Group, where he advised on high yield financings and merger and acquisition assignments for companies in the power and utilities sector. Mr. Horn graduated with honors from McGill University.38December 2019
The Board determined that Mr. Horn is qualified to serve on our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: expertise in the oil and gas industry, including expertise in managing oil and gas investments and for his prior directorship experience serving various oil and gas companies.

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Douglas W. YorkDouglas W. York was appointed to the Board in April 2020. Mr. York previously served on our Board from October 2018 to December 2019. Mr. York is a Co-Founder and Managing Director of Sequel Energy Group LLC. Since 2016, Mr. York has also served as Managing Member for Halflight Land & Minerals LLC. Previously, Mr. York served as Co-Founder and Managing Member of privately held Sequel Energy, LLC during September 2006 through July 2014. Sequel Energy, LLC was formed in September 2006 and was focused on the acquisition and development of operated and non-operated interests in Louisiana, Oklahoma and North Dakota prior to divesting its assets in late 2013 and early 2014. Before co-founding Sequel, Mr. York spent ten years during August 1996 through March 2006 with St. Mary Land and Exploration Company (NYSE - SM), a publicly-traded company with operations in multiple U.S. basins, where he served as VP, Engineering and Acquisitions and later as EVP and COO. Mr. York served as Regional Engineer for the Northern Business Unit of the Rockies Region for three years during December 1993 through July 1996 with Meridian Oil Company. Mr. York began his career with ARCO Oil and Gas Company from November 1993 through January 1984, where his roles included Drilling Engineering, Reservoir Engineering and Planning. Mr. York holds a B.S. Degree in Petroleum Engineering from the University of Tulsa. He has served on the Boards of the Independent Petroleum Association of the Mountain States, Montana Petroleum Association, Petroleum Engineering Advisory Board at the University of Tulsa, KLR Energy Acquisition Corp. and the Development Board of Colorado UpLift.59April 2020
The Board determined that Mr. York should be nominated to our Board of Directors due to his pertinent experience, qualifications, attributes and skills, which include: managing a public oil and gas company, experience in the valuation of oil and gas properties and financial expertise.
Kyle M. HammondKyle M. Hammond was promoted to President of Legacy in March 2019 and continues to serve as its Chief Operating Officer. Mr. Hammond was appointed to the Board in December 2019. Prior to Mr. Hammond’s promotion, he served as Executive Vice President and Chief Operating Officer of Legacy since March 2015. From its formation in August 2011 to his appointment as Executive Vice President and Chief Operating Officer of Legacy, Mr. Hammond served as President and Chief Executive Officer and as a director of FireWheel Energy LLC, a private equity backed oil and gas development company headquartered in Midland, Texas. Prior to forming FireWheel Energy LLC, Mr. Hammond served as VP of Operations for the Permian Division of XTO Energy/Exxon from 2003 to August 2011. Mr. Hammond currently serves on the board of directors of Abilene Christian University, Blanks Ranch Properties, LLC and Midland Christian School. Mr. Hammond earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.59December 2019
The Board determined that Mr. Hammond is qualified to serve on our Board of Directors due to his service as our Chief Operating Officer, and his pertinent experience, qualifications, attributes and skills, which include: the knowledge and experience attained through 17 years of service in the oil and gas industry, with a focus in the Permian Basin, and his familiarity with our operations.

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

Executive Officers

The following table shows information for our executive officers.


NameAgePosition
James Daniel Westcott39Chief Executive Officer
Kyle M. Hammond59President and Chief Operating Officer
Robert L. Norris40Chief Financial Officer
Albert E. Ferrara, III35General Counsel and Corporate Secretary
Cory J. Elliott42Chief Information Officer
Micah C. Foster40Chief Accounting Officer and Controller

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

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

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

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

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

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

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

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

Code of Ethics

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

Section 16(a) Beneficial Ownership Reporting Compliance

Under Section 16(a) of the Exchange Act, directors, certain officers, and beneficial owners of 10% or more of our common stock (“Reporting Persons”) were required from time to time to file with the SEC and NASDAQ reports of ownership and changes of ownership. Reporting Persons are required to furnish Legacy with copies of all Section 16(a) reports they file. Based solely on its review of forms and written representations received from Reporting Persons with respect to the fiscal year ended December 31, 2019, Legacy believes that all filing requirements applicable to its directors and officers had been met.
 
ITEM 11.EXECUTIVE COMPENSATION
 
2019 Summary Compensation Table

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

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Name and Principal PositionYearSalary ($)(a)Bonus ($)Unit Awards ($)(b)Stock Awards ($)(c)(d)Non-Equity Incentive Plan Compensation ($)(e)All Other Compensation ($)Total ($)
Paul T. Horne2019$112,500  $—  $—  $—  $—  $15,458  (f) $127,958  
Chairman of the Board and2018$666,667  $604,061  $6,423,085  $4,030,984  $—  $838,621  (f) $12,563,418  
Chief Executive Officer (1)
James Daniel Westcott2019$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. Hammond2019$491,667  $1,000,000  $—  $—  $1,158,743  $21,600  (h) $2,672,010  
President and Chief2018$445,833  $247,878  $3,275,773  $6,718,312  $—  $689,907  (h) $11,377,703  
Operating Officer(3)
Robert L. Norris2019$345,205  $600,000  $—  $—  $634,260  $15,833  (i) $1,595,298  
Chief Financial Officer (4)2018$—  $—  $—  $—  $—  $—  $—  

1.Effective March 1, 2019, Mr. Horne retired from his role as Chief Executive Officer of the Company.
2.Effective March 1, 2019, in connection with Mr. Horne’s retirement as Chief Executive Officer of the Company, Mr. Westcott was promoted to Chief Executive Officer of the Company.
3.Effective March 1, 2019, in connection with Mr. Westcott’s promotion to Chief Executive Officer of the Company, Mr. Hammond was promoted to President and Chief Operating Officer of the Company.
4.Effective February 19, 2019, Mr. Norris was appointed as Chief Financial Officer of the Company.
(a) For Messrs. Westcott, and Hammond annual salary increases (where applicable) for 2019 and 2018 became effective on March 1, 2019 and March 1, 2018, respectively.
(b) Phantom units were granted to officers on February 16, 2018. The amount shown reflects the grant date fair value of these awards based upon the Financial Accounting Standards Board’s authoritative guidance relating to stock compensation. The assumptions used in calculating these amounts are discussed further in Note 16 – “Share-Based Compensation” to the financial statements in the Partnership’s annual report on Form 10-K filed with the SEC on February 23, 2018. Assuming all performance and service conditions are met at the maximum possible level, the grant date fair value of the unit awards granted in 2018 pursuant to the compensation policy for each NEO is as follows: Mr. Horne: $6,936,093; Mr. Westcott: $3,745,490; and Mr. Hammond: $3,537,407. In connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. Under the individual phantom unit award agreements, such vested phantom units (and any related distribution equivalent rights) were generally to be settled in cash. As described above, pursuant to the terms of the Phantom Unit Settlement Agreement, each NEO that was to receive a cash amount in settlement of their phantom units became eligible instead to receive a portion of that settlement amount and forfeited, without consideration, his right to receive any remaining portion of the settlement amount. The aggregate settlement amount to be awarded to all executive officers, including each of NEOs, was $13.8 million, and the executive officers, including each of NEOs, agreed to forfeit an aggregate of $7.8 million pursuant to the Phantom Unit Settlement Agreements, each in proportion to each executive officer’s settlement amount.
(c) Represents initial grants of restricted stock units ("RSU") in the Company to our NEOs after the consummation of the Corporate Reorganization under our 2018 Incentive Plan. The following vesting schedule applies to the restricted stock units awarded in 2018: (i) 25% on March 1, 2020; (ii) 25% on March 1, 2021, and (ii) the remaining 50% on March 1, 2022, calculated in accordance with the Financial Accounting Standards Board’s Accounting Standards Codification Topic 718, Compensation — Stock Compensation. The grant date fair value of RSUs is determined using the fair value of our common stock on the date of grant. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan with no recovery.
(d) The market value of the restricted stock units, based on the closing price of the Partnership’s units on March 23, 2018, the approval date, for each NEO is as follows: Mr. Horne: $2,700,000; Mr. Westcott: $7,500,000; and Mr. Hammond: $4,500,000. The information in this footnote is provided as supplemental to, and not as a substitute for, the information

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presented in accordance with SEC rules in the 2019 Summary Compensation Table. Upon the occurrence of the Effective Date, all then existing equity was extinguished in accordance with the Plan with no recovery.
(e) For 2019, reflects the aggregate sum of incentive cash compensation paid to each NEO under the Company’s 2019
Key Employee Incentive Plan.
(f) Reflects for 2019: $15,458 of 401(k) employer matching contributions. Reflects for 2018: $22,000 of 401(k) employer matching contributions and $51,977 of unit distributions received by Mr. Horne on his phantom units. As described above, in connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. For phantom units, amounts, if any, for 2018 include the cash settlement amount provided for in Mr. Horne’s Phantom Unit Settlement Agreement, less any amount already accounted for in the “Unit Awards” column.
(g) Reflects for 2019: $19,000 of 401(k) employer matching contributions. Reflects for 2018: $18,500 of 401(k) employer matching contributions and $47,874 of unit distributions received by Mr. Westcott on his phantom units. As described above, in connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. For phantom units, amounts, if any, for 2018 include the cash settlement amount provided for in Mr. Westcott’s Phantom Unit Settlement Agreement, less any amount already accounted for in the “Unit Awards” column.
(h) Reflects for 2019: $21,600 of 401(k) employers matching contributions. Reflects for 2018: $22,000 of 401(k) employer matching contributions. As described above, in connection with the Corporate Reorganization, all outstanding awards granted under the Partnership LTIP automatically vested in full pursuant to the terms of the Partnership LTIP and the individual award agreements thereunder. For phantom units, amounts, if any, for 2018 include the cash settlement amount provided for in Mr. Hammond’s Phantom Unit Settlement Agreement, less any amount already accounted for in the “Unit Awards” column.
(i) Reflects for 2019: $15,833 of 401(k) employers matching contribution for Mr. Norris.

Outstanding Equity Awards at 2019 Fiscal Year-End

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

Employment Agreements

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

Key Employee Incentive Plan

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

Retention Agreements

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

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

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

48

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

Director Compensation

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

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

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

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

Director Compensation for the 2019 Fiscal Year
Change in Pension Value and Nonqualified Deferred Compensation Earnings
YearFees Earned ($)(a)Share and Unit Awards ($)Option Awards ($)Non-Equity Incentive Plan Compensation ($)All Other Compensation ($)Total ($)
Paul T. Horne2019$265,750  $125,000  $—  $—  $—  $—  $390,750  
James Daniel Westcott2019$—  $—  $—  $—  $—  $—  $—  
William R. Granberry2019$232,750  $125,000  $—  $—  $—  $—  $357,750  
G. Larry Lawrence2019$255,500  $125,000  $—  $—  $—  $—  $380,500  
Kyle D. Vann2019$238,500  $125,000  $—  $—  $—  $—  $363,500  
Douglas W. York2019$215,250  $125,000  $—  $—  $—  $—  $340,250  

a.Includes $25,000 and $5,000 that Mr. Lawrence received for his service as chairman of the audit committee and chairman of a committee formed in connection with the Chapter 11 cases, respectively, $10,000 that Mr. Granberry received for his service as chairman of the nominating and governance committee, and $15,000 that Mr. Vann received for his service as chairman of the compensation committee.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership of our common stock as of April 27, 2020 for:

each person known by us to be a beneficial owner of 5% or more of our outstanding shares;
each director;
each named executive officer; and
all directors and executive officers as a group.

The amounts and percentage of shares beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Under

49

these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, to the Company’s knowledge the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them, subject to community property laws where applicable. Percentage of total shares beneficially owned is based on 61,062,850 shares outstanding as of April 27, 2020. Unless otherwise noted, the business address for the beneficial owners listed below is 303 W. Wall, Suite 1800, Midland, Texas 79701.
Shares Beneficially Owned
OwnerNumberPercentage
Directors, Named Executive Officers and Executive Officers
Richard Betz0*
David Coppé0*
Gary Gould0*
Robert Horn0*
Douglas W. York0*
James Daniel Westcott0*
Kyle M. Hammond0*
Robert L. Norris0*
Paul T. Horne0*
All directors and executive officers as a group (12 persons)0*
Greater than 5% Stockholder
GSO Entities (1)53,450,11588 %
Canyon Capital Advisors LLC (2)4,307,397%
* Percentage of shares beneficially owned does not exceed 1%

(1)GSO ADGM I LGCY LP directly holds 282,940 shares of common stock; GSO Energy Select Opportunities Fund AIV-3 LP directly holds 19,439,650 shares of common stock; GSO Energy Partners-A LP directly holds 3,419,771 shares of common stock; GSO Energy Partners-B LP directly holds 1,304,778 shares of common stock; GSO Energy Partners-C LP directly holds 1,759,624 shares of common stock; GSO Energy Partners-C II LP directly holds 1,666,898 shares of common stock; GSO Energy Partners-D LP directly holds 2,609,519 shares of common stock; GSO Palmetto Opportunistic Investment Partners LP directly holds 2,158,022 shares of common stock; and GSO CSF III AIV-3 LP (collectively, with the other direct holders described in this paragraph, the “GSO Entities”) directly holds 20,808,913 shares of common stock.

GSO Aiguille des Grands Montets Fund I LP is the sole limited partner and beneficial owner of GSO ADGM I LGCY LP. GSO Capital Partners LP is the investment manager of GSO Aiguille des Grands Montets Fund I LP. GSO Advisor Holdings L.L.C. is the special limited partner of GSO Capital Partners LP with the investment and voting power over the securities beneficially owned by GSO Capital Partners LP. Blackstone Holdings I L.P. is the sole member of GSO Advisor Holdings L.L.C.

GSO Energy Select Opportunities Associates LLC is the general partner of GSO Energy Select Opportunities Fund AIV-3 LP. GSO Energy Partners-A Associates LLC is the general partner of GSO Energy Partners-A LP. GSO Energy Partners-B Associates LLC is the general partner of GSO Energy Partners-B LP. GSO Energy Partners-C Associates LLC is the general partner of GSO Energy Partners-C LP. GSO Energy Partners-C Associates II LLC is the general partner of GSO Energy Partners-C II LP. GSO Energy Partners-D Associates LLC is the general partner of GSO Energy Partners-D LP. GSO Palmetto Opportunistic Associates LLC is the general partner of GSO Palmetto Opportunistic Investment Partners LP. GSO Capital Solutions Associates III LLC is the general partner of GSO CSF III AIV-3 LP. GSO Holdings I L.L.C. is the managing member of each of GSO Energy Select Opportunities Associates LLC, GSO Energy Partners-A Associates LLC, GSO Energy Partners-B Associates LLC, GSO Energy Partners-C Associates LLC, GSO Energy Partners-C Associates II LLC, GSO Energy Partners-D Associates LLC, GSO Palmetto Opportunistic Associates LLC and GSO Capital Solutions Associates III LLC. Blackstone Holdings II L.P. is the managing member of GSO Holdings I L.L.C. with respect to securities beneficially owned by the GSO Entities.

50


Blackstone Holdings I/II GP L.L.C. is the general partner of each of Blackstone Holdings I L.P. and Blackstone Holdings II L.P. The Blackstone Group Inc. is the sole member of Blackstone Holdings I/II GP L.L.C. Blackstone Group Management L.L.C. is the sole holder of the Class C common stock of The Blackstone Group Inc. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Each of the foregoing entities and individuals disclaims beneficial ownership of the securities held directly by the GSO Entities (other than the GSO Entities to the extent of their direct holdings). The business address of the GSO Entities is c/o GSO Capital Partners LP, 345 Park Avenue, 31st Floor, New York, New York 10154.

(2)Canyon Capital Advisors LLC (“Canyon”) is the investment advisor or co-investment advisor to various private funds and other investment vehicles (collectively, the “Funds” and each a “Fund”) owning
4,307,397 shares of Legacy’s common stock
(the “Shares”). Each Fund is currently a party to an investment advisory agreement (or similarly titled agreement) with Canyon, pursuant to which Canyon is granted discretionary right, power and authority to manage, and vote with respect to certain of the Funds’ investments, including each Fund’s investment in the Shares. Joshua S. Friedman and Mitchell R. Julis (the “Principals”) are the Managing Partners of Canyon and may be deemed to share voting or dispositive control over the Shares owned by the Funds. Canyon and each of the Principals disclaim beneficial ownership of the Shares, except to the extent of their individual pecuniary interests therein. The address for Canyon Capital Advisors LLC is 2000 Avenue of the Stars, 11th Floor, Los Angeles, CA 90067.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table provides information as of December 31, 2019 with respect to the shares that may be issued under our existing equity compensation plan.
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and RightWeighted Average Exercise Price of Outstanding Options, Warrants and RightsNumber 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




51

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
Certain Relationships and Related Party Transactions

Transactions Related to the Chapter 11 Cases

Rights Offering and Noteholder Backstop Agreement

On the Effective Date, pursuant to the Plan, Canyon Capital Advisors LCC and certain of their affiliates, as holders of claims arising under the indentures governing our Notes, received shares of common stock in satisfaction of such claims and pursuant to the Noteholder Backstop Commitment Agreement, dated as of June 13, 2019, and for their participation in the Company’s $66.5 million rights offering. See Note 1 of the Notes to Consolidated Financial Statements for more information regarding the rights offering and noteholder backstop agreement.

Term Loan Credit Agreement and Sponsor Backstop Agreement

On the Effective Date, pursuant to the Plan, GSO and certain of its affiliates, as holders of claims arising under the indentures governing our Notes and 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, received shares of common stock in satisfaction of such claims. Pursuant to the Plan, the Company also received $189.8 million in proceeds from GSO and certain of its affiliates in exchange for the issuance of shares of common stock, pursuant to the Sponsor Backstop Commitment Agreement, dated June 13, 2019, among Legacy and GSO and certain of its affiliates. See Note 1 of the Notes to Consolidated Financial Statements for more information regarding the sponsor backstop agreement and Note 5 of the Notes to Consolidated Financial Statements for more information regarding the Term Loan Credit Agreement.

Transactions with Other Related Persons

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 $55,165 and $169,949 in 2019 and 2018, respectively to Blue Quail for such services.

Travis McGraw, the brother of former Legacy executive officer Kyle A. McGraw, is an employee of Legacy serving as Legacy’s Production Accounting/Marketing Manager. The aggregate value of compensation paid by us to Travis McGraw in 2018 was less than $250,000. There were no material differences between the compensation paid to Travis McGraw and the compensation paid to any other employees who hold analogous positions.

Alan McGraw, the son of former Legacy executive officer Kyle A. McGraw, was an employee of Legacy until March 2019, serving as a Landman. The aggregate value of compensation paid by us to Alan McGraw in 2018 was less than $200,000. There were no material differences between the compensation paid to Alan McGraw and the compensation paid to any other employees who hold analogous positions.

Parents

GSO beneficially holds approximately 88% of our outstanding shares as of April 27, 2020.

Board Independence

We are not subject to listing requirements of any national securities exchange or national securities association and, as a result, we are not at this time required to have our Board comprised of a majority of “independent directors.” In accordance with Item 407(a) of Regulation S-K of the Securities Act of 1933 and the Securities Exchange Act of 1934, we reference the definition of “Independent Director” as provided by Rule 5605(a)(2)(A)-(F) of the Nasdaq Equity Rules. In applying this definition, we believe the following directors could each meet the definition of “Independent Director” within the meaning of such rules, even though such rules do not currently apply to us, as we are not listed with the Nasdaq: Messrs. Coppé, Betz, Gould, and York.

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 were:

52


Year ended December 31
20192018
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 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 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.



53

PART IV
 
ITEM 15.EXHIBITS, 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.
 

54

(a)(3) Exhibits
 
The following documents are filed as a part of this annual report on Form 10-K or incorporated by reference: 


55


Exhibit  
Number Description
10.1—  
10.2—  
10.3—  
10.4†—  
10.5†—  
10.6†—  
10.7†—  
10.8†—  
10.9†—  
10.10†—  
10.11†—  
10.12†—  
10.13†—  





56




Exhibit  
Number Description
21.1*—  
24.1*—  
31.1*—  
31.2*—  
32.1*—  
99.1*—  
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.

57

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 29th day of April, 2020.
 
LEGACY RESERVES INC.
  
  
By:
/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 ControllerApril 29, 2020
Micah C. Foster(Principal Accounting Officer)
/S/     RICHARD F. BETZ
DirectorApril 29, 2020
Richard F. Betz
/S/     DAVID COPPÉ
DirectorApril 29, 2020
David Coppé
/S/     GARY GOULD
DirectorApril 29, 2020
Gary Gould
/S/   ROBERT HORN
DirectorApril 29, 2020
Robert Horn
/S/     DOUGLAS W. YORK Director April 29, 2020
Douglas W. York    


58

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
 Page
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements: 
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Unaudited Supplementary Information

F-1

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

LEGACY RESERVES INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2019 AND 2018  
F-3

SuccessorPredecessor
 20192018
 (In thousands)
ASSETS
Current assets:  
Cash$4,306  $1,098  
Restricted cash24,039  —  
Accounts receivable, net:
Oil and natural gas62,543  56,615  
Joint interest owners15,842  15,370  
Other —  
Fair value of derivatives (Notes 11 and 12)569  66,662  
Prepaid expenses and other current assets9,708  11,347  
Total current assets117,009  151,092  
Oil and natural gas properties, at cost:  
Proved oil and natural gas properties using the successful efforts method of accounting650,839  3,471,456  
Unproved properties280,025  19,863  
Accumulated depletion, depreciation, amortization and impairment(4,921) (2,177,006) 
Total oil and natural gas properties, net925,943  1,314,313  
Other property and equipment, net of accumulated depreciation and amortization of $— and $12,323, respectively5,993  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 payable12,021  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  
Other28,717  13,953  
Total current liabilities116,876  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 liabilities2,055  643  
Total liabilities639,725  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 capital405,559  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

See accompanying notes to consolidated financial statements.
F-5

LEGACY RESERVES INC.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
SuccessorPredecessor
Period fromPeriod fromYear Ended December 31,
December 11, 2019January 1, 2019
to December 31,to December 10,
(In thousands, except per share data)2019201920182017
 
Revenues:   
Oil sales$23,232  $300,905  $375,444  $239,448  
Natural gas liquids (NGL) sales916  14,082  27,750  24,796  
Natural gas sales6,016  101,488  151,667  172,057  
Total revenues30,164  416,475  554,861  436,301  
Expenses:   
Oil and natural gas production9,779  173,232  200,285  183,219  
Exploration Expense750  —  —  —  
Production and other taxes1,564  22,371  29,532  19,825  
General and administrative1,470  77,364  73,039  49,372  
Depletion, depreciation, amortization and accretion6,259  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 expenses19,257  537,564  507,029  418,243  
Operating income (loss)10,907  (121,089) 47,832  18,058  
Other income (expense):   
Interest income 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  —  —  
Other42   722  792  
Income (loss) before income taxes3,053  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 Diluted61,063  114,811  105,087  100,049  

See accompanying notes to consolidated financial statements.
F-6

LEGACY RESERVES INC.
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS'/UNITHOLDERS’ DEFICIT
FOR THE YEARS ENDED DECEMBER 31, 2018 (Predecessor) AND 2017 (Predecessor)
 
Series A Preferred EquitySeries B Preferred EquityIncentive Distribution EquityUnitholders' Equity (Deficit)Stockholders' Deficit
UnitsAmountUnitsAmountUnitsAmount Limited Partner UnitsLimited Partner AmountGeneral Partner AmountSharesPar ValueAPICAcc. DeficitTotal Deficit
 (In thousands)
Balance, December 31, 20162,300  $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, 20172,300  $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.





























F-7

LEGACY RESERVES INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)

Stockholders' Equity (Deficit)
SharesPar ValueAPICAcc. DeficitTotal 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 exchange5,368  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 Offering27,705  277  256,300  —  256,577  
Issuance of Successor common stock33,358  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  





F-8

LEGACY RESERVES INC.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017
SuccessorPredecessor
Period fromPeriod from
December 11, 2019January 1, 2019
to December 31,to December 10,Year Ended December 31,
(In thousands)2019201920182017
 
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 accretion6,259  156,935  159,998  126,938  
Amortization of debt discount and issuance costs123  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 derivatives6,292  52,337  (49,099) (19,711) 
Equity in income (loss) of equity method investees 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 gas1,129  (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   
Increase (decrease) in accounts payable3,794  (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 assets350  1,608  54,968  11,099  
Investment in other equipment150  (4,003) (406) (593) 
Corporate Reorganization—  —  (3,120) —  
Distribution from equity method investee—  660  —  —  
Net cash settlements on commodity derivatives76  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 debt17,000  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  —  —  
F-9

                    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 items14,307  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.
F-10

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
F-11

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”).

F-12

Table of Contents   LEGACY RESERVES INC.
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.

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.

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.

F-13

Table of Contents   LEGACY RESERVES INC.
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 equivalents16,563  
Indicated invested capital value785,596  
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 equivalents16,563  
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.


F-14

Table of Contents   LEGACY RESERVES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


As of December 11, 2019
Reorganization AdjustmentsFresh-Start Adjustments
(in thousands)PredecessorSuccessor
ASSETS
Current assets:
     Cash$7,187  $9,376  (1)$—  $16,563  
     Restricted cash3,450  23,936  (1)—  27,386  
     Accounts receivable, net:
Oil and natural gas63,672  —  —  63,672  
Joint interest owners13,213  —  —  13,213  
Other —  —   
     Fair value of derivatives—  —  —  —  
     Prepaid expenses and other current assets10,465  —  —  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 accounting3,565,631  —  (2,918,997) (10)646,634  
Unproved properties20,244  —  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 amortization5,949  —  235  (10)6,184  
Operating rights, net of amortization574  —  (545) (11)29  
Fair value of derivatives91  —  —  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 payable5,350  2,875  (5)—  8,225  
Accrued oil and natural gas liabilities63,965  —  —  63,965  
Fair value of derivatives4,749  —  —  4,749  
Asset retirement obligation3,938  —  801  (12)4,739  
Other50,223  (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 obligation257,984  —  (110,537) (12)147,447  
Fair value of derivatives2,118  —  —  2,118  
Other long-term liabilities2,096  —  —  2,096  
     Total liabilities not subject to compromise986,423  (218,615) (109,736) 658,072  
     Liabilities subject to compromise789,802  (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  


F-15

Table of Contents   LEGACY RESERVES INC.
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 Facility388,000  
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 Payable29,478  
Accounts Payable2,875  
Total Liabilities Subject to Compromise789,802  
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 equity44,345  
Net impact to accumulated deficit$679,904  

Fresh Start Adjustments

F-16

Table of Contents   LEGACY RESERVES INC.
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
PredecessorSuccessor
Oil and Gas Properties
Proved properties$3,565,631  $(2,918,997) $646,634  
Unproved properties20,244  259,759  280,003  
Total Oil and Gas Properties3,585,875  (2,659,238) 926,637  
Less - Accumulated depletion, depreciation and impairment(2,424,454) 2,424,454  —  
Net Oil and Gas Properties1,161,421  (234,784) 926,637  
Furniture, Fixtures, and other equipment18,782  (12,598) 6,184  
Less - Accumulated depreciation(12,833) 12,833  —  
Net Furniture, Fixtures and other equipment5,949  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):


SuccessorPredecessor
Period from December 11, 2019 to December 31, 2019Period 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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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.

(c) Accounts Receivable
 
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).

SuccessorPredecessor
Period from December 11, 2019 to December 31,Year ended December 31,
(In thousands)20192018
Revenue payable to joint interest21,103  22,750  
Accrued lease operating expense20,713  41,227  
Accrued capital expenditures8,880  24,690  
Accrued ad valorem tax5,723  5,255  
Other4,757  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.

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.

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.

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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

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.

(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):

SuccessorPredecessor
Year ended December 31,Year ended December 31,
(In thousands)20192018
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.

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.

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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 DateEarly 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

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

NGL and Natural Gas Sales

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

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

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.
 SuccessorPredecessor
 Period from December 11, 2019 to December 31,Period from January 1, 2019 to December 10,
(In thousands)20192019
Revenues: 
Oil sales$23,232  $300,905  
Natural gas liquids (NGL) sales916  14,082  
Natural gas sales6,016  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 ValueGross Amounts Offset in the Consolidated Balance SheetsNet 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) $—  $(13,145) 
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December 31, 2018 (Predecessor)
 Fair Value Measurements Using
Quoted Prices in
Active Markets for
Identical Assets
Significant Other
Observable
Inputs
Significant
Unobservable
Inputs
Total Fair ValueGross Amounts Offset in the Consolidated Balance SheetsNet Amounts Presented in the Consolidated Balance Sheets
Description(Level 1)(Level 2)(Level 3)
 (In thousands)
Assets:
Current
Commodity derivatives$—  $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)
 SuccessorPredecessor
Period from December 11, 2019 to December 31,Period from January 1, 2019 to December 10,December 31,
(In thousands)2019201920182017
Beginning balance$—  $—  $(5,088) $ 
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) 
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(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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



(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 derivati