Annual Report (10-k)

Date : 03/22/2019 @ 8:05PM
Source : Edgar (US Regulatory)
Stock : Legacy Reserves Inc. (MM) (LGCY)
Quote : 0.0395  0.0 (0.00%) @ 1:00AM

Annual Report (10-k)

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________
  Form 10-K
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2018
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from               to
Commission file number 1-38668
__________________
  Legacy Reserves Inc.
(Exact name of registrant as specified in its charter)
__________________
Delaware
82-4919553
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
 
 
303 W. Wall Street, Suite 1800
79701
Midland, Texas
(Zip Code)
(Address of principal executive offices)
 
Registrant’s telephone number, including area code:
(432) 689-5200
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.01 par value listed on the NASDAQ Stock Market LLC.

Securities registered pursuant to 12(g) of the Act:
None.
______________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o      No  þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes   o      No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      No  o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  þ      No  o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer  þ
Non-accelerated filer  o


Smaller reporting company  o

 
 
Emerging growth company  o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o  No  þ
The aggregate market value of units representing limited partner interests ("units") in Legacy Reserves LP (predecessor registrant to Legacy Reserves Inc.) held by non-affiliates of the registrant was approximately $452.5 million on June 30, 2018 , based on $6.90 per unit, the last reported sales price of the units on the NASDAQ Global Select Market on such date.
114,810,671 shares of common stock, par value $0.01, of the registrant were outstanding as of March 20, 2019.
DOCUMENTS INCORPORATED BY REFERENCE
Parts of the definitive proxy statement for the registrant’s 2019 annual meeting of stockholders are incorporated by reference into Part III of this annual report on Form 10-K.
 



LEGACY RESERVES INC.

Table of Contents
 
 
 
 
PART I
 
 
 
ITEM 1.
 
 
 
ITEM 1A.
 
 
 
ITEM 1B.
 
 
 
ITEM 2.
 
 
 
ITEM 3.
 
 
 
ITEM 4.
 
 
 
PART II
 
 
 
ITEM 5.
  32
 
 
 
ITEM 6.
 
 
 
ITEM 7.
  35
 
 
 
ITEM 7A.
 
 
 
ITEM 8.
 
 
 
ITEM 9.
  59
 
 
 
ITEM 9A.
 
 
 
ITEM 9B.
 
 
 
PART III
 
 
 
ITEM 10.
 
 
 
ITEM 11.
 
 
 
ITEM 12.
  62
 
 
 
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.
 

ii


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. Reserves that can be expected to be recovered through: (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Proved developed non-producing or PDNPs. Proved oil and natural gas reserves that are developed behind pipe or shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
 
Proved reserves. Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
 
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs . Proved undeveloped oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Proved reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Proved undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
 
Reserve acquisition cost. The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.
 
R/P ratio (reserve life). The reserves as of the end of a period divided by the production volumes for the same period.
 
Reserve replacement. The replacement of oil and natural gas produced with reserve additions from acquisitions, reserve additions and reserve revisions.
 

iii


Reserve replacement cost. An amount per Boe equal to the sum of costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural gas prices in past years have increased the economic life of reserves, adding additional reserves with no required capital expenditures. On the other hand, increases in oil and natural gas prices have increased the cost of reserve purchases and reserves added through development projects. The reserve replacement cost may not be indicative of the economic value of the reserves added due to differing lease operating expenses per barrel, differing timing of production, and other qualitative factors.
 
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
 
Standardized measure. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission (using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price for each month) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Texas margin taxes and the federal income taxes associated with a corporate subsidiary have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure. Standardized measure does not give effect to commodity derivative transactions.
 
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
 
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:

our ability to pursue financial, transactional and other strategic alternatives to address our liquidity and capital structure;

the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, debt refinancing or extensions, exchanges or repurchases of debt, issuances of debt or equity securities, access to additional borrowing capacity and our ability to generate sufficient cash flow from operations to fund our capital expenditures and meeting working capital needs;

our ability to comply with, renegotiate or receive waivers of debt covenants under our Credit Agreement (as defined below) and our Term Loan Credit Agreement (as defined below);

our business strategy;

the amount of oil and natural gas we produce;

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

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

our ability to replace reserves and increase reserve value;

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

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

the level of our capital expenditures;

our ability to divest non-core assets at economically attractive prices;

our future operating results; and

our plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this document, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
 
The forward-looking statements contained in this document are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this document are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in Item 1A. under "Risk Factors.” The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly.
 


v


PART I

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

we had proved reserves of approximately 164.9 MMBoe, of which 63% were natural gas, 37% were oil and natural gas liquids (“NGLs”) and 96% were classified as proved developed producing; and

our proved reserves to production ratio was approximately 9.5 years based on the annualized production volumes for the three months ended December 31, 2018 .

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

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

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

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

2018 and Current Highlights

Deployed $229.5 million of development capital expenditures, primarily focused on the drilling and completion of our Permian Basin horizontal development assets;

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

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

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

1


In March 2019, we extended the term on our Credit Agreement through May 31, 2019.
 
Business Strategy
 
The key elements of our business strategy are to:

Prudently deploy capital in development opportunities that maximize value;

Identify, acquire and exploit additional opportunities to broaden our operational footprint and enrich our future growth potential;
Utilize our extensive Permian portfolio of small-tract acreage to increase our drillable footprint;

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

Rationalize our asset base by regularly reviewing our asset portfolio and divesting non-core assets; and
Maintain capital budget flexibility to preserve liquidity.

2019 Operating Focus

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

Operating Regions

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

East Texas. We entered the East Texas region through our July 2015 acquisitions in Anderson, Freestone, Houston, Leon, Limestone, Robertson and Shelby counties. 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.
 

2


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

Proved Reserves by Operating Region as of December 31, 2018
Operating Regions
 
Oil (MBbls)
 
Natural
Gas (MMcf)
 
NGLs(MBbls)
 
Total (MBoe)
 
% Liquids
 
% PDP
 
% Total
Permian Basin
 
44,671

 
116,879

 
660

 
64,811

 
70
%
 
90
%
 
39
%
East Texas
 
103

 
292,249

 
211

 
49,022

 
1
%
 
100
%
 
30
%
Rocky Mountain
 
6,479

 
206,541

 
7,257

 
48,160

 
29
%
 
100
%
 
29
%
Mid-Continent
 
824

 
6,051

 
1,083

 
2,916

 
65
%
 
92
%
 
2
%
Total
 
52,077

 
621,720

 
9,211

 
164,909

 
37
%
 


 
100
%

Development Activities

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

The table below details the activity in our PUD locations from December 31, 2017 to December 31, 2018 :
 
Gross Locations
 
Net Locations
 
Net Volume (MBoe)
Balance, December 31, 2017
40

 
20.1

 
7,963

PUDs converted to PDP by drilling
(19
)
 
(9.5
)
 
(5,807
)
PUDs removed due to performance (a)
(2
)
 
(0.3
)
 
(89
)
PUDs removed from future drilling schedule (b)
(3
)
 
(1.0
)
 
(570
)
Extensions and discoveries (a)
16

 
10.8

 
4,659

Other

 
0.3

 
40

Balance, December 31, 2018
32

 
20.4

 
6,196

________________

(a)
PUDs removed due to performance or added due to extensions and discoveries are those PUDs removed or added, as applicable, due to new or revised engineering, geologic and economic evaluations such as offset well production data, the drilling of offset wells, new geologic data or changes in projected capital costs or product prices. PUDs are removed or added depending on whether the technical criteria for the proved undeveloped reserve classification is satisfied and, in the case of additions due to performance, whether the well is scheduled to be drilled within five years after initial recognition as proved reserves.
The increases in PUDs due to extensions and discoveries were driven by offset drilling in connection with our drilling program in the Permian Basin, which includes the horizontal Spraberry, horizontal Wolfcamp and horizontal Bone Spring wells.
The reduction in PUDs due to performance was due to the removal of PUDs as they became uneconomic as of December 31, 2018 based on offset well performance.
(b)
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.
As of December 31, 2018 , we identified 10 gross ( 6.4 net) recompletion and fracture stimulation projects.

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

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

3


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

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

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

The Acceleration Payment was funded by a $145 million draw under our Term Loan Credit Agreement.

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

Oil and Natural Gas Derivative Activities
 
Our business strategy includes entering into oil and natural gas derivative contracts which are designed to mitigate price risk for a portion of our oil, NGL and natural gas production from time to time. At December 31, 2018 , we had in place oil and natural gas derivatives covering portions of our estimated future oil and natural gas production. Our derivative contracts are in the form of fixed price swaps and enhanced swaps for NYMEX WTI oil; fixed price swaps for NYMEX Henry Hub; and fixed price swaps for the Midland-to-Cushing oil differential.

Marketing and Major Purchasers
 
For the year ended December 31, 2018 and 2017 , Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to the purchasers as detailed in the table below. For the year ended December 31, 2016 , Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer.
 
2018
 
2017
 
2016
Plains Marketing, LP
20%
 
10%
 
6%
Rio Energy International Inc
13%
 
9%
 
3%

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.
 

4


Competition
 
We operate in a highly competitive environment for acquiring leases and properties, securing and retaining trained personnel and service providers and marketing oil and natural gas. Our competitors may be able to pay more for leases, productive oil and natural gas properties and development projects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
 
Seasonal Nature of Business
 
The demand for oil and natural gas can be seasonal based on motor vehicle driving patterns and heating and cooling demands related to weather. Our Rockies' oil prices suffer relative to WTI in the winter due to reduced demand for asphaltic crude. Refinery turnarounds in the Permian typically occur in the first quarter, and, historically, we have experienced wider oil differentials during this time.
 
Environmental Matters and Regulation
 
General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

require the acquisition of various permits before drilling commences;

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

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.

5


 
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.
 
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, regulates emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources including pursuing the energy extraction sector under a National Compliance Initiative. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. In addition, more stringent federal, state and local regulations, such as the EPA rules issued in May 2016 regarding the aggregation of exploration and production equipment as a single source could result in increased costs and the need for operational changes. Finally, the EPA issued rules in May 2016 covering methane emissions from new oil and natural gas industry operations which could result in additional costs and restrictions on our operations.
 
OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.
 

6


In 2009, the EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources, including the oil and natural gas production industry. In May 2016, the EPA finalized regulations that establish new controls for emissions of methane and volatile organic compounds from oil and natural gas operations. Additional regional, federal or state requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our products. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
 
We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2018 . Additionally, as of the date of this document, we are not aware of any environmental issues or claims that require material capital expenditures during 2019 . However, we cannot assure investors that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operations.

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

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

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

the location of wells; 
the method of drilling and casing wells;

7


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 pro-ration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally regulate and seek to restrict the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
 
Natural gas regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or the FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.
 
Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.
 
State regulation. The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. New Mexico currently imposes a 3.75% severance tax on both oil and natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
 
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
 
Employees
 
As of December 31, 2018 , we had 337 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.


8


Available Information
 
We make available free of charge on our website, www.legacyreserves.com , our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such information with, or furnish it to, the Securities and Exchange Commission ("SEC"). The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov .

The 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 SEC.


9


ITEM 1A.
RISK FACTORS
 
Risks Related to our Business
 
We have determined, and our independent registered public accounting firm has concurred, that there is substantial doubt about our ability to continue as a going concern.
We have significant obligations and commitments coming due in the near term. On March 21, 2019, we entered into an amendment to the Credit Agreement pursuant to which the lenders agreed to extend the maturity date from April 1, 2019 to May 31, 2019. Without additional sources of capital or a significant restructuring of our balance sheet, the maturity of our Credit Agreement raises substantial doubt about our ability to continue as a going concern, which means that we may be unable to continue operations for the foreseeable future or realize assets and discharge liabilities in the ordinary course of operations. As a result, our independent registered public accounting firm included an explanatory paragraph with respect to this uncertainty in its report that is included with our financial statements in this annual report on Form 10-K. Such explanatory paragraph may materially and adversely affect the price per share of our common stock and may otherwise limit our ability to raise additional funds through the issuance of debt or equity securities or otherwise. Further, the perception that we may be unable to continue as a going concern may impede our ability to raise additional funds or operate our business due to concerns with respect to our ability to discharge our contractual obligations.
We have prepared our financial statements on a going concern basis, which contemplates that we will be able to realize our assets and discharge our liabilities and commitments in the ordinary course of business. Our financial statements included in this annual report on Form 10-K do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty. Without additional capital or a significant restructuring of our balance sheet, however, we may be unable to continue as a viable entity, in which case our stockholders may lose all or some of their investment in us.
We have engaged financial and legal advisors to assist us in, among other things, evaluating financial, transactional and other strategic alternatives to address our liquidity and capital structure that may be time consuming, disruptive and costly to our business.
As a result of extremely challenging current market conditions and our upcoming debt maturities, on March 13, 2019, we announced that we engaged financial and legal advisors to assist in evaluating financial, transactional and other strategic alternatives to address our liquidity and capital structure. The process of exploring strategic alternatives may be time consuming and disruptive to our business operations and may impair our ability to retain and motivate key personnel. We may incur substantial expenses associated with identifying, evaluating and preparing for any such strategic alternatives. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets. There can be no assurance that sufficient liquidity can be raised from any one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations or at all.
We may need to seek relief under the U. S. Bankruptcy Code, even if we are successful in effecting a financial, transactional or other strategic alternative. Any bankruptcy proceeding may result in holders of our equity securities and our other stakeholders receiving little or no consideration.
It may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code. Such a proceeding could be commenced in the near term and requires our conducting of preparatory work. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.
If we are unable to refinance or repay our indebtedness under our Credit Agreement when it comes due or otherwise fail to comply with certain restrictions and financial covenants in our Credit Agreement and Term Loan Credit Agreement, we could be in default under our Credit Agreement or Term Loan Credit Agreement which may result in acceleration or repayment of all of our outstanding indebtedness.
We could default on the payment of our indebtedness under our Credit Agreement when it comes due which may result in acceleration of all amounts outstanding under our Credit Agreement or foreclosure on our oil and natural gas properties. Additionally, our Credit Agreement and our Term Loan Credit Agreement restrict, among other things, our ability to incur debt and requires us

10


to comply with certain financial covenants and ratios.  We may not be able to comply with these restrictions and covenants in the future and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control.  Our failure to comply with any of the restrictions and covenants under our Credit Agreement or our Term Loan Credit Agreement could result in a default under our Credit Agreement or our Term Loan Credit Agreement.  On March 21, 2019, we received a waiver of certain covenants under our Credit Agreement and Term Loan Credit Agreement.  The waiver received under our Term Loan Credit Agreement is temporary such that we will be in default for the failure to have delivered audited financial statements without a “going concern” or like qualification or exception as of May 31, 2019, the same day as the scheduled maturity of our Credit Agreement. Further, upon delivery of our financial statements for the quarter ended March 31, 2019, we expect to be in violation of the current ratio covenant under our Credit Agreement, which would constitute a default under the Credit Agreement. Although we have received waivers from our lenders under the Credit Agreement and the Term Loan Credit Agreement in the past, there can be no assurances that we will receive any waivers in the future. If the lenders under our Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under our Credit Agreement or Term Loan Credit Agreement as a result of any such default, such acceleration could cause a cross-default of all of our other outstanding indebtedness and permit the holders of such indebtedness to accelerate the maturities of such indebtedness.
Our substantial indebtedness, liquidity issues and the potential for strategic alternatives or restructuring transactions may impact our business, financial condition and operations.
Due to our substantial indebtedness, liquidity issues and the potential for strategic alternatives or restructuring transactions, there is risk that, among other things:
third parties’ confidence in our ability to develop oil and natural gas properties could erode, which could impact our ability to execute on our business strategy;
it may become more difficult to retain, attract or replace key employees;
employees could be distracted from performance of their duties or more easily attracted to other career opportunities;
we could lose some or a significant portion of our liquidity, either due to stricter credit terms from vendors, or, in the event we undertake a Chapter 11 proceeding and conclude that we need to procure debtor-in-possession financing, an inability to obtain any needed debtor-in-possession financing or to provide adequate protection to certain secured lenders to permit us to access some or all of our cash; and
our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.

The occurrence of certain of these events may increase our operating costs and may have a material adverse effect on our business, results of operations and financial condition.
If oil and natural gas prices decline, our cash flow from operations will decline.

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

the domestic and foreign supply of and demand for oil and natural gas;
market expectations about future prices of oil and natural gas;
the price and quantity of imports of crude oil and natural gas;
overall domestic and global economic conditions;
political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
the willingness and ability of members of the Organization of Petroleum Exporting Countries and other petroleum producing countries to agree to and maintain oil price and production controls;
trading in oil and natural gas derivative contracts;
the level of consumer product demand;
weather conditions and natural disasters;

11


technological advances affecting energy production and consumption;
domestic and foreign governmental regulations and taxes;
the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;
the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
the price and availability of alternative fuels.

Historically, oil and natural gas prices have been extremely volatile. For example, for the five years ended December 31, 2018 , the NYMEX-WTI oil price ranged from a high of $107.95 per Bbl to a low of $26.19 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $8.15 per MMBtu to a low of $1.49 per MMBtu. As of February 28, 2019, the NYMEX WTI oil spot price was $57.21 per Bbl and the NYMEX-Henry Hub natural gas spot price was $2.89 per MMBtu. If oil and natural gas prices decline from current levels, it may have a material adverse effect on our operations and financial condition.

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

The growth of our business depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Historically, we have also acquired additional oil and natural gas reserves through acreage trades with other producers and we may not be able to identify or execute attractive acreage trades in the future. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties, including through acreage trades, containing proved reserves, or both. Further, the rate of estimated decline of our oil and natural gas reserves may increase if our wells do not produce as expected. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs. If oil and natural gas prices increase, our costs for additional reserves would also increase; conversely if natural gas or oil prices decrease, it could make it more difficult to fund the replacement of our reserves.
 
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

As of December 31, 2018 , we had total debt of approximately $1.3 billion . Our existing and future indebtedness could have important consequences to us, including:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;
covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
our access to the capital markets may be limited;
we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results and cash flows are not sufficient to service our current or future indebtedness, we will be forced to take actions such as further reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.


12


Our development projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves.
 
Our development and acquisition activities require substantial capital expenditures. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil and natural gas reserves. We intend to finance our future capital expenditures with cash flow from operations and, subject to availability, borrowings under our Credit Agreement and our Term Loan Credit Agreement. Our cash flow from operations and access to capital are subject to a number of variables, including:

our proved reserves;

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

capital and lending market conditions;

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

our ability to identify, acquire and exploit new reserves.

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

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, results of operations and financial condition.
 
Our drilling activities are subject to many risks, including the risk that we will not encounter commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
 
In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

the high cost, shortages or delivery delays of equipment, materials, and services;
unexpected operational events;
adverse weather conditions or events;
facility or equipment malfunctions;
title disputes;
regulatory changes and approvals;
pipeline ruptures or spills;
collapses of wellbore, casing or other tubulars;
unusual or unexpected geological formations;
loss of drilling fluid circulation;
formations with abnormal pressures;
fires;

13


blowouts, craterings and explosions;
interference from new well stimulation;
offset operations causing irregularities or interruptions in production; and
uncontrollable flows of oil, natural gas or well fluids.

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

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.
 
We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, results of operations and financial condition.

If commodity prices decline, a significant portion of our development projects may become uneconomic and cause write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition.
 
Lower oil and natural gas prices may not only decrease our revenues, but also may render many of our development and production projects uneconomic and result in a downward adjustment of our reserve estimates, which would negatively impact our borrowing base under our Credit Agreement and ability to fund operations.

A reduction in commodity prices may be caused by many factors, including substantial increases in U.S. production and reserves from unconventional (shale) reservoirs, without a corresponding increase in demand. The International Energy Agency forecasts continued U.S. oil production growth in 2019 . This environment could cause the prices for oil to fall to lower levels.

Furthermore, a decrease in oil and natural gas prices may render a significant portion of our development projects uneconomic. In addition, if oil and natural gas prices decline, our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. For example, in the year ended December 31, 2018 , we incurred impairment charges of $68.0 million , a portion of which was driven by commodity price changes. We may incur further impairment charges in the future related to depressed commodity prices, which could have a material adverse effect on our results of operations in the period taken.

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

Increased capital requirements for our projects will result in higher reserve replacement costs and could cause certain of our projects to become uneconomic even with increased commodity prices and therefore not to be implemented, reducing our production and cash flow. Decreased availability of drilling equipment and services could significantly impact the planned execution of our development program.


14


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

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

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

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

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

Due to regional fluctuations in the actual prices received for our natural gas production, the derivative contracts we enter into may not provide us with sufficient protection against price volatility since they are based on indexes related to different and remote regional markets.
 
We sell our natural gas into local markets, the majority of which is produced in East Texas, Colorado, West Texas, Southeast New Mexico, Central Oklahoma and Wyoming and shipped to the Midwest, West Coast and Texas Gulf Coast. These regions account for over 90% of our natural gas sales. In the past, we have used swaps on Northwest Pipeline, California SoCal NGI and San Juan Basin natural gas prices and we may do so again in the future. While we are paid a local price indexed to or closely related to these indexes, these indexes are heavily influenced by prices received in remote regional consumer markets less transportation costs and thus may not be effective in protecting us against local price volatility.

Decreases of our borrowing base under our Credit Agreement by our lenders, and any potential disruptions of the financial markets could adversely affect our business, results of operations and financial condition.

We depend on our Credit Agreement and our Term Loan Credit Agreement for future capital needs. Our Credit Agreement, which matures on May 31, 2019, limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. As of March 13, 2019 , our borrowing base was $575.0 million and we had approximately $2.9 million available for borrowing. Under the terms of our Credit Agreement, our borrowing base reduces to $570.0 million on May 22, 2019. Our Term Loan Credit Agreement for second lien term loans maturing on August 31, 2020 provides for up to an aggregate principal amount of $400.0 million, of which we have drawn $338.6 million .

15



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

Outstanding borrowings in excess of the borrowing base must be repaid within four months, and, if mortgaged properties represent less than 95% of total value of oil and natural gas properties used to determine the borrowing base, we must pledge other oil and natural gas properties as additional collateral. We may not have the financial resources in the future to make any mandatory principal prepayments required under our Credit Agreement.
 
Any decrease of our borrowing base could adversely affect our business, results of operations and financial condition.
 
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities.”

Any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations.
 
We may not achieve the expected results of any acquisition we complete, and any adverse conditions or developments related to any such acquisition may have a negative impact on our operations and financial condition.
 
Further, even if we complete any acquisitions, which we would expect to increase our cash flow, actual results may differ from our expectations and the impact of these acquisitions may actually result in a decrease in cash flow. Any acquisition involves potential risks, including, among other things:

the validity of our assumptions about recoverable reserves, development potential, future production, revenues, capital expenditures, future oil and natural gas prices, operating costs and potential environmental and other liabilities;
an inability to successfully integrate the assets and businesses we acquire;
a decrease in our liquidity by using a portion of our available cash or borrowing capacity under our Credit Agreement and our Term Loan Credit Agreement to finance acquisitions;
a lack of capital could cause the development of any acquisitions to be slower than forecasted;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
the diversion of management’s attention from other business concerns;
the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges; and
the loss of key purchasers.

Our decision to acquire a property depends in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, seismic data and other information, the results of which are often inconclusive and subject to various interpretations. Our estimates of future reserves and estimates of future development and production for our acquisitions and related forecasts of anticipated cash flow therefrom are initially based on detailed information furnished by the sellers and are subject to review, analysis and adjustment by our internal staff, typically without consulting with outside petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain and our proved reserves estimates and cash flow forecasts therefrom may exceed actual acquired proved reserves or the estimates of future cash flows therefrom. In connection with our assessments, we perform a review of the acquired properties included in our acquisitions that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems.
 
Also, our reviews of newly acquired properties are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an

16


inspection is undertaken. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.
 
Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities including the Bureau of Land Management. We may incur substantial costs in order to maintain compliance with these existing laws and regulations and could experience substantial disruptions to our operations if we do not timely receive permits required to drill new wells, especially on federal lands. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. All such costs or disruptions may have a negative effect on our business, results of operations and financial condition.
 
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
 
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to oil and natural gas exploration, production and restoration activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by environmental and other impacts of our operations.
 
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our financial condition could be adversely affected.

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

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

17


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

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

Restrictive covenants under the indentures governing our 2020 Senior Notes, 2021 Senior Notes and 2023 Convertible Notes may adversely affect our operations.     
The indentures governing the Senior Notes contains, and any future indebtedness we incur may contain, a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
sell assets, including equity interests in our restricted subsidiaries;
pay distributions on, redeem or purchase our equity or redeem or purchase our subordinated debt;
make investments;
incur or guarantee additional indebtedness or issue preferred units;
create or incur certain liens;
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets;
engage in transactions with affiliates;
create unrestricted subsidiaries; and
engage in certain business activities.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
A failure to comply with the covenants in the indentures governing the Senior Notes or any future indebtedness could result in an event of default under the indentures governing the Senior Notes, our Credit Agreement, our Term Loan Credit Agreement, or any future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. Further, if the lenders under our Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness as a result of a default under the Credit Agreement or Term Loan Credit Agreement, such acceleration could cause a cross-default of all our other outstanding indebtedness, including the Senior Notes, and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions.

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

18


inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations and financial condition.

Further, the present value of future net cash flows from our proved reserves may not be the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the trailing 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. To illustrate the price impact of commodity prices on our proved reserves subsequent to December 31, 2018 , we recalculated the value of our proved reserves as of  December 31, 2018 using the five-year average forward price as of February 25, 2019 for both WTI oil and NYMEX natural gas. While this 5-year NYMEX forward strip price is not necessarily indicative of our overall outlook on future commodity prices, this commonly used methodology may help provide investors with an understanding of the impact of a volatile commodity price environment. Under such assumptions, we estimate the cumulative projected production from our year-end proved reserves would decrease by approximately 8.0% to 151.7 MMBoe from our previously reported 164.9 MMBoe, which is calculated as required by the SEC. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
 
Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas we produce.
 
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, oversupply of oil due to nearby refinery outages, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations and financial condition.

We do not control all of our operations and development projects and failure of an operator of wells in which we own partial interests to adequately perform could adversely affect our business, results of operations and financial condition.
 
Many of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells.
 
If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The success and timing of our development projects on properties operated by others is outside of our control.
 
The failure of an operator of wells in which we own partial interests to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues and could adversely affect our business, results of operations and financial condition.
 
Increases in interest rates could adversely affect our business, results of operations, cash flows from operations and financial condition.
 
Since all of the indebtedness outstanding under our Credit Agreement is at variable interest rates, we have significant exposure to increases in interest rates. As a result, our business, results of operations, cash flows from operations and financial condition may be adversely affected by significant increases in interest rates.

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

19


 
Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry who are also subject to the effects of the current oil and natural gas commodity price environment. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic, industry and other conditions. In addition, our oil, natural gas and interest rate derivative transactions expose us to credit risk in the event of nonperformance by counterparties.
 
We depend on a limited number of key personnel who would be difficult to replace.
 
Our operations are dependent on the continued efforts of our executive officers, senior management and key employees. The loss of any executive officer, member of our senior management or other key employees could negatively impact our ability to execute our strategy.
Our business may be affected by shortages of skilled employees and labor cost inflation.
Competition for skilled employees in the oil and gas industry in Midland, Texas is strong, and labor costs have increased moderately since 2015. We expect that the demand and, hence, costs for skilled employees will increase as prices for oil and natural gas rise. Continual high demand for skilled employees and continued increases in labor costs could have a material adverse effect on our business, financial condition, results of operations and prospects.

We may be unable to compete effectively, which could have an adverse effect on our business, results of operations and financial condition.
 
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties, including acreage trades, and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration and development activities during periods of low oil and natural gas market prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with these companies could have an adverse effect on our business, results of operations and financial condition.
 
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential investors could lose confidence in our financial reporting, which would harm our business and the trading price of our securities.
 
Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our securities.

A failure in our operational systems or cyber security attacks on any of our facilities or those of third parties may have a material adverse effect on our business, results of operations and financial condition.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition,

20


dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.
Our operations are also subject to the risk of cyber security attacks. Any cyber security attacks that affect our facilities, our customers or our financial data could have a material adverse effect on our business. In addition, cyber security attacks on our customer and employee data may result in financial loss or potential liability and may negatively impact our reputation. Third-party systems on which we rely could also suffer system failures, which could negatively impact our business, results of operations and financial condition.
Our sales of oil, natural gas, NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.
The Federal Trade Commission, the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission (the “CFTC”) hold statutory authority to monitor certain segments of the physical, swaps and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas, NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales and trading may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

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

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

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

21



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

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

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

The price of our common stock may experience volatility.
The price of our common stock may be volatile. Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, sales of our common stock by significant stockholders, short-selling of our common stock by investors, issuance of a significant number of shares for equity-based compensation or to raise additional capital to fund our operations, changes in market valuations of similar companies and speculation in the press or investment community about our financial condition or results of operations, as well as any doubt about its ability to continue as a going concern. General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price.
We may not be able to maintain our listing on the NASDAQ Global Select Market.

NASDAQ has established certain standards for the continued listing of a security on the NASDAQ Global Select Market. The standards for continued listing include, among other things, that the minimum bid price for the listed securities not fall below $1.00 per share for a period of 30 consecutive trading days. Although we are currently in compliance with the minimum bid price requirement, as of the filing of this annual report on Form 10-K, our minimum bid price was below $1.00 since March 14, 2019. If we do not satisfy any of the NASDAQ’s continued listing standards, our common stock could be delisted. Any such delisting could adversely affect the market liquidity of our common stock and the market price of our common stock could decrease. A delisting could adversely affect our ability to obtain financing for our operations or result in a loss of confidence by investors, customers, suppliers or employees.
Our amended and restated certificate of incorporation and second amended and restated bylaws contain provisions that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of your shares of common stock at a premium to the market price or would otherwise be beneficial to you.
There are provisions in our amended and restated certificate of incorporation and second amended and restated bylaws that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of your shares of common stock at a premium to the market price or would otherwise be beneficial to you. For example, our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us.
In addition, provisions of our amended and restated certificate of incorporation and second amended and restated bylaws, including limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of us. Certain provisions of the DGCL may also discourage takeover attempts that have not been approved by our Board of Directors.

22


We do not expect to pay dividends on our common stock for the foreseeable future.
We do not expect to pay dividends for the foreseeable future. In addition, our Credit Agreement and term loan credit agreement may prohibit us from paying any dividends without the consent of the lenders under the Credit Agreement and term loan credit agreement, other than dividends payable solely in equity interests of Legacy Inc.
The value of your shares may be diluted by future equity issuances, and shares eligible for future sale may have adverse effects on our share price.
We cannot predict the effect of future sales of shares or the availability of shares for future sales, on the market price of or the liquidity of the market for the shares. Sales of substantial amounts of shares, or the perception that such sales could occur, could adversely affect the prevailing market price of the shares. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Our authorized capital stock consists of 945,000,000 shares of common stock and 105,000,000 shares of preferred stock, a significant portion of which is unissued. We may need to raise a significant amount of capital to pay down outstanding indebtedness, including principal, interest and fees due under our Credit Agreement, term loan credit agreement and senior notes, to fund our drilling program and may raise such capital through the issuance of newly issued common stock or preferred stock. Such issuance and sale of equity could be dilutive to the interests of existing stockholders.
Additionally, the conversion of some or all of our convertible senior notes will dilute the ownership interests of existing stockholders. Any sales in the public market of the common stock issuable upon such conversion could adversely affect the prevailing market price of the shares.


ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
     None.


23


ITEM 2.
PROPERTIES
 
As of December 31, 2018 , we owned interests in producing oil and natural gas properties in 555 fields in the Permian Basin, East Texas, Piceance Basin of Colorado, Wyoming, North Dakota, Montana, Oklahoma and several other states, from 9,263 gross productive wells of which 2,943 are operated and 6,320 are non-operated. The following table sets forth information about our proved oil and natural gas reserves as of December 31, 2018 . The PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. For a definition of “standardized measure,” please see the glossary of terms at the beginning of this annual report on Form 10-K.
 
As of December 31, 2018
 
Proved Reserves
 
PV-10 (b)
Field or Region
MMBoe
 
R/P (a)
 
% Oil and NGLs
 
Amount
 
% of Total
 
 
 
 
 
 
 
($ in Millions)
 
 
Spraberry Field (c)
25.6

 
8.4

 
72
%
 
$
445.5

 
33
%
Lea Field
9.4

 
5.0

 
74

 
187.5

 
14

East Texas (d)
48.5

 
12.1

 

 
175.9

 
13

Piceance Basin (e)
41.9

 
10.6

 
18

 
108.8

 
8

Total — Top 4
125.4

 
9.7

 
27
%
 
$
917.7

 
68
%
All others
39.5

 
8.9

 
71

 
432.3

 
32

Total
164.9

 
9.5

 
37
%
 
$
1,350.0

 
100
%
__________________
(a)
Reserves as of December 31, 2018 divided by annualized fourth quarter production volumes.
(b)
PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. The below table provides a reconciliation of the GAAP standardized measure to PV-10 (non-GAAP) at December 31, 2018. As Legacy was a pass-through entity not subject to income taxes in 2017 and 2016, no income taxes were included in the computation of standardized measure for those years.
 
 
December 31,
 
 
2018
 
 
(In millions)
Standardized measure of discounted net cash flows
 
$
1,197,613

Present value of future income taxes discounted at 10%
 
152,361

PV-10
 
1,349,974

(c)
As the Spraberry Field contains 25,585 MBoe, or 15.5% of total proved reserves of 164,895 MBoe, the following table presents the production, by product, for the Spraberry Field for 2018 , 2017 and 2016 .
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands, except daily production)
Oil (MBbls)
 
2,230

 
1,167

 
429

Natural gas liquids (Mgal)
 
150

 
271

 
448

Natural gas (MMcf)
 
3,973

 
2,130

 
1,400

Total (Mboe)
 
2,896

 
1,528

 
673

Average daily production (Boe per day)
 
7,934

 
4,186

 
1,839


24



(d)
As East Texas contains 48,490 MBoe, or 29.4% of total proved reserves of 164,895 MBoe, the following table presents the production, by product, for East Texas for 2018 , 2017 and 2016 .
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands, except daily production)
Oil (MBbls)
 
10

 
15

 
17

Natural gas liquids (Mgal)
 
986

 
1,139

 
1,117

Natural gas (MMcf)
 
24,517

 
27,737

 
30,315

Total (Mboe)
 
4,120

 
4,665

 
5,097

Average daily production (Boe per day)
 
11,288

 
12,781

 
13,926


(e)
As the Piceance Basin contains 41,886 MBoe, or 25.4% of total proved reserves of 164,895 MBoe, the following table presents the production, by product, for the Piceance Basin for 2018 , 2017 and 2016 .
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
 
 
(In thousands, except daily production)
Oil (MBbls)
 
38

 
48

 
52

Natural gas liquids (Mgal)
 
31,237

 
22,110

 
22,288

Natural gas (MMcf)
 
19,387

 
22,065

 
24,206

Total (Mboe)
 
4,013

 
4,252

 
4,617

Average daily production (Boe per day)
 
10,995

 
11,649

 
12,615


Summary of Oil and Natural Gas Properties and Projects

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

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

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

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

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

25




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

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

Proved Reserves
 
The following table sets forth a summary of information related to our estimated net proved reserves as of the dates indicated based on reserve reports prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”). The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency. Standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.
 
The following information represents estimates of our proved reserves as of December 31, 2018 , 2017 and 2016 . These reserve estimates have been prepared in compliance with the SEC rules and accounting standards using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price for each month in the years ended December 31, 2018 , 2017 and 2016 . As a result of this methodology, we used an average WTI posted price of $65.56 per Bbl for oil and an average Platts' Henry Hub natural gas price of $3.10 per MMBtu to calculate our estimate of proved reserves as of December 31, 2018 . Please see the table below.

 
As of December 31,
 
2018
 
2017
 
2016
Reserve Data:
 
 
 
 
 
Estimated net proved reserves:
 
 
 
 
 
Oil (MMBbls)
52.1

 
51.1

 
32.5

Natural Gas Liquids (MMBbls)
9.2

 
9.5

 
7.8

Natural Gas (Bcf)
621.7

 
716.1

 
627.0

Total (MMBoe)
164.9

 
180.0

 
144.8

Proved developed reserves (MMBoe)
158.7

 
172.0

 
139.2

Proved undeveloped reserves (MMBoe)
6.2

 
8.0

 
5.6

Proved developed reserves as a percentage of total proved reserves
96
%
 
96
%
 
96
%
PV-10 (in millions) (a)
$
1,350.0

 
$
1,172.1

 
$
575.6

Oil and Natural Gas Prices(b)
 
 
 
 
 
Oil - WTI per Bbl
$
65.56

 
$
47.79

 
$
39.25

Natural gas - Henry Hub per MMBtu
$
3.10

 
$
2.98

 
$
2.48

____________________

(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 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.”

26


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

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

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

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. Please read “Risk Factors—Risks Related to our Business—Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. PV-10 amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate PV-10, which is required by FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
 
From time to time, we engage LaRoche to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither LaRoche nor any of its employees have any interest in those properties, and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties.
 
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 41-year career with four publicly traded oil and natural gas producing companies, including Legacy. He has over 31 years of SEC reserve report preparation experience in addition to continuing education courses on reserve estimation and reporting, including one in 2009 covering the effect of the SEC’s Final Rule, Modernization of Oil and Gas Reporting. For

27


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

Production and Price History
 
The following table sets forth a summary of unaudited information with respect to our production and sales of oil and natural gas for the years ended December 31, 2018 , 2017 and 2016 :
 
 
Year Ended December 31,
 
2018
 
2017(a)
 
2016
Production:
 
 
 
 
 
Oil (MBbls)
6,629

 
5,032

 
4,019

Natural gas liquids (MGal)
41,549

 
38,159

 
36,757

Gas (MMcf)
58,457

 
62,833

 
66,824

Total (MBoe)
17,361

 
16,413

 
16,032

Average daily production (Boe per day)
47,564

 
44,967

 
43,803

Average sales price per unit (excluding commodity derivative cash settlements):
 
 
 
 
 
Oil (per Bbl)
$
56.64

 
$
47.59

 
$
37.95

NGL (per Gal)
$
0.67

 
$
0.65

 
$
0.42

Gas (per Mcf)
$
2.59

 
$
2.74

 
$
2.19

Combined (per Boe)
$
31.96

 
$
26.58

 
$
19.61

Average sales price per unit (including commodity derivative cash settlements):
 
 
 
 
 
Oil (per Bbl)
$
54.10

 
$
49.94

 
$
47.27

NGL (per Gal)
$
0.67

 
$
0.65

 
$
0.42

Gas (per Mcf)
$
2.68

 
$
2.93

 
$
2.60

Combined (per Boe)
$
31.29

 
$
28.05

 
$
23.63

Average unit costs per Boe:
 
 
 
 
 
Production costs, excluding production and other taxes
$
11.02

 
$
10.58

 
$
10.59

Ad valorem taxes
$
0.51

 
$
0.59

 
$
0.60

Production and other taxes
$
1.70

 
$
1.21

 
$
0.89

General and administrative, excluding transaction costs and LTIP
$
2.25

 
$
2.07

 
$
1.95

Total general and administrative
$
4.21

 
$
3.01

 
$
2.72

Depletion, depreciation and amortization
$
9.22

 
$
7.73

 
$
9.38

____________________

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

Productive Wells
 
The following table sets forth information at December 31, 2018 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the product of our fractional working interests owned in gross wells. 
 
Oil
 
Natural Gas
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated
1,808

 
1,308

 
1,135

 
1,006

 
2,943

 
2,314

Non-operated
2,467

 
249

 
3,853

 
1,168

 
6,320

 
1,417

Total
4,275

 
1,557

 
4,988

 
2,174

 
9,263

 
3,731

 

28


Developed and Undeveloped Acreage
 
The following table sets forth information as of December 31, 2018 relating to our leasehold acreage.
 
Developed
Acreage(a)
 
Undeveloped
Acreage(b)
 
Total
Acreage
 
Gross(c)
 
Net(d)
 
Gross(c)
 
Net(d)
 
Gross(c)
 
Net(d)
Total
868,589
 
437,140
 
204,453
 
63,265
 
1,073,042
 
500,405
____________________
(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.

Drilling Activity
 
The following table sets forth information with respect to wells completed by Legacy during the years ended December 31, 2018 , 2017 and 2016 . 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,
 
2018
 
2017
 
2016
Gross:
 
 
 
 
 
Development
 
 
 
 
 
Productive
54

 
42

 
12

Dry

 

 

Total
54

 
42

 
12

Exploratory
 
 
 
 
 
Productive

 

 

Dry

 

 

Total

 

 

Net:
 
 
 
 
 
Development
 
 
 
 
 
Productive
27.6

 
27.4

 
2.2

Dry

 

 

Total
27.6

 
27.4

 
2.2

Exploratory
 
 
 
 
 
Productive

 

 

Dry

 

 

Total

 

 

   

29


Summary of Development Projects
 
For the year ended December 31, 2018 , we invested approximately $229.5 million in implementing our development strategy, including $176.9 million related to the drilling and completion of 54 gross ( 27.6 net) development wells. The remaining $52.6 million was comprised of the development of proved undeveloped reserves still in process, recompletions, fracture stimulation projects and various infrastructure capital. We estimate that our capital expenditures for the year ending December 31, 2019 will be approximately $135 million, subject to any limitations contained in the agreements governing our indebtedness, for development drilling, recompletions and fracture stimulation and other development-related projects to implement this strategy. Over 90% of this capital is expected to be deployed in the Permian Basin. We will consider adjustments to this capital program based on our assessment of additional development opportunities that are identified during the year and the cash available to invest in our development projects.

Present Activities

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

Operations
 
General
 
We operate approximately 66% of our total net daily production of oil and natural gas. Excluding our assets in the Piceance Basin, we operate approximately 87% of our net daily production of oil and natural gas. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own drilling rigs or any material oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ drilling, production and reservoir engineers, geologists and other specialists who have worked and will work to improve production rates, increase reserves, and lower the cost of operating our oil and natural gas properties. We also employ field operating personnel including production superintendents, production foremen, production technicians and lease operators. We charge the non-operating partners an operating fee for operating the wells, typically on a fee per well-operated basis proportionate to each owner's working interest. Our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.
 
Oil and Natural Gas Leases
 
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. In our areas of operation, this amount generally ranges from 12.5% to 33.7%, resulting in an 87.5% to 66.3% net revenue interest to the working interest owners, including us. Most of our leases are held by production and do not require lease rental payments.
 
Derivative Activity
 
We enter into derivative transactions with unaffiliated third parties with respect to oil and natural gas prices to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. We have entered into derivative contracts in the form of fixed price swaps for NYMEX WTI oil, NYMEX Henry Hub natural gas as well as Midland-to-Cushing crude oil and CIG-Rockies basis differentials. We also enter into derivative transactions with respect to London Interbank Offered Rate ("LIBOR") interest rates to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in LIBOR interest rates. All of our interest rate derivative transactions are LIBOR interest rate swaps. Our derivatives swap floating LIBOR rates for fixed rates. All of these commodity and interest rate contracts were executed in a costless manner, requiring no payment of premiums. Furthermore, none of our current derivative counterparties require us to post collateral. For a more detailed discussion of our derivative activities, please read “Business—Oil and Natural Gas Derivative Activities,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations” and “—Quantitative and Qualitative Disclosures About Market Risk.”
 
Title to Properties
 
Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title opinions have been obtained on a portion of our properties.

30


 
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.
 
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this document.
 
ITEM 3.
LEGAL PROCEEDINGS
 
We are, from time to time, involved in litigation and claims arising out of our operations in the normal course of business including regulatory and environmental matters, none of which are expected to be material. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on our consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings cannot be predicted with certainty.
      
ITEM 4.
MINE SAFETY DISCLOSURES
 
Not applicable.

31


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

Our common stock is listed on the NASDAQ Global Select Market under the symbol “LGCY.” As of March 13, 2019 , there were 114,810,671 shares of common stock outstanding, held by approximately  109 stockholders of record. This number reflects only the stockholders of record, and does not reflect all beneficial owners of common stock, such as those who hold their common stock through a broker.
 
Subsequent to the Corporate Reorganization, we have not paid any cash dividends and we currently do not anticipate paying any cash dividends in the foreseeable future.
 



32


ITEM 6.
SELECTED FINANCIAL DATA
 
You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Legacy’s consolidated financial statements and related notes included elsewhere in this annual report on Form 10-K. The operating results of the properties acquired have been included from their respective acquisition dates as discussed below.
 
 
Years Ended December 31,
 
2018
 
2017(a)
 
2016
 
2015(b)
 
2014(c)
 
(In thousands, except per share/unit data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
Oil sales
$
375,444

 
$
239,448

 
$
152,507

 
$
199,841

 
$
396,774

Natural gas liquids sales
27,750

 
24,796

 
15,406

 
16,645

 
27,483

Natural gas sales
151,667

 
172,057

 
146,444

 
122,293

 
108,042

Total revenues
554,861

 
436,301

 
314,357

 
338,779

 
532,299

Expenses:
 
 
 
 
 
 
 
 
 
Oil and natural gas production
200,285

 
183,219

 
179,333

 
194,491

 
198,801

Production and other taxes
29,532

 
19,825

 
14,267

 
16,383

 
31,534

General and administrative
73,039

 
49,372

 
43,639

 
46,511

 
38,980

Depletion, depreciation, amortization
 
 
 
 
 
 
 
 
 
and accretion
159,998

 
126,938

 
150,414

 
177,258

 
173,686

Impairment of long-lived assets
67,978

 
37,283

 
61,796

 
633,805

 
448,714

(Gain) loss on disposal of assets
(23,803
)
 
1,606

 
(50,095
)
 
(3,972
)
 
(2,479
)
Total expenses
507,029

 
418,243

 
399,354

 
1,064,476

 
889,236

Operating income (loss)
47,832

 
18,058

 
(84,997
)
 
(725,697
)
 
(356,937
)
Other income (expense):
 
 
 
 
 
 
 
 
 
Interest income
36

 
64

 
67

 
329

 
873

Interest expense
(117,008
)
 
(89,206
)
 
(79,060
)
 
(76,891
)
 
(67,218
)
Gain on extinguishment of debt
66,066

 

 
150,802

 

 

Equity in income (loss) of equity method investees
(19
)
 
17

 

 
126

 
428

Net gains (losses) on commodity derivatives
49,172

 
17,776

 
(41,224
)
 
98,253

 
138,092

Other
722

 
792

 
(179
)
 
841

 
258

Income (loss) before income taxes
46,801

 
(52,499
)
 
(54,591
)
 
(703,039
)
 
(284,504
)
Income tax (expense) benefit
(2,968
)
 
(1,398
)
 
(1,229
)
 
1,498

 
859

Net loss attributable to stockholders/unitholders
$
43,833

 
$
(53,897
)
 
$
(55,820
)
 
$
(701,541
)
 
$
(283,645
)



33


 
Years Ended December 31,
 
2018
 
2017(a)
 
2016
 
2015(b)
 
2014(c)
Income/(Loss) per share (a)
 
 
 
 
 
 
 
 
 
Basic and diluted
$
0.42

 
$
(0.54
)
 
$
(0.57
)
 
$
(7.26
)
 
$
(3.23
)
Distributions paid per unit
$

 
$

 
$

 
$
1.46

 
$
2.41

____________________

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

Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
175,941

 
$
99,795

 
$
3,296

 
$
2,046

 
$
207,216

Net cash provided by (used in)
 
 
 
 
 
 
 
 
 

investing activities
$
(188,128
)
 
$
(279,236
)
 
$
119,989

 
$
(377,420
)
 
$
(632,414
)
Net cash provided by (used in)
 
 
 
 
 
 
 

 
 
financing activities
$
12,110

 
$
177,718

 
$
(119,130
)
 
$
376,655

 
$
423,339

Capital expenditures
$
228,261

 
$
314,491

 
$
41,932

 
$
579,463

 
$
640,414


 
Historical As of December 31,
 
2018
 
2017(a)
 
2016
 
2015(b)
 
2014(c)
 
(In thousands)
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,098

 
$
1,246

 
$
2,555

 
$
2,006

 
$
725

Other current assets
149,994

 
111,358

 
80,217

 
127,453

 
191,529

Oil and natural gas properties, net of
 
 
 
 
 
 
 
 
 
accumulated depletion, depreciation,
 
 
 
 
 
 
 
 
 
amortization and impairment
1,314,313

 
1,353,356

 
1,181,909

 
1,408,956

 
1,639,974

Other assets
9,526

 
27,122

 
35,145

 
74,705

 
66,378

Total assets
$
1,474,931

 
$
1,493,082

 
$
1,299,826

 
$
1,613,120

 
$
1,898,606

Current liabilities
$
984,650

 
$
144,810

 
$
86,609

 
$
81,093

 
$
97,576

Long-term debt
432,923

 
1,346,769

 
1,161,394

 
1,427,614

 
938,876

Other long-term liabilities
249,989

 
273,190

 
273,902

 
284,090

 
224,949

Stockholders'/Partners’ equity(deficit)
(192,631
)
 
(271,687
)
 
(222,079
)
 
(179,677
)
 
637,205

Total liabilities and stockholders'/partners’ equity (deficit)
$
1,474,931

 
$
1,493,082

 
$
1,299,826

 
$
1,613,120

 
$
1,898,606

____________________

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

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

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


34


ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this annual report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Information,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, actual results may differ materially from those anticipated or implied in the forward-looking statements.

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

Going Concern

We have significant obligations and commitments coming due in the near term. On March 21, 2019, we entered into an amendment to the Credit Agreement (as defined below) pursuant to which the lenders agreed to extend the maturity date from April 1, 2019 to May 31, 2019 and as of December 31, 2018, we had availability under the Credit Agreement of $32.9 million . Without additional sources of capital or a significant restructuring of our balance sheet, the maturity of our Credit Agreement raises substantial doubt about our ability to continue as a going concern, which means that we may be unable to continue operations for the foreseeable future or realize assets and discharge liabilities in the ordinary course of operation.

The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements in this annual report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

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

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

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

We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by drilling to find additional reserves, acquiring more reserves than we produce, utilizing multiple types of recovery techniques such as secondary (waterflood) and

35


tertiary recovery methods to re-pressure the reservoir and recover additional oil, recompleting or adding pay in existing wellbores and improving artificial lift.

Outlook. The oil and natural gas industry is in a challenging environment, especially over the past five years, as evidenced by volatility in the crude oil prices that ranged from over $100 per barrel in early 2014 to less than $30 per barrel in early 2016. While prices in 2017 and 2018 have recovered off the lows experienced in 2016 they have experienced a sharp decline at the end of 2018 from levels seen in 2017 and are still well below levels seen in 2014. Sustained development activity in the Permian Basin has created certain basin-wide operational challenges. Crude oil and associated natural gas production growth has strained existing takeaway capacity and caused widening basis differentials in the Permian Basin relative to benchmark crude oil and natural gas prices, which affect the prices we realize for our crude oil and natural gas production. The narrowing of these basis differentials is largely dependent on the construction of new takeaway capacity and other factors beyond our control. While we believe that a significant number of these projects will be completed in 2019, there is no guarantee that these projects will be completed on time or at all. In addition, the availability of services related to drilling, completion and other well site activity is becoming tighter. We do not have the ability to control the supply of these services and if we are unable to find adequate services for our operations at economic prices, there could be a material adverse impact on our financial condition. Also, production from our horizontal development within the Permian Basin has, from time to time, been temporarily shut-in or constrained due to proximate development operations. We cannot control or accurately forecast the timing, duration or other operational impositions associated with such well interference but the impacts could have a material adverse effect on our financial condition. Our development capital expenditures are expected to be approximately $135 million, subject to any limitations contained in the agreements governing our indebtedness, in 2019 and will continue to be focused on the development of our Permian Basin horizontal development assets, subject to any constraints imposed by our Term Loan Credit Agreement that may limit our capital expenditures as discussed in “Capital Resources and Liquidity—Future Liquidity Considerations”. We intend to continue to prudently manage our historical low-decline proved developed producing oil and gas properties to support the development of our high return prospects as we pursue additional cash flow and increase oil and natural gas reserves. To illustrate the sensitivity of our proved reserves to fluctuations in commodity prices, we recalculated our proved reserves as of December 31, 2018, using the five-year average forward price as of February 25, 2019 for both WTI oil and NYMEX natural gas. While this 5-year NYMEX forward strip price is not necessarily indicative of our overall outlook on future commodity prices, this commonly used methodology may help provide investors with an understanding of the impact of a volatile commodity price environment. Under such assumptions, we estimate the cumulative projected production from our year-end proved reserves would decrease by approximately 8.0% to 151.7 MMBoe from the reported 164.9 MMBoe, which is calculated as required by the SEC.

We may breach certain financial covenants under Legacy LP's $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and the lenders party thereto as amended most recently by the Twelfth Amendment thereto (as amended, the “Credit Agreement”) and Legacy LP's second lien term loan credit agreement (as amended, our “Term Loan Credit Agreement”), which would constitute a default under our Credit Agreement or our Term Loan Credit Agreement. Further, while we received a waiver of the covenant under our Term Loan Credit Agreement that requires us to deliver audited financial statements without a “going concern” or like qualification or exception, such waiver expires on May 31, 2019 and such default cannot be remedied. Upon delivery of our financial statements for the quarter ended March 31, 2019, we expect to be in violation of the current ratio covenant under our Credit Agreement, which would constitute a default under the Credit Agreement. Defaults, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and subsequent acceleration of all amounts outstanding under our Credit Agreement or our Term Loan Credit Agreement or foreclosure on our oil and natural gas properties. Certain payment defaults or acceleration under our Credit Agreement or our Term Loan Credit Agreement could cause a cross-default or cross-acceleration of all of our indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, we believe the long-term global outlook for commodity prices and our efforts to date will be viewed positively by our lenders. For further discussion on the consequences of a breach of such covenants, including a potential cross-default of all our existing indebtedness, please read “Risk Factors—Risks Related to Our Business—If we are unable to refinance or repay our indebtedness under our Credit Agreement when it comes due or otherwise fail to comply with certain restrictions and financial covenants in our Credit Agreement and Term Loan Credit Agreement, we could be in default under our Credit Agreement and Term Loan Credit Agreement which may result in acceleration or repayment of all of our outstanding indebtedness,” in Item 1A.

Considering the current environment for the oil and natural gas industry, our goals in 2019 are to:

reposition our balance sheet by evaluating and opportunistically pursuing strategic alternatives to materially reduce our outstanding indebtedness and restructure our near term maturity indebtedness.

minimize production declines and operating costs through efficient operations; and

efficiently develop our horizontal inventory in the Permian Basin to generate strong cash-on-cash investment returns.

36



In the event that cash flows from operations are greater than we currently anticipate, whether as a result of increased commodity prices, reduced interest expense or otherwise, or additional external financing sources become available to us, we intend to pay down debt, accelerate our development plan, and increase development capital expenditures.
Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through organic development projects and acquisitions. Our ability to add reserves through organic development projects and acquisitions is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and completions equipment and personnel.
Our 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 2019, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. Commodity prices may decrease, which could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital 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.

37


Operating Data

The following table sets forth our selected financial and operating data for the periods indicated.                
 
Year Ended December 31,
 
2018
 
2017(b)
 
2016
 
(In thousands, except per unit data and production)
Revenues
 
 
 
 
 
Oil sales
$
375,444

 
$
239,448

 
$
152,507

Natural gas liquids sales
27,750

 
24,796

 
15,406

Natural gas sales
151,667

 
172,057

 
146,444

Total revenues
$
554,861

 
$
436,301

 
$
314,357

Expenses:
 
 
 
 
 
Oil and natural gas production
$
191,345

 
$
173,599

 
$
169,755

Ad valorem taxes
8,940

 
9,620

 
9,578

Total
$
200,285

 
$
183,219

 
$
179,333

Production and other taxes
$
29,532

 
$
19,825

 
$
14,267

General and administrative, excluding transaction costs and LTIP
$
39,041

 
$
34,006

 
$
31,196

Transaction costs
5,635

 
8,769

 
5,245

LTIP expense
28,362

 
6,597

 
7,198

Total general and administrative
$
73,038

 
$
49,372

 
$
43,639

Depletion, depreciation, amortization and accretion
$
159,998

 
$
126,938

 
$
150,414

Commodity derivative cash settlements:
 
 
 
 
 
Oil derivative cash settlements (paid)/received
(16,845
)
 
11,840

 
37,464

Natural gas derivative cash settlements received
5,130

 
12,316

 
27,041

Total commodity derivative cash settlements
(11,715
)
 
24,156

 
64,505

Production:
 
 
 
 
 
Oil (MBbls)
6,629

 
5,032

 
4,019

Natural gas liquids (MGal)
41,549

 
38,159

 
36,757

Natural gas (MMcf)
58,457

 
62,833

 
66,824

Total (MBoe)
17,361

 
16,413

 
16,032

Average daily production (Boe/d)
47,564

 
44,967

 
43,803

Average sales price per unit (excluding commodity derivative cash settlements):
 
 
 
 
 
Oil price (per Bbl)
$
56.64

 
$
47.59

 
$
37.95

Natural gas liquids price (per Gal)
$
0.67

 
$
0.65

 
$
0.42

Natural gas price (per Mcf)(a)
$
2.59

 
$
2.74

 
$
2.19

Combined (per Boe)
$
31.96

 
$
26.58

 
$
19.61

Average sales price per unit (including commodity derivative cash settlements):
 
 
 
 
 
Oil price (per Bbl)
$
54.10

 
$
49.94

 
$
47.27

Natural gas liquids price (per Gal)
$
0.67

 
$
0.65

 
$
0.42

Natural gas price (per Mcf)(a)
$
2.68

 
$
2.93

 
$
2.60

Combined (per Boe)
$
31.29

 
$
28.05

 
$
23.63

Average WTI oil spot price (per Bbl)
$
65.23

 
$
50.80

 
$
43.29

Average Henry Hub natural gas spot price (per MMBtu)
$
3.15

 
$
2.99

 
$
2.52

Average unit costs per Boe: