PART I
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:
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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
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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
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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:
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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
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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.
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2018 and Current Highlights
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Deployed
$229.5 million
of development capital expenditures, primarily focused on the drilling and completion of our Permian Basin horizontal development assets;
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Increased revenue
27%
, relative to
2017
, to
$554.9 million
;
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Increased oil production
32%
relative to
2017
, to
18,162
Bbls/d;
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Completed our transition to a corporation and commenced trading as Legacy Reserves Inc.
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In March 2019, we extended the term on our Credit Agreement through May 31, 2019.
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Business Strategy
The key elements of our business strategy are to:
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Prudently deploy capital in development opportunities that maximize value;
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Identify, acquire and exploit additional opportunities to broaden our operational footprint and enrich our future growth potential;
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Utilize our extensive Permian portfolio of small-tract acreage to increase our drillable footprint;
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Maintain efficient operations to minimize production declines, improve lifting costs and well economics;
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Rationalize our asset base by regularly reviewing our asset portfolio and divesting non-core assets; and
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Maintain capital budget flexibility to preserve liquidity.
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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.
Our proved reserves by operating region as of
December 31, 2018
are as follows:
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Proved Reserves by Operating Region as of December 31, 2018
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Operating Regions
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Oil (MBbls)
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Natural
Gas (MMcf)
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NGLs(MBbls)
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Total (MBoe)
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% Liquids
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% PDP
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% Total
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Permian Basin
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44,671
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116,879
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660
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64,811
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70
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%
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90
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%
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39
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%
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East Texas
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103
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292,249
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211
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49,022
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1
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%
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100
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%
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30
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%
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Rocky Mountain
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6,479
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206,541
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7,257
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48,160
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29
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%
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100
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%
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29
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%
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Mid-Continent
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824
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6,051
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1,083
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2,916
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65
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%
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92
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%
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2
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%
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Total
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52,077
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621,720
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9,211
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164,909
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37
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%
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100
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%
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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
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Gross Locations
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Net Locations
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Net Volume (MBoe)
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Balance, December 31, 2017
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40
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20.1
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7,963
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PUDs converted to PDP by drilling
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(19
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)
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(9.5
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)
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(5,807
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)
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PUDs removed due to performance (a)
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(2
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(0.3
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(89
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PUDs removed from future drilling schedule (b)
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(3
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(1.0
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(570
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)
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Extensions and discoveries (a)
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16
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10.8
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4,659
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Other
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—
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0.3
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40
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Balance, December 31, 2018
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32
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20.4
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6,196
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(a)
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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.
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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.
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(b)
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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.
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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
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.
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2018
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2017
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2016
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Plains Marketing, LP
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20%
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10%
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6%
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Rio Energy International Inc
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13%
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9%
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3%
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Our oil sales prices are based on formula pricing and calculated either using a discount to NYMEX WTI oil or using the appropriate buyer’s posted price less a regional differential and transportation fee.
Although we believe we could identify a substitute purchaser if we were to lose any of our oil or natural gas purchasers, the loss could temporarily cause a loss or deferral of production and sale of our oil and natural gas in that particular purchaser’s service area. However, if one or more of our larger purchasers ceased purchasing oil or natural gas altogether, the loss of any such purchaser could have a detrimental impact on our short-term production volumes and our ability to find substitute purchasers for our production volumes in a timely manner, though we do not believe this would have a long-term material adverse effect on our operations.
Competition
We operate in a highly competitive environment for acquiring leases and properties, securing and retaining trained personnel and service providers and marketing oil and natural gas. Our competitors may be able to pay more for leases, productive oil and natural gas properties and development projects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Seasonal Nature of Business
The demand for oil and natural gas can be seasonal based on motor vehicle driving patterns and heating and cooling demands related to weather. Our Rockies' oil prices suffer relative to WTI in the winter due to reduced demand for asphaltic crude. Refinery turnarounds in the Permian typically occur in the first quarter, and, historically, we have experienced wider oil differentials during this time.
Environmental Matters and Regulation
General.
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:
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require the acquisition of various permits before drilling commences;
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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
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These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.
Waste Handling.
The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation and Liability Act.
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, may impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas development and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, most of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed of substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges.
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The Oil Pollution Act of 1990, as amended or OPA, which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that cause a release of oil into waters of the United States. In addition, owners and operators of facilities that store oil above threshold amounts must develop and implement spill response plans.
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.
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:
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the method of drilling and casing wells;
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the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells; and
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notice to surface owners and other third parties.
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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.
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.
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
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:
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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;
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it may become more difficult to retain, attract or replace key employees;
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employees could be distracted from performance of their duties or more easily attracted to other career opportunities;
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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
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our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.
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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:
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the domestic and foreign supply of and demand for oil and natural gas;
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market expectations about future prices of oil and natural gas;
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the price and quantity of imports of crude oil and natural gas;
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overall domestic and global economic conditions;
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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;
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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;
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trading in oil and natural gas derivative contracts;
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the level of consumer product demand;
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weather conditions and natural disasters;
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technological advances affecting energy production and consumption;
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domestic and foreign governmental regulations and taxes;
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the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;
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the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
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the price and availability of alternative fuels.
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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:
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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;
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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;
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our access to the capital markets may be limited;
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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
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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.
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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.
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:
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the level of oil and natural gas we are able to produce from existing wells;
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capital and lending market conditions;
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the prices at which our oil and natural gas are sold; and
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our ability to identify, acquire and exploit new reserves.
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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:
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the high cost, shortages or delivery delays of equipment, materials, and services;
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unexpected operational events;
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adverse weather conditions or events;
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facility or equipment malfunctions;
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regulatory changes and approvals;
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pipeline ruptures or spills;
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collapses of wellbore, casing or other tubulars;
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unusual or unexpected geological formations;
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loss of drilling fluid circulation;
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formations with abnormal pressures;
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blowouts, craterings and explosions;
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interference from new well stimulation;
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offset operations causing irregularities or interruptions in production; and
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uncontrollable flows of oil, natural gas or well fluids.
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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.
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
.
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:
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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;
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an inability to successfully integrate the assets and businesses we acquire;
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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;
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a lack of capital could cause the development of any acquisitions to be slower than forecasted;
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a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
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the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
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the diversion of management’s attention from other business concerns;
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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
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the loss of key purchasers.
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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
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.
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:
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•
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sell assets, including equity interests in our restricted subsidiaries;
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•
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pay distributions on, redeem or purchase our equity or redeem or purchase our subordinated debt;
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•
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incur or guarantee additional indebtedness or issue preferred units;
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•
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create or incur certain liens;
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•
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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
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•
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consolidate, merge or transfer all or substantially all of our assets;
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•
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engage in transactions with affiliates;
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•
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create unrestricted subsidiaries; and
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•
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engage in certain business activities.
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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
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.
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,
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.
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.
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.
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ITEM 1B.
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UNRESOLVED STAFF COMMENTS
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None.
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.
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As of December 31, 2018
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Proved Reserves
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PV-10 (b)
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Field or Region
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MMBoe
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R/P (a)
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% Oil and NGLs
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Amount
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% of Total
|
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($ in Millions)
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Spraberry Field (c)
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25.6
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8.4
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72
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%
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$
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445.5
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33
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%
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Lea Field
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9.4
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5.0
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|
74
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187.5
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14
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East Texas (d)
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48.5
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12.1
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—
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175.9
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13
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Piceance Basin (e)
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41.9
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10.6
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18
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|
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108.8
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|
8
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Total — Top 4
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125.4
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|
|
9.7
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|
27
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%
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$
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917.7
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|
|
68
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%
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All others
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39.5
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8.9
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|
71
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432.3
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|
32
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Total
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164.9
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9.5
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37
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%
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$
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1,350.0
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|
100
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%
|
__________________
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(a)
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Reserves as of
December 31, 2018
divided by annualized fourth quarter production volumes.
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(b)
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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.
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December 31,
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2018
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(In millions)
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Standardized measure of discounted net cash flows
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$
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1,197,613
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Present value of future income taxes discounted at 10%
|
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152,361
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PV-10
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|
1,349,974
|
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(c)
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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
.
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Year Ended December 31,
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|
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2018
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2017
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2016
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(In thousands, except daily production)
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Oil (MBbls)
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2,230
|
|
|
1,167
|
|
|
429
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|
Natural gas liquids (Mgal)
|
|
150
|
|
|
271
|
|
|
448
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|
Natural gas (MMcf)
|
|
3,973
|
|
|
2,130
|
|
|
1,400
|
|
Total (Mboe)
|
|
2,896
|
|
|
1,528
|
|
|
673
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|
Average daily production (Boe per day)
|
|
7,934
|
|
|
4,186
|
|
|
1,839
|
|
|
|
(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
.
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|
|
|
|
|
|
|
|
|
|
|
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.
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.”
|
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
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
|
|
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
|
—
|
|
|
—
|
|
|
—
|
|
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.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
(a) Organization, Basis of Presentation and Description of Business
Unless the context requires otherwise or unless otherwise noted, all references to “Legacy Reserves,” “Legacy Inc.,” “Legacy,” the “Company,” “we,” “us,” “our” or like terms are to Legacy Reserves Inc. and its subsidiaries for the periods after September 20, 2018, the date the Corporate Reorganization was consummated (as defined below). For the periods prior to September 20, 2018, unless the context requires otherwise or unless otherwise noted, all references to “Legacy Reserves,” “Legacy LP,” “Legacy,” the “Company,” “we,” “us,” “our” or like terms are to Legacy Reserves LP and its subsidiaries.
Legacy is an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Its current operations are focused on the horizontal development of unconventional plays in the Permian Basin and the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions.
The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.
(b) Going Concern
Legacy has significant obligations and commitments coming due in the near term. The Credit Agreement (as defined in Note 3) matures on May 31, 2019 and as of December 31, 2018, Legacy had borrowings of
$541.0 million
and availability under the Credit Agreement of
$32.9 million
. In addition, Legacy received a temporary waiver under the Term Loan Credit Agreement (as defined in Note 3) of its requirement to deliver fiscal year 2018 audited financial statements without a "going concern" or like qualification or exception through May 31, 2019. Due to the short-term nature of this waiver and the anticipation that we will be in violation of this covenant upon expiry of the waiver, Legacy has determined that the total borrowings outstanding under the Term Loan Credit Agreement of
$338.6 million
are due in the near term and have thus recorded these as a current liability. Without additional sources of capital or a significant restructuring of its balance sheet, the maturity of the Credit Agreement raises substantial doubt about Legacy's ability to continue as a going concern, which means that Legacy may be unable to continue operations for the foreseeable future or realize assets and discharge liabilities in the ordinary course of operation.The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.
In order to improve its liquidity position, Legacy is currently evaluating financial, transactional and other strategic 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.
(c) Corporate Reorganization
On September 20, 2018, we completed the transactions contemplated by the Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”), dated July 9, 2018, by and among Legacy Inc., Legacy LP, Legacy Reserves GP, LLC (the “General Partner”) and Legacy Reserves Merger Sub LLC, a wholly owned subsidiary of Legacy Inc. (“Merger Sub”), and the GP Purchase Agreement, dated March 23, 2018, by and among Legacy Inc., the General Partner, Legacy LP, Lion GP Interests, LLC, Moriah Properties Limited, and Brothers Production Properties, Ltd., Brothers Production Company, Inc., Brothers Operating Company, Inc., J&W McGraw Properties, Ltd., DAB Resources, Ltd. and H2K Holdings, Ltd. (such transactions referred to herein collectively as the “Corporate Reorganization”). Upon the consummation of the Corporate Reorganization:
|
|
•
|
Legacy Inc., which prior to the Corporate Reorganization, was a wholly owned subsidiary of the General Partner, acquired all of the issued and outstanding limited liability company interests in the General Partner and became the sole member of the General Partner with the General Partner becoming a subsidiary of Legacy Inc.; and
|
|
|
•
|
Legacy LP merged with Merger Sub, with Legacy LP continuing as the surviving entity and as a subsidiary of Legacy Inc. (the “Merger”), the limited partner interests of Legacy LP, other than the incentive distribution units in Legacy LP, were exchanged for shares of Legacy Inc.’s common stock, par value
$0.01
(“common stock”) and the general partner interest remained outstanding.
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Corporate Reorganization was accounted for under ASC 805 as a combination of entities under common control. As such, the assets and liabilities of the Partnership were recognized at their carrying values in Legacy Inc.
(d) Accounts Receivable
Accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 12).
(e) Oil and Natural Gas Properties
Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.
Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 13, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates.
Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended
December 31, 2018
, Legacy recognized
$58.7 million
of impairment expense in
50
separate producing fields, due primarily to the further decline in oil and natural gas futures prices, increased expenses and well performance during the year ended
December 31, 2018
, which decreased the expected future cash flows below the carrying value of the assets. For the year ended
December 31, 2017
, Legacy recognized
$37.3 million
of impairment expense, in
47
separate producing fields, due primarily to the further decline in oil and natural gas futures prices, increased expenses and well performance during the year ended
December 31, 2017
, which decreased the expected future cash flows below the carrying value of the assets. For the year ended
December 31, 2016
, Legacy recognized
$61.8 million
of impairment expense, due primarily to well performance and the further decline in commodity prices during the year ended December 31, 2016, which decreased the expected future cash flows below the carrying value of the assets.
Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Legacy recognized
$9.3 million
of impairment of unproven properties
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
during the year ended
December 31, 2018
. Legacy did not recognize impairment expense on unproved properties during the years ended
December 31, 2017
and
2016
.
(f) Oil, NGLs and Natural Gas Reserve Quantities
Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards.
Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered.
(g) Income Taxes
Prior to consummation of the Corporate Reorganization on September 20, 2018, Legacy LP was treated as a partnership for federal and state income tax purposes, in which the taxable income or loss was passed through to its unitholders. Legacy LP was subject to Texas margin tax and certain of Legacy LP’s subsidiaries were c-corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, Legacy LP did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for its operations.
Effective upon consummation of the Corporate Reorganization, Legacy Inc. became subject to federal and state income taxes as a c-corporation. As such, we account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income or loss in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At
December 31, 2018
, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Please see Note 16 for more information on Legacy's accounting for income taxes.
(h) Derivative Instruments and Hedging Activities
Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 10 and 11).
(i) Use of Estimates
Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, impairment of oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues.
(j) Revenue Recognition
On January 1, 2018, Legacy adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition applied to all contracts. ASU 2014-09 created ASC 606,
Revenue from Contracts with Customers
(ASC 606).
Legacy enters into contracts with customers to sell its produced oil, natural gas and NGLs. Revenue attributable to these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when Legacy’s performance obligations under these contracts are satisfied, which generally occurs when control of the oil, natural gas and NGLs transfers to the purchaser and collectability is reasonably assured. Given the nature of Legacy’s products sold, Legacy has concluded that control transfers to its customers at a point in time. In accordance with ASC 606, Legacy considers the following indicators of the transfer of control to determine the point in time at which control transfers to its customers: (i) Legacy has a present right to payment for the asset; (ii) the customer has legal title to the asset; (iii) Legacy has transferred physical possession of the asset; and (iv) the customer has the significant risks and rewards of ownership.
Oil Sales
Legacy's oil sales contracts are generally structured such that Legacy sells its oil production to the purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality and physical location. Legacy recognizes revenue when control transfers to the purchaser upon delivery at or near the wellhead based on the net price received from purchaser.
Natural Gas and NGL Sales
Under Legacy's gas processing contracts, Legacy delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to Legacy for the resulting sales of NGLs and residue gas. Under this contract structure, Legacy has determined that the midstream processing entity represents Legacy’s customer, and, consequently, Legacy recognizes revenue when control transfers to the midstream processing entity upon delivery. The amount of revenue recognized is based on the net amount of the proceeds received from the midstream processing entity, which is generally tied to the prevailing index prices for residue gas and NGLs less deductions for gathering, processing, transportation and other expenses.
Under Legacy's dry gas sales that do not require processing, Legacy sells its natural gas production to third party purchasers at a contractually specified delivery point at or near the wellhead. Pricing provisions are tied to a market index, with certain deductions based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions. Legacy recognizes revenue when control transfers to its third party purchasers upon delivery of the natural gas based on the relevant index price net of deductions.
Estimation
To the extent actual product volumes and related prices are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. Refer to
Note 4 - Revenue from Contracts with Customer
for additional information.
Imbalances
Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of
December 31, 2018
,
2017
and
2016
.
(k) Investments
Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition.
(l) Environmental
Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.
(m) Income (Loss) Per Share
Basic income (loss) per share amounts are calculated using the weighted average number of shares outstanding during each period. Diluted income (loss) per share also gives effect to dilutive unvested restricted shares (calculated based upon the treasury stock method) (see Note 14). In accordance with ASC 805, income (loss) per share amounts for historical periods have been recomputed to reflect shares issued in the Corporate Reorganization.
(n) Segment Reporting
Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes.
(o) Share-Based Compensation
Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“Legacy LP LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises unit appreciation rights ("UARs") and certain phantom unit awards, Legacy accounted for these awards under the liability method, which requires Legacy to recognize the fair value of each unit award at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounted for executive phantom unit and restricted unit awards under the equity method. Pursuant to the terms of the Corporate Reorganization, the Legacy LP LTIP was terminated. On September 19, 2018, the Legacy Inc. 2018 Omnibus Incentive Plan (the "Legacy Inc, LTIP") was approved by the former unitholders of Legacy LP in connection wiht the Corporate Reorganization. Legacy accounts for the restricted stock units ("RSUs") under the equity method. Legacy’s shares outstanding, as reflected in the accompanying consolidated balance sheet at
December 31, 2018
, do not include
7,302,809
shares related to unvested RSUs.
(p) Accrued Oil and Natural Gas Liabilities
Below are the components of accrued oil and natural gas liabilities as of
December 31, 2018
and
2017
.
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2018
|
|
2017
|
|
(In thousands)
|
Accrued capital expenditures
|
$
|
24,690
|
|
|
$
|
33,198
|
|
Accrued lease operating expense
|
41,227
|
|
|
18,179
|
|
Revenue payable to joint interest owners
|
22,750
|
|
|
18,510
|
|
Accrued ad valorem tax
|
5,255
|
|
|
5,807
|
|
Other
|
4,964
|
|
|
5,624
|
|
|
$
|
98,886
|
|
|
$
|
81,318
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(q) Restricted Cash
Restricted cash of
$3.3 million
and
$3.2 million
as of
December 31, 2018
and
2017
, respectively, is recorded in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business.
(r) Prior Year Financial Statement Presentation
Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this annual report on Form 10-K.
(s) Recent Accounting Pronouncements
In February 2016, the FASB issued ASU No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms at commencement longer than twelve months. Legacy engaged a third party consultant to assist with its implementation of ASU 2016-02. Leases will be classified as either finance or operating, with that classification affecting the pattern of expense recognition in the income statement.
ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Legacy will adopt ASU 2016-02 using a modified retrospective approach in the first quarter of 2019 (that is, the period of adoption). At transition, Legacy will utilize the package of practical expedients provided in ASU 2016-02 that allow companies, among other things, to not reassess contracts that commenced prior to adoption. In addition, Legacy expects to utilize the practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under currently effective lease accounting guidance.
Legacy is evaluating the provisions of ASU 2016-02 and finalizing the impact it will have on its consolidated results of operations, financial position and financial disclosures. Legacy believes that the new guidance will impact its consolidated balance sheet due to the recognition of right-of-use assets and lease liabilities that are not recognized under currently effective guidance (for example, operating leases). The adjustments that will be required upon implementation of ASU 2016-02, which Legacy anticipates to be less than $15 million, have not been finalized.
Legacy commonly enters into lease agreements in support of its operations for assets such as office space, vehicles, drilling rigs, compressors and other well equipment. In its efforts to determine the impact of ASU 2016-02, Legacy developed an implementation approach that included educating key stakeholders within the organization, analyzing systems reports to identify the types and volume of contracts that may meet the definition of a lease and performing a detailed review of material contracts identified through that analysis. Legacy is also implementing a financial lease accounting system solution to facilitate compliance with ASU 2016-02.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(2) Fair Values of Financial Instruments
The estimated fair values of Legacy’s financial instruments approximate the carrying amounts except as discussed below:
Debt.
The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The carrying amount of the second lien term loan debt under Legacy’s term loan credit agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar borrowings. The fair value of the
8%
senior notes due 2020 (the "2020 Senior Notes"), the
6.625%
senior notes due 2021 (the "2021 Senior Notes") and the
8%
convertible senior notes due 2023 (the "2023 Convertible Notes") was
$97.8 million
,
$57.9 million
and
$42.3 million
, respectively, as of
December 31, 2018
. As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1.
Derivatives.
See Note 10 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives.
(3) Debt
Debt consists of the following at
December 31, 2018
and
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Current debt
|
|
|
|
|
Credit Facility due 2019
|
|
$
|
541,000
|
|
|
$
|
—
|
|
Second Lien Term Loans due 2020
|
|
338,626
|
|
|
—
|
|
Unamortized debt issuance costs
|
|
(17,332
|
)
|
|
—
|
|
Unamortized discount on Second Lien Term Loans
|
|
(5,648
|
)
|
|
—
|
|
Total current debt, net
|
|
$
|
856,646
|
|
|
$
|
—
|
|
|
|
|
|
|
Long-term debt
|
|
|
|
|
Credit Facility due 2019
|
|
$
|
—
|
|
|
$
|
499,000
|
|
Second Lien Term Loans due 2020
|
|
—
|
|
|
205,000
|
|
8% Senior Notes due 2020
|
|
208,885
|
|
|
232,989
|
|
6.625% Senior Notes due 2021
|
|
131,279
|
|
|
432,656
|
|
8% Convertible Senior Notes due 2023
|
|
128,103
|
|
|
—
|
|
|
|
$
|
468,267
|
|
|
$
|
1,369,645
|
|
Unamortized discount on Senior Notes
|
|
(31,517
|
)
|
|
(13,101
|
)
|
Unamortized debt issuance costs
|
|
(3,827
|
)
|
|
(9,775
|
)
|
Total long-term debt, net
|
|
$
|
432,923
|
|
|
$
|
1,346,769
|
|
Total debt, net
|
|
$
|
1,289,569
|
|
|
$
|
1,346,769
|
|
Credit Facility
On April 1, 2014, Legacy LP entered into a
five years
$1.5 billion
secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, Compass Bank, as syndication agent, UBS Securities LLC and U.S. Bank National Association, as co-documentation agents and the lenders party thereto (as amended, the “Credit Agreement”). On March 21, 2019, Legacy entered into the Twelfth Amendment to the Credit Agreement. Please see Note 18 for further discussion. Legacy's obligations under the Credit Agreement are secured by mortgages on over 95% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries and Legacy's ownership interests in the General Partner. Concurrently with the Corporate Reorganization, the General Partner and Legacy Inc. provided guarantees of Legacy LP's obligations under the Credit Agreement. The amount available for borrowing at any one time is limited to the borrowing base and contains a
$2 million
sub-limit for letters of credit. The borrowing base was reaffirmed at
$575 million
as part of the fall 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
redetermination. The borrowing base is subject to semi-annual redeterminations on or about April 1 and October 1 of each year, but no redeterminations are scheduled between now and maturity on April 1, 2019. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. Legacy also has the right, once during each calendar year, to request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Credit Agreement so long as it does not increase the borrowing base then in effect.
Prior to the Corporate Reorganization, the Credit Agreement contained a covenant that prohibited Legacy from paying distributions to its limited partners, including holders of its preferred units, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements were available was greater than
4.0
to
1.0
or (ii) Legacy had unused lender commitments of less than or equal to
15%
of the total lender commitments then in effect. Following the consummation of the Corporate Reorganization, the Credit Agreement contains a covenant that prohibits Legacy from paying dividends to its stockholders, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than
3.0
to
1.0
or (ii) Legacy has unused lender commitments of less than or equal to
20%
of the total lender commitments then in effect.
The Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
|
|
•
|
as of any day, first lien debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to not be greater than
2.5
to
1.0
;
|
|
|
•
|
as of the last day of any fiscal quarter, secured debt to EBITDA as of the last day of any fiscal quarter for the four fiscal quarters then ending of not more than
4.5
to
1.0
, beginning with the fiscal quarter ending on December 31, 2018;
|
|
|
•
|
as of the last day of any fiscal quarter, total EBITDA over the last four quarters to total interest expense over the last four quarters to be greater than
2.0
to
1.0
;
|
|
|
•
|
consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than
1.0
to
1.0
, excluding non-cash assets and liabilities under FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives; and
|
|
|
•
|
as of the last day of any fiscal quarter, the ratio of (a) the sum of (i) the net present value using NYMEX forward pricing, discounted at
10
percent per annum, of Legacy’s proved developed producing oil and gas properties as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be (giving pro forma effect to material acquisitions or dispositions since the date of such reports) (“PDP PV-10”), (ii) the net mark to market value of Legacy’s commodity derivative agreements and (iii) Legacy’s cash and cash equivalents, in each case as of such date to (b) Secured Debt as of such day to be equal to or less than
1.0
to
1.0
.
|
On September 14, 2018 and September 20, 2018, Legacy entered into the Tenth Amendment and Eleventh Amendment, respectively, to the Credit Agreement (the “Credit Agreement Amendments”). The Credit Agreement Amendments amend certain provisions set forth in the Credit Agreement to, among other items:
|
|
•
|
permit the issuance of the 2023 Convertible Notes;
|
|
|
•
|
provide that the 2023 Convertible Notes constitute debt that is permitted refinancing debt;
|
|
|
•
|
allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common stock; and
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
|
|
•
|
permit the redemption of certain senior notes or permitted refinancing debt of such senior notes with any combination of the following: (i) proceeds of certain permitted refinancing debt; (ii) net cash proceeds of any sale of equity interests (other than disqualified capital stock) of Legacy Inc.; and/or (iii) in exchange for equity interests (other than disqualified capital stock) of Legacy Inc.
|
All capitalized terms not defined in the foregoing description have the meaning assigned to them in the Credit Agreement.
As of
December 31, 2018
, Legacy had outstanding borrowings of
$541 million
under the Credit Agreement at a weighted average interest rate of
5.44%
and therefore had approximately
$32.9 million
of borrowing availability remaining. For the year ended
December 31, 2018
, Legacy paid
$27.3 million
of interest expense on the Credit Agreement.
As of
December 31, 2018
, Legacy's ratio of current assets to current liabilities was less than
1.0
to
1.0
, in violation of a covenant contained in the Credit Agreement. On March 21, 2019, Legacy received waivers with respect to compliance with such covenant for the fiscal quarter ended
December 31, 2018
and the requirement of delivery of fiscal year 2018 audited financials without a "going concern" qualification or exception. Legacy was in compliance with all other covenants contained in the Credit Agreement. Depending on future oil and natural gas prices, Legacy could breach certain financial covenants under its Credit Agreement, which would constitute a default under its Credit Agreement. Such default, if not remedied, would require a waiver from Legacy's lenders in order for it to avoid an event of default and, subject to certain limitations, subsequent acceleration of all amounts outstanding under its Credit Agreement and potential foreclosure on its oil and natural gas properties. If the lenders under Legacy's Credit Agreement were to accelerate the indebtedness under its Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of its other outstanding indebtedness, including its Second Lien Term Loans (as defined below), its
8%
Senior Notes due 2020 (the "2020 Senior Notes"), its
6.625%
Senior Notes due 2021 (the "2021 Senior Notes") and its
8%
Convertible Senior Notes due 2023 (the "2023 Convertible Notes" and, together with the 2020 Senior Notes and the 2021 Senior Notes, the “Senior Notes”), and permit the holders of such indebtedness to accelerate the maturities of such indebtedness. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, Legacy believes the long-term global outlook for commodity prices and its efforts to date will be viewed positively by its lenders.
Second Lien Term Loans
On October 25, 2016, Legacy entered into a Second Lien Term Loan Credit Agreement (as amended, the "Term Loan Credit Agreement") among Legacy, as borrower, Cortland Capital Market Services LLC ("Cortland"), as administrative agent and second lien collateral agent, and the lenders party thereto, providing for term loans up to an aggregate principal amount of
$300.0 million
(the “Second Lien Term Loans”). On May 21, 2019, Legacy entered into the Seventh Amendment to the Term Loan Credit Agreement. Please see Note 18 for further discussion. The Second Lien Term Loans under the Term Loan Credit Agreement are issued with an upfront fee of
2%
and bear interest at a rate of
12%
per annum payable quarterly in cash. GSO Capital Partners L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Term Loan Credit Agreement matures on August 31, 2021; provided that, if on July 1, 2020, Legacy has greater than or equal to a face amount of
$15.0 million
of Senior Notes that were outstanding on the date the Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Term Loan Credit Agreement will mature on August 1, 2020. The Second Lien Term Loans are secured on a second lien priority basis by the same collateral that secures Legacy's Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that are guarantors under the Credit Agreement. In addition, upon consummation of the Corporate Reorganization, the General Partner and Legacy Inc. became guarantors. As of
December 31, 2018
, Legacy had approximately
$338.6 million
drawn under the Term Loan Credit Agreement. On December 31, 2017, Legacy entered into the Third Amendment to the Term Loan Credit Agreement (the "Third Amendment") among Legacy, as borrower, Cortland, as administrative agent and second lien collateral agent, and the lenders party thereto, including GSO and certain funds and accounts managed, advised or sub-advised by GSO, which, among other things, increased the maximum amount available for borrowing under the Second Lien Term Loans to
$400.0 million
, extended the availability of undrawn principal (
$61.4 million
of availability as of
December 31, 2018
) to October 25, 2019 and relaxed the asset coverage ratio to
0.85
to
1.00
until the fiscal quarter ended December 31, 2018. The Third Amendment became effective on January 5, 2018.
Prior to the Corporate Reorganization, the Term Loan Credit Agreement contained a covenant that prohibited Legacy from paying distributions to its limited partners, including holders of its preferred units, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements were available was greater than
4.00
to 1.00 or (ii) Legacy had unused lender commitments of less than or equal to 15% of the total lender commitments then in effect. Following consummation of the Corporate Reorganization, the Term Loan Credit Agreement contains a covenant that prohibits Legacy from paying dividends to the stockholders, if (i) Total Debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
financial statements are available is greater than
3.00
to 1.00 or (ii) Legacy has unused lender commitments of less than or equal to 20% of the total lender commitments then in effect.
The Term Loan Credit Agreement also contains covenants that, among other things, require Legacy to:
|
|
•
|
not permit, as of the last day of any fiscal quarter, the ratio of the sum of (i) the net present value using NYMEX forward pricing of Legacy’s PDP PV-10, (ii) the net mark to market value of Legacy’s commodity derivative agreements and (iii) Legacy’s cash and cash equivalents to Secured Debt to be less than
0.85
to 1.00 until the fiscal quarter ended December 31, 2018 and
1.00
to 1.00 thereafter; and
|
|
|
•
|
not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, Legacy’s ratio of Secured Debt as of such day to EBITDA for the four fiscal quarters then ending to be greater than
4.50
to 1.00.
|
On September 14, 2018 and September 20, 2018, Legacy entered into the Fifth Amendment and Sixth Amendment, respectively, to the Term Loan Credit Agreement (the “Term Loan Amendments”). The Term Loan Amendments amend certain provisions set forth in the Term Loan Credit Agreement to, among other items:
|
|
•
|
permit the issuance of the 2023 Convertible Notes;
|
|
|
•
|
provide that the 2023 Convertible Notes constitute debt that is permitted refinancing debt;
|
|
|
•
|
allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common stock; and
|
|
|
•
|
permit the redemption of certain senior notes or permitted refinancing debt of such senior notes with any combination of the following: (i) proceeds of certain permitted refinancing debt; (ii) net cash proceeds of any sale of equity interests (other than disqualified capital stock) of Legacy Inc.; and/or (iii) in exchange for equity interests (other than disqualified capital stock) of Legacy Inc.
|
At
December 31, 2018
, Legacy was in compliance with all covenants contained in the Second Lien Term Loan Credit Agreement.
For the year ended
December 31, 2018
, Legacy incurred interest expense of
$41.0 million
under the Second Lien Term Loan Credit Agreement.
8% Senior Notes Due 2020
On December 4, 2012, Legacy and its
100%
owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of
$300.0 million
of Legacy's
8%
Senior Notes due 2020 (the "2020 Senior Notes"), which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at
97.848%
of par.
Legacy has the option to redeem the 2020 Senior Notes, in whole or in part, at par together with any accrued and unpaid interest, if any, to the date of redemption.
Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of
101%
of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its
100%
owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as Legacy's Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other debt; or (vii) upon merging into, or transferring all of its properties
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
to Legacy or another guarantor and ceasing to exist. Refer to Note 17 - Subsidiary Guarantors for further details on Legacy's guarantors.
The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and certain other conditions; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. Further, if the lenders under Legacy's Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under Legacy's Credit Agreement or Term Loan Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2020 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness.
In connection with the exchange of approximately
$21.0 million
aggregate principal amount of 2020 Senior Notes for the same aggregate principal of the 2023 Convertible Notes and the issuance of
105,020
shares of Common Stock in September 2018, Legacy recognized a
$1.4 million
gain on extinguishment of debt, which consisted of the difference between (1) the face amount of the exchanged 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the new 2023 Convertible Notes.
During the year ended
December 31, 2018
, Legacy exchanged
1,000,000
shares of Common Stock for
$3.1 million
of face amount of its outstanding 2020 Senior Notes. Legacy treated the exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on the date of exchange.
During the year ended December 31, 2016, Legacy repurchased a face amount of
$52.0 million
of its 2020 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.
On June 1, 2016, Legacy exchanged
2,719,124
units representing limited partner interests in the Partnership for
$15.0 million
of face amount of its outstanding 2020 Senior Notes. Legacy treated this exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on June 1, 2016.
The indenture also includes customary events of default. As of the
December 31, 2018
, the Company was in compliance with all covenants of the 2020 Senior Notes.
Interest is payable on June 1 and December 1 of each year.
6.625% Senior Notes Due 2021
On May 28, 2013, Legacy and its
100%
owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of
$250 million
of Legacy's
6.625%
Senior Notes due 2021 (the "2021 Senior Notes"), which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at
98.405%
of par.
On May 13, 2014, Legacy and its
100%
owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional
$300 million
of the
6.625%
2021 Senior Notes. These 2021 Senior Notes were issued at
99%
of par.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The terms of the 2021 Senior Notes, including details related to Legacy's guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the maturity date, interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at par together with any accrued and unpaid interest, if any, to the date of redemption.
Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of
101%
of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy and Legacy Reserves Finance Corporation's obligations under the 2021 Senior Notes are guaranteed by the same parties and on the same terms as Legacy's 2020 Senior Notes discussed above. Further, if the lenders under Legacy's Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under Legacy's Credit Agreement or Term Loan Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2021 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness.
As of
December 31, 2018
, the Company was in compliance with all covenants of the 2021 Senior Notes.
Interest is payable on June 1 and December 1 of each year.
On September 20, 2018, in connection with the exchange of approximately
$109.0 million
aggregate principal amount of 2021 Senior Notes for the same aggregate principal of the 2023 Convertible Notes, Legacy recognized a
$10.7 million
gain on extinguishment of debt, which consisted of the difference between (1) the face amount of the exchanged 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the new 2023 Convertible Notes.
During the year ended
December 31, 2018
, Legacy exchanged
2,000,000
shares of Common Stock for
$5.3 million
of face amount of its outstanding 2020 Senior Notes. Legacy treated the exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on the date of exchange.
On December 31, 2017, Legacy entered into an agreement to repurchase a face amount of
$187.1 million
of its 2021 Senior Notes from certain holders in a single transaction. The transaction was funded on January 5, 2018 and will therefore be recognized in 2018. Legacy will treat this repurchase as an extinguishment of debt. Accordingly, Legacy will recognize a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.
During the year ended December 31, 2016, Legacy repurchased a face amount of
$117.3 million
of its 2021 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price.
For the year ended
December 31, 2018
, Legacy paid
$34.6 million
of cash interest expense for the 2020 Senior Notes and 2021 Senior Notes.
8% Convertible Senior Notes Due 2023 ("2023 Convertible Notes")
On September 20, 2018, the Issuers, completed private exchanges with certain holders of senior notes, pursuant to which the Issuers exchanged (i)
$21.004 million
aggregate principal amount of 2020 Senior Notes for
$21.004 million
aggregate principal amount of 2023 Convertible Notes and
105,020
shares of common stock and (ii)
$109.0 million
aggregate principal amount of 2021 Senior Notes for
$109.0 million
aggregate principal amount of 2023 Convertible Notes. The 2023 Convertible Notes were issued pursuant to an Indenture, dated as of September 20, 2018 (the “2023 Convertible Note Indenture”)
Upon issuance, the Company separately accounted for the liability and equity components in accordance with Accounting Standards Codification 470-20. The initial fair value of the 2023 Convertible Notes in its entirety (inclusive of the equity component related to the conversion option) was estimated using observable inputs such as trades that occurred on the day of the transaction. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the aggregate principal amount of the 2023 Convertible Notes and the fair value of the liability component was recorded as a debt discount and is being amortized to interest expense over the term of the notes using the effective interest method. The fair value of the liability component of the 2023 Convertible Notes was estimated at
$101.0 million
, resulting in a
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
debt discount of
$29.0 million
The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial fair value of the 2023 Convertible Notes. The equity component was recorded in additional paid-in capital within stockholders’ equity and will not be remeasured as long as it continues to meet the conditions for equity classification.
The 2023 Convertible Notes mature on September 20, 2023, unless earlier repurchased or redeemed by the Issuers or converted. The 2023 Convertible Notes are subject to redemption for cash, in whole or in part, at the Issuers’ option at a redemption price equal to
100%
of the 2023 Convertible Notes to be redeemed, plus any accrued and unpaid interest. In addition, the Issuers are required to make an offer to holders of the 2023 Convertible Notes upon a change of control at a price equal to
101%
, plus any accrued and unpaid interest, and an offer to holders of the 2023 Convertible Notes upon consummation by the Issuers or any restricted subsidiaries of certain asset sales at a price equal to
100%
, plus any accrued and unpaid interest.
The 2023 Convertible Notes are convertible into shares of common stock at an initial conversion rate of
166.6667
shares per
$1,000
principal amount of 2023 Convertible Notes, which is equal to an initial conversion price of
$6.00
per share of common stock (the "Conversion Price").
The 2023 Convertible Notes are convertible, at the option of the holders, into shares of common stock at any time from the date of issuance up until the close of business on the earlier of (i) the business day prior to the date of a mandatory conversion notice, (ii) with respect to a 2023 Convertible Note called for redemption, the business day immediately preceding the redemption date or (iii) the business day immediately preceding the maturity date. In addition, if a holder exercises its right to convert on or prior to September 19, 2019, such holder will receive an early conversion payment, in cash, per
$1,000
principal amount as follows:
|
|
|
|
Early Conversion Date
|
|
Early Conversion Payment
|
December 1, 2018 through May 31, 2019
|
|
$64.22
|
June 1, 2019 through September 19, 2019
|
|
$24.22
|
Subject to compliance with certain conditions, the Issuers have the right to mandatorily convert all of the 2023 Convertible Notes if the volume weighted average price of the common stock equals or exceeds the conversion price for at least
20
trading days (whether or not consecutive) during any period of
30
consecutive trading days commencing on or after the initial issuance date.
The 2023 Convertible Notes are guaranteed by Legacy Inc., the General Partner, Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services LLC, Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC.
The terms of the 2023 Convertible Notes, including the Guarantors, are substantially identical to the terms of the 2020 Senior Notes and 2021 Senior Notes with the exception of the interest rate, conversion and redemption provisions noted above. Additionally, if the lenders under Legacy's Credit Agreement or Term Loan Credit Agreement were to accelerate the indebtedness under Legacy's Credit Agreement or Term Loan Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2023 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness.
During the year ended
December 31, 2018
, certain holders of the 2023 Convertible Notes exercised their option to convert
$1.9 million
of face amount of 2023 Convertible Notes in exchange for
316,828
shares of common stock.
Interest is payable on June 1 and December 1 of each year.
|
|
(4)
|
Impact of ASC 606 Adoption
|
On January 1, 2018, Legacy adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”) using the modified retrospective method of transition applied to all contracts. ASU 2014-09 created ASC 606 - Revenue from Contracts with Customers ("ASC 606"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP and includes a five step process to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The impact of adoption on Legacy's current period results is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve months ended December 31, 2018
|
|
|
Under ASC 606
|
|
Under ASC 605
|
|
Change
|
|
|
(In thousands)
|
Revenues:
|
|
|
|
|
|
|
|
Oil Sales
|
|
$
|
375,444
|
|
|
$
|
375,244
|
|
|
$
|
(200
|
)
|
Natural gas liquids (NGL) sales
|
|
27,750
|
|
|
27,232
|
|
|
(518
|
)
|
Natural gas sales
|
|
151,667
|
|
|
145,135
|
|
|
(6,532
|
)
|
|
|
$
|
554,861
|
|
|
$
|
547,611
|
|
|
$
|
(7,250
|
)
|
Costs and expenses:
|
|
|
|
|
|
|
Oil and natural gas production
|
|
200,285
|
|
|
193,035
|
|
|
(7,250
|
)
|
|
|
|
|
|
|
|
Net income
|
|
43,833
|
|
|
43,833
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Partners' deficit, as of January 1, 2018
|
|
271,687
|
|
|
271,687
|
|
|
$
|
—
|
|
The change to oil sales and a related change to oil production expense are due to the conclusion that Legacy transfers control of oil production to purchasers at or near the wellhead. As such, certain transportation expenses that are deducted from the sales price Legacy receives from the purchaser are presented net in revenue in accordance with ASC 606. This represents a change from Legacy's prior practice under ASC 605 of presenting those transportation costs gross as an oil and natural gas production expense.
The change to natural gas and NGL sales and the related change to natural gas production expense are due to the conclusion that Legacy represents an agent in certain gas processing agreements with midstream entities in accordance with the control model in ASC 606. This represents a change from Legacy's previous conclusion utilizing the principal versus agent indicators under ASC 605 that Legacy acted as the principal in those arrangements. As a result, Legacy is required to present certain gathering and processing expenses net in natural gas and NGL sales under ASC 606.
|
|
(5)
|
Revenue from Contracts with Customers
|
Oil, NGL and natural gas sales revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. This generally occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. A more detailed summary of the sale of each product type is included below.
Oil Sales
Legacy's oil sales contracts are generally structured such that Legacy sells its oil production to the purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality and physical location. Legacy recognizes revenue when control transfers to the purchaser upon delivery at the net price received from purchaser.
NGL and Natural Gas Sales
Under Legacy's gas processing contracts, Legacy delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to Legacy for the resulting sales of NGLs and residue gas. In these scenarios, Legacy evaluates whether it is the principal or the agent in the transaction. In virtually all of Legacy's gas processing contracts, Legacy has concluded that it is the agent, and the midstream processing entity is Legacy's customer. Accordingly, Legacy recognizes revenue upon delivery based on the net amount of the proceeds received from the midstream processing entity. Proceeds are generally tied to the prevailing index prices for residue gas and NGLs less deductions for gathering, processing, transportation and other expenses.
Under Legacy's dry gas sales that do not require processing, Legacy sells its natural gas production to third party purchasers at a contractually specified delivery point at or near the wellhead. Pricing provisions are tied to a market index, with certain deductions based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. Legacy recognizes revenue upon delivery of the natural gas to third party purchasers based on the relevant index price net of deductions.
Imbalances
Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2018, 2017 and 2016.
Disaggregation of Revenue
Legacy has identified three material revenue streams in its business: oil sales, NGL sales, and natural gas sales. Revenue attributable to each of Legacy's identified revenue streams is disaggregated in the table below.
|
|
|
|
|
|
|
|
Twelve Months Ended
|
|
|
December 31,
|
|
|
2018
|
|
|
(In thousands)
|
Revenues:
|
|
|
Oil sales
|
|
$
|
375,444
|
|
Natural gas liquids (NGL) sales
|
|
27,750
|
|
Natural gas sales
|
|
151,667
|
|
Total revenues
|
|
$
|
554,861
|
|
Significant Judgments
Principal versus agent
Legacy engages in various types of transactions in which midstream entities process its gas and subsequently market resulting NGLs and residue gas to third-party customers on Legacy's behalf, such as Legacy's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether Legacy is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.
Transaction price allocated to remaining performance obligations
A significant number of Legacy's product sales are short-term in nature with a contract term of one year or less. For those contracts, Legacy has utilized the practical expedient in ASC 606 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For Legacy's product sales that have a contract term greater than one year, Legacy has utilized the practical expedient in ASC 606 that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Contract balances
Under Legacy's product sales contracts, it is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional and invoiced amounts are recorded as “Accounts receivable - oil and natural gas” in its consolidated balance sheet.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. In this scenario, payment is also unconditional, as Legacy has satisfied its performance obligations through delivery of the relevant product. As a result, Legacy has concluded that its product sales do not give rise to contract assets or liabilities under ASC 606.
Prior-period performance obligations
Legacy records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, Legacy is required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated.
Legacy records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Legacy has existing internal controls in place for its estimation process, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the
twelve
months ended
December 31, 2018
, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
(6) Asset Acquisitions and Dispositions
On August 1, 2017, Legacy made a payment in the amount of
$141 million
(the “Acceleration Payment”) in connection with its First Amended and Restated Development Agreement (the “Restated Agreement”) with Jupiter JV, LP (“Jupiter”). The Acceleration Payment caused the reversion to Legacy of additional working interests in all wells and associated personal property and infrastructure (collectively, the “Wells”) and all undeveloped assets subject to the Restated Agreement. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01. Therefore, the acquired interests were recorded based upon the cash consideration paid, with all value assigned to proved oil and natural gas properties.
During the year ended
December 31, 2018
, Legacy divested certain individually immaterial oil and natural gas assets for net cash proceeds of
$55.0 million
. These dispositions were treated as asset sales and resulted in a gain on disposition of assets of
$23.8 million
during the period.
(7) Related Party Transactions
Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which former Legacy director Cary D. Brown is a principal. Legacy has contracted with Blue Quail to provide water transfer services and paid
$169,949
,
$9,758
and
$98,297
in
2018
,
2017
and
2016
, respectively to Blue Quail for such services.
(8) Commitments and Contingencies
From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows.
Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected.
Legacy has employment agreements with its officers. The employment agreements with its officers specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from
12
to
36
months salary plus bonus and COBRA benefits, respectively.
(9) Business and Credit Concentrations
LEGACY RESERVES LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Cash
Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash.
Revenue and Accounts Receivable
Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables.
No
bad debt expense was recorded in
2018
,
2017
or
2016
. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 12.
Commodity Derivatives
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, collars and enhanced swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. Legacy values these transactions at fair value on a recurring basis (Note 10). As of
December 31, 2018
, Legacy’s commodity derivative transactions have a fair value favorable to the Company of
$67.2 million
, collectively. Legacy enters into commodity derivative transactions with entities which Legacy's management believes are creditworthy. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis.
(10) Fair Value Measurements
Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
|
|
|
Level 1:
|
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
|
Level 2:
|
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and collars and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date.
|
Level 3:
|
Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.
|
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair Value on a Recurring Basis
The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31,
2018
and
2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
Quoted Prices in
Active Markets for
Identical Assets
|
|
Significant Other
Observable
Inputs
|
|
Significant
Unobservable
Inputs
|
|
Total Fair Value
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
Description
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
|
|
|
(In thousands)
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
—
|
|
|
$
|
69,288
|
|
|
$
|
—
|
|
|
$
|
69,288
|
|
|
$
|
(4,670
|
)
|
|
$
|
64,618
|
|
Interest rate derivatives
|
|
—
|
|
|
2,044
|
|
|
—
|
|
|
2,044
|
|
|
—
|
|
|
2,044
|
|
Noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
—
|
|
|
3,473
|
|
|
—
|
|
|
3,473
|
|
|
(338
|
)
|
|
3,135
|
|
Interest rate derivatives
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
—
|
|
|
(4,670
|
)
|
|
—
|
|
|
(4,670
|
)
|
|
4,670
|
|
|
—
|
|
Noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
—
|
|
|
(888
|
)
|
|
—
|
|
|
(888
|
)
|
|
338
|
|
|
(550
|
)
|
|
|
$
|
—
|
|
|
$
|
69,247
|
|
|
$
|
—
|
|
|
$
|
69,247
|
|
|
$
|
—
|
|
|
$
|
69,247
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
Quoted Prices in
Active Markets for
Identical Assets
|
|
Significant Other
Observable
Inputs
|
|
Significant
Unobservable
Inputs
|
|
Total Fair Value
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
Description
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
|
|
|
(In thousands)
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
—
|
|
|
$
|
19,792
|
|
|
$
|
—
|
|
|
$
|
19,792
|
|
|
$
|
(7,204
|
)
|
|
$
|
12,588
|
|
Interest rate derivatives
|
|
—
|
|
|
837
|
|
|
—
|
|
|
837
|
|
|
(1
|
)
|
|
836
|
|
Noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
—
|
|
|
14,278
|
|
|
—
|
|
|
14,278
|
|
|
(1,460
|
)
|
|
12,818
|
|
Interest rate derivatives
|
|
—
|
|
|
1,281
|
|
|
—
|
|
|
1,281
|
|
|
|
|
1,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
—
|
|
|
(21,027
|
)
|
|
(4,191
|
)
|
|
(25,218
|
)
|
|
7,204
|
|
|
(18,014
|
)
|
Interest rate derivatives
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
LTIP liability
|
|
—
|
|
|
(1,947
|
)
|
|
—
|
|
|
(1,947
|
)
|
|
|
|
(1,947
|
)
|
Noncurrent
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
—
|
|
|
(1,637
|
)
|
|
(897
|
)
|
|
(2,534
|
)
|
|
1,460
|
|
|
(1,074
|
)
|
Interest rate derivatives
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
$
|
—
|
|
|
$
|
11,576
|
|
|
$
|
(5,088
|
)
|
|
$
|
6,488
|
|
|
$
|
—
|
|
|
$
|
6,488
|
|
Legacy estimates the fair values of its commodity swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including costless collars, three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for Legacy's oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of its interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of Legacy's non-performance risk and the credit standing of the counterparties involved in Legacy’s derivative contracts. The risk of nonperformance by Legacy’s counterparties is mitigated by the fact that enters into derivative transactions with entities which Legacy's management believes are creditworthy. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
|
December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
(In thousands)
|
|
Beginning balance
|
$
|
(5,088
|
)
|
|
$
|
8
|
|
|
$
|
(4,493
|
)
|
|
Total gains (losses)
|
30,571
|
|
|
(5,073
|
)
|
|
253
|
|
|
Settlements
|
(22,379
|
)
|
|
(23
|
)
|
|
4,248
|
|
|
Transfers
|
(3,104
|
)
|
(a)
|
—
|
|
|
—
|
|
|
Ending balance
|
$
|
—
|
|
|
$
|
(5,088
|
)
|
|
$
|
8
|
|
|
Gains (losses) included in earnings relating to derivatives
|
|
|
|
|
|
|
|
still held as of December 31, 2018, 2017 and 2016
|
$
|
—
|
|
|
$
|
(5,088
|
)
|
|
$
|
68
|
|
|
____________________
|
|
(a)
|
Due to the lack of a historical market, we have historically accounted for our Midland-to-Cushing crude oil differential swaps as Level 3. However, with recent widening differentials, an active market has been created in which quoted prices are readily observable. As such, we have determined that the inputs used to value these derivatives now classify as Level 2 and transferred the value of the derivatives into Level 2.
|
During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Legacy's derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within Legacy's consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on Legacy's results of operations or financial condition.
Fair Value on a Non-Recurring Basis
Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("ARO") estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these measurements as Level 3. A reconciliation of the beginning and ending balances of Legacy’s ARO is presented in Note 13.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31,
2018
and
2017
consist of adjustments of the carrying value oil and natural gas properties to their fair value of
$43.9 million
and
$31.9 million
, respectively. Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the year ended
December 31, 2018
, Legacy incurred impairment charges of
$58.7 million
as oil and natural gas properties with a net cost basis of
$102.6 million
were written down to their fair value of
$43.9 million
. During the year ended
December 31, 2017
, Legacy incurred impairment charges of
$37.3 million
as oil and natural gas properties with a net cost basis of
$69.1 million
were written down to their fair value of
$31.8 million
. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.
The remaining
$9.3 million
of impairment during the year ended
December 31, 2018
represented impairment of unproved properties acquired since 2010 that are no longer viable for development.
(11) Derivative Financial Instruments
Commodity derivative transactions
Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps and enhanced swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
These derivative instruments are intended to mitigate a portion of Legacy’s price-risk and may be considered hedges for economic purposes, but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings.
By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates credit risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended
December 31, 2018
,
2017
, and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Beginning fair value of commodity derivatives
|
$
|
6,318
|
|
|
$
|
12,698
|
|
|
$
|
118,427
|
|
Total gain (loss) crude oil derivatives
|
54,380
|
|
|
(15,325
|
)
|
|
(9,410
|
)
|
Total gain (loss) natural gas derivatives
|
(5,208
|
)
|
|
33,101
|
|
|
(31,814
|
)
|
Crude oil derivative cash settlements paid (received)
|
16,845
|
|
|
(11,840
|
)
|
|
(37,464
|
)
|
Natural gas derivative cash settlements received
|
(5,130
|
)
|
|
(12,316
|
)
|
|
(27,041
|
)
|
Ending fair value of commodity derivatives
|
$
|
67,205
|
|
|
$
|
6,318
|
|
|
$
|
12,698
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of
December 31, 2018
, Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
|
|
|
|
|
|
|
|
|
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Price per Bbl
|
|
Price Range per Bbl
|
2019
|
|
3,285,000
|
|
$61.33
|
|
$57.15
|
-
|
$67.65
|
As of
December 31, 2018
, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:
|
|
|
|
|
|
|
|
|
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Price per Bbl
|
|
Price Range per Bbl
|
2019
|
|
2,193,000
|
|
$(3.62)
|
|
$(5.60)
|
-
|
$(1.15)
|
As of
December 31, 2018
, Legacy had the following Midland-to-Cushing crude oil differential enhanced swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:
|
|
|
|
|
|
|
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Short Call Price per Bbl
|
|
Average Swap Price per Bbl
|
2019
|
|
$1,460,000
|
|
$70.00
|
|
$(2.91)
|
As of
December 31, 2018
, Legacy had the following NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
Price Range
|
Calendar Year
|
|
Volumes (MMBtu)
|
|
Price per MMBtu
|
|
per MMBtu
|
2019
|
|
37,175,000
|
|
$3.36
|
|
$3.05
|
-
|
$4.40
|
As of
December 31, 2018
, Legacy had the following Henry Hub NYMEX to CIG natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
Price Range
|
Calendar Year
|
|
Volumes (MMBtu)
|
|
Price per MMBtu
|
|
per MMBtu
|
2019
|
|
3,600,000
|
|
$(0.47)
|
|
$(0.46)
|
-
|
$(0.49)
|
Interest rate derivative transactions
Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in overhedged amounts.
Legacy does not designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings and classified as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Beginning fair value of interest rate swaps
|
$
|
2,117
|
|
|
$
|
183
|
|
|
$
|
(362
|
)
|
Total gain (loss) loss on interest rate swaps
|
1,213
|
|
|
1,168
|
|
|
(2,108
|
)
|
Cash settlements paid
|
(1,286
|
)
|
|
766
|
|
|
2,653
|
|
Ending fair value of interest rate swaps
|
$
|
2,044
|
|
|
$
|
2,117
|
|
|
$
|
183
|
|
The table below summarizes the interest rate swap assets and liabilities as of
December 31, 2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Fixed
|
|
Effective
|
|
Maturity
|
|
Estimated
Fair Market Value
at
December 31,
|
Notional Amount
|
|
Rate
|
|
Date
|
|
Date
|
|
2018
|
|
|
(Dollars in thousands)
|
$235,000
|
|
1.363
|
%
|
|
9/1/2015
|
|
9/1/2019
|
|
2,044
|
|
Total fair value of interest rate derivatives
|
|
|
|
|
|
|
|
$
|
2,044
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(12) Sales to Major Customers
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%
|
(13) Asset Retirement Obligation
An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period in which it is incurred and becomes determinable. When liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the additions to the ARO asset and liability is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by Legacy's management at the time of the valuation and are the most sensitive and subject to change. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon Legacy’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using Legacy’s credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. When obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from Legacy's balance sheet. Any difference in the cost to plug and the related liability is recorded as a gain or loss on Legacy's statement of operations in the disposal of assets line item.
The following table reflects the changes in the ARO during the years ended December 31,
2018
,
2017
and
2016
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Asset retirement obligation — beginning of period
|
$
|
274,686
|
|
|
$
|
272,148
|
|
|
$
|
286,405
|
|
Liabilities incurred with properties acquired
|
226
|
|
|
62
|
|
|
24
|
|
Liabilities incurred with properties drilled
|
65
|
|
|
39
|
|
|
1
|
|
Liabilities settled during the period
|
(2,258
|
)
|
|
(1,891
|
)
|
|
(2,351
|
)
|
Liabilities associated with properties sold
|
(27,673
|
)
|
|
(8,464
|
)
|
|
(24,605
|
)
|
Current period accretion
|
12,568
|
|
|
12,792
|
|
|
12,674
|
|
Current period revisions to previous estimates
|
(4,880
|
)
|
|
—
|
|
|
—
|
|
Asset retirement obligation — end of period
|
$
|
252,734
|
|
|
$
|
274,686
|
|
|
$
|
272,148
|
|
Each year Legacy reviews and, to the extent necessary, revises its ARO estimates. During
2018
, Legacy reviewed future anticipated abandonment dates with previous estimates and, as a result, decreased its estimate of future asset retirement obligations by
$4.9 million
. During
2016
and
2017
,
no
revisions of previous estimates were deemed necessary.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(14) Stockholders' Deficit / Partners' Deficit
Preferred Units
On September 20, 2018, in connection with the Corporate Reorganization, all of Legacy LP's 8% Series A Fixed-to-Floating Cumulative Redeemable Perpetual Preferred Units and 8.000% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding were converted into shares of common stock.
Incentive Distribution Units
On September 20, 2018, all of Legacy LP's Incentive Distribution Units outstanding were cancelled in connection with the Corporate Reorganization.
Loss per share / unit
The following table sets forth the computation of basic and diluted loss per share / unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Income/(loss)
|
$
|
43,833
|
|
|
$
|
(53,897
|
)
|
|
$
|
(55,820
|
)
|
Income/(loss) attributable to shareholders
|
$
|
43,833
|
|
|
$
|
(53,897
|
)
|
|
$
|
(55,820
|
)
|
Weighted average number of shares outstanding
|
105,087
|
|
|
100,049
|
|
|
98,249
|
|
Effect of dilutive securities:
|
|
|
|
|
|
Restricted and phantom units
|
—
|
|
|
—
|
|
|
—
|
|
Weighted average units and potential units outstanding
|
105,087
|
|
|
100,049
|
|
|
98,249
|
|
Basic and diluted income/(loss) per share
|
$
|
0.42
|
|
|
$
|
(0.54
|
)
|
|
$
|
(0.57
|
)
|
As of December 31,
2018
,
7,302,809
restricted stock units were excluded from the calculation of diluted earnings per share due to their anti-dilutive effect. As of December 31,
2017
,
241,373
restricted units and
1,389,773
phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. As of December 31,
2016
,
484,447
restricted units and
1,212,692
phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.
As of December 31,
2018
,
21,356,510
shares related to 2023 Convertible Notes were excluded from the calculation of diluted earnings per share due to their anti-dilutive effect.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(15) Stock-Based Compensation
Legacy LP Long Term Incentive Plan
On March 15, 2006, a Long-Term Incentive Plan (as amended, “LTIP”) for Legacy was created and Legacy adopted the LTIP for its employees, consultants and directors, its affiliates and its general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights (“UARs”). The LTIP permits the grant of awards that may be made or settled in units up to an aggregate of
5,000,000
units. As of September, 2018 grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering
3,459,197
units had been made, comprised of
266,014
unit option awards,
988,207
restricted unit awards,
1,424,114
phantom unit awards and
780,862
unit awards. Pursuant to the terms of the Corporate Reorganization, the Legacy LP long-term incentive plan ("Legacy LP LTIP") was terminated.
Unit Appreciation Rights
A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy accounts for the UARs under the liability method.
During the year ended
December 31, 2016
, Legacy issued (i)
204,500
UARs to employees which vest ratably over a
three
-year period and (ii)
96,520
UARs to employees which cliff-vest at the end of a
three
-year period. Legacy did not issue UARs to employees during the years ended
December 31, 2017
and
2018
. All outstanding UARs were exercised or forfeited in connection with the Corporate Reorganization.
For the years ended December 31,
2018
,
2017
and
2016
, Legacy recorded compensation (benefit) expense of
$(169,024)
,
$(37,240)
and
$223,569
, respectively, due to the changes in the compensation liability related to the above awards based on its use of the Black-Scholes model to estimate the December 31,
2018
,
2017
and
2016
fair value of these UARs. All outstanding UARs vested on September 20, 2018 in connection with the Corporate Reorganization and were subsequently exercised or forfeited.
The cost of employee services in exchange for an award of equity instruments was measured based on a grant-date fair value of the award (with limited exceptions), and that cost was generally recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing stock predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Because the UARs were settled in cash, Legacy accounted for them by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period. Compensation cost was recognized based on the change in the liability between periods.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
A summary of UAR activity for the year ended December 31,
2018
,
2017
and
2016
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
Weighted-Average
Exercise
Price
|
|
Weighted-Average Remaining
Contractual
Term
|
|
Aggregate Intrinsic Value
|
Outstanding at January 1, 2016
|
936,116
|
|
|
$
|
20.61
|
|
|
|
|
|
Expired
|
(21,067
|
)
|
|
$
|
16.07
|
|
|
|
|
|
Forfeited
|
(30,503
|
)
|
|
$
|
19.80
|
|
|
|
|
|
Outstanding at December 31, 2016
|
884,546
|
|
|
$
|
20.75
|
|
|
3.67
|
|
$
|
—
|
|
UARs exercisable at
|
|
|
|
|
|
|
|
December 31, 2016
|
570,369
|
|
|
$
|
24.38
|
|
|
2.77
|
|
$
|
—
|
|
Outstanding at January 1, 2017
|
884,546
|
|
|
$
|
20.75
|
|
|
|
|
|
Expired
|
(147,024
|
)
|
|
$
|
24.50
|
|
|
|
|
|
Forfeited
|
(15,501
|
)
|
|
$
|
13.91
|
|
|
|
|
|
Outstanding at December 31, 2017
|
722,021
|
|
|
$
|
20.13
|
|
|
3.29
|
|
$
|
—
|
|
UARs exercisable at
|
|
|
|
|
|
|
|
December 31, 2017
|
592,522
|
|
|
$
|
23.23
|
|
|
2.99
|
|
$
|
—
|
|
Outstanding at January 1, 2018
|
722,021
|
|
|
$
|
20.13
|
|
|
|
|
|
Expired
|
(90,844
|
)
|
|
$
|
4.69
|
|
|
|
|
|
Forfeited
|
(631,177
|
)
|
|
$
|
22.35
|
|
|
|
|
|
Outstanding at December 31, 2018
|
—
|
|
|
$
|
—
|
|
|
0.00
|
|
$
|
—
|
|
UARs exercisable at
|
|
|
|
|
|
|
|
December 31, 2018
|
—
|
|
|
$
|
—
|
|
|
0.00
|
|
$
|
—
|
|
The following table summarizes the status of Legacy’s non-vested UARs since January 1,
2018
:
|
|
|
|
|
|
|
|
|
Non-Vested UARs
|
|
Number of
Units
|
|
Weighted-
Average Exercise
Price
|
Non-vested at January 1, 2018
|
129,499
|
|
|
$
|
5.97
|
|
Vested
|
(124,832
|
)
|
|
5.99
|
|
Forfeited
|
(4,667
|
)
|
|
5.25
|
|
Non-vested at December 31, 2018
|
—
|
|
|
$
|
—
|
|
Phantom Units
Legacy previously issued phantom units under the Legacy LP LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either one Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy accounted for the phantom units settled in Partnership units by utilizing the equity method. Legacy accounted for the phantom units settled in cash by utilizing the liability method.
391,674
Phantom units that settle in cash and
1,032,440
phantom units that settle in units vested on September 20, 2018 in connection with the Corporate Reorganization.
Compensation expense related to the phantom units was
$22.9 million
,
$4.6 million
and
$3.7 million
for the years ended December 31,
2018
,
2017
and
2016
, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Restricted Units
Legacy LP previously issued restricted units to certain employees and members of management. All restricted units vested on September 20, 2018 in connection with the Corporate Reorganization.
Compensation expense related to restricted units was
$0.8 million
,
$1.5 million
and
$2.7 million
for the years ended December 31,
2018
,
2017
and
2016
, respectively.
Board Units
On
May 10, 2016
, Legacy granted and issued
39,526
units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was
$2.59
at the time of issuance. On
May 16, 2017
, Legacy granted and issued
47,847
units to each of its
six
non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was
$2.04
at the time of issuance. On
May 15, 2018
, Legacy granted and issued
12,019
units to
four
non-employee directors who serve on the Board of Directors of Legacy and
6,010
units to
two
non-employee directors of Legacy LP who do not serve on the Board of Directors of Legacy Inc. The value of each unit was
$8.69
at the time of issuance. None of these units were subject to vesting. Legacy recognized the expense associated with the unit grants on the date of grant.
Legacy Reserves Inc. 2018 Omnibus Incentive Plan
On September 19, 2018, the Legacy Inc. 2018 Omnibus Incentive Plan (the "Legacy Inc. LTIP") was approved by the former unitholders of Legacy LP in connection with the Corporate Reorganization for it and its affiliates' employees, consultants and directors. The Legacy Inc. LTIP provides for up to
10,500,000
shares (the "Share Reserve") to be used for awards, and that the Share Reserve will increase proportionately by
10%
of all shares of common stock issued by Legacy Inc. after the effective date of the Legacy Inc. LTIP and before the first anniversary of the effective date. The awards under the Legacy Inc. LTIP may include stock grants, restricted stock, restricted stock units and stock options. As of December 31,
2018
, grants of awards net of forfeitures covering
7,335,379
shares had been made, compromised of
7,302,809
restricted stock units and
32,570
stock awards.
Restricted Stock Units
During the twelve months ended December 31,
2018
, Legacy issued an aggregate
7,302,809
restricted stock units ("RSUs") to both executive and non-executive employees. The RSUs vest generally over a three or four-year period. Compensation expense related to the RSUs was
$4.1 million
for the twelve months ended December 31,
2018
. RSUs are accounted for under the equity method.
A summary of RSU activity for the year ended December 31,
2018
is as follows:
|
|
|
|
|
|
|
|
|
Number of Restricted Stock Units
|
|
Weighted Average Grant Date Fair Value
|
Outstanding at January 1, 2018
|
—
|
|
|
$
|
—
|
|
Granted
|
7,523,720
|
|
|
$
|
4.89
|
|
Expired
|
—
|
|
|
$
|
—
|
|
Forfeited
|
(220,911
|
)
|
|
$
|
5.14
|
|
Outstanding at December 31, 2018
|
7,302,809
|
|
|
$
|
4.88
|
|
As of December 31,
2018
, there was a total of
$31.5 million
of unrecognized compensation expense related to the unvested portion of these RSUs. At December 31,
2018
, this cost was expected to be recognized over a weighted-average period of
3.2
years. Pursuant to the provisions of ASC 718, Legacy's issued shares, as reflected in the accompanying consolidated balance sheet at December 31,
2018
, do not include
7,302,809
shares related to unvested RSUs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Board Shares
On September 25, 2018, Legacy granted and issued
5,030
shares to
four
non-employee directors who serve on the Board of Directors of Legacy in accordance with Legacy's director compensation policy. The value of each share was
$4.97
at the time of issuance.
On October 16, 2018, Legacy granted and issued
12,450
shares to
one
non-employee director who serves on the Board of Directors of Legacy in accordance with Legacy's director compensation policy. The value of each share was
$5.02
at the time of issuance.
(16) Income Taxes
Effective September 20, 2018, pursuant to the Merger Agreement, Legacy Inc. became subject to federal and state income taxes. Prior to consummation of the Corporate Reorganization, Legacy LP was treated as a partnership for federal and state income tax purposes, in which the taxable income or loss was passed through to its unitholders. With the exception of the state of Texas and certain subsidiaries, Legacy LP did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for its operations.
On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) was enacted into law. The provisions of the Tax Act that impact Legacy include, but are not limited to, (1) reducing the U.S. federal corporate income tax rate from
35%
to
21%
, (2) full expensing of certain qualified property acquired after September 27, 2017, (3) limitations on the maximum deduction for net operating loss (NOL) as well as indefinite life carryforwards for tax years beginning after December 31, 2017 and (4) limitations on the maximum deduction for net business interest expense in tax years beginning after December 31, 2017. Legacy has previously recorded all amounts for the income effects of the Tax Act as of December 31, 2017.
The effective income tax rates for the years ended December 31,
2018
,
2017
and
2016
were
6.3%
and
(2.7)%
and
(2.3)%
, respectively. For the year ended December 31,
2018
, our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax, 2023 Convertible Notes issuance, Texas margins tax, and the valuation allowance. For the twelve months ended December 31,
2017
, our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax and Texas margins tax. For the year ended December 31,
2016
, our effective tax rate differed from the statutory rate primarily due to Legacy LP’s income not being subject to U.S. federal income tax and Texas margins tax.
For the years ended December 31,
2018
,
2017
and
2016
we recorded income/(loss) before income taxes of
$46.8 million
,
$(52.5) million
and
$(54.6) million
, respectively. All of Legacy's income is sourced within the United States.
The income tax expense (benefit) consists of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
(In thousands)
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
140
|
|
|
$
|
1,911
|
|
|
$
|
1,183
|
|
State
|
|
(147
|
)
|
|
(52
|
)
|
|
(193
|
)
|
Total current income tax expense (benefit)
|
|
(7
|
)
|
|
1,859
|
|
|
990
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
|
$
|
1,270
|
|
|
$
|
(464
|
)
|
|
$
|
(782
|
)
|
State
|
|
1,705
|
|
|
3
|
|
|
1,021
|
|
Total deferred income tax expense (benefit)
|
|
2,975
|
|
|
(461
|
)
|
|
239
|
|
Total income tax expense
|
|
$
|
2,968
|
|
|
$
|
1,398
|
|
|
$
|
1,229
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Tax at federal statutory rate
|
|
21.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Partnership loss not subject to federal tax
|
|
16.6
|
%
|
|
(36.1
|
)%
|
|
(35.7
|
)%
|
Federal rate change
|
|
—
|
%
|
|
(1.6
|
)%
|
|
—
|
%
|
2023 Convertible Notes issuance
|
|
7.4
|
%
|
|
—
|
%
|
|
—
|
%
|
Valuation allowance adjustment
|
|
(44.1
|
)%
|
|
—
|
%
|
|
—
|
%
|
Texas margins tax
|
|
6.1
|
%
|
|
(1.6
|
)%
|
|
(2.0
|
)%
|
Other
|
|
(0.7
|
)%
|
|
1.6
|
%
|
|
0.4
|
%
|
Effective tax rate
|
|
6.3
|
%
|
|
(2.7
|
)%
|
|
(2.3
|
)%
|
Deferred income tax balances representing the tax effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2018
|
|
2017
|
|
|
(In thousands)
|
Deferred tax assets:
|
|
|
|
|
Oil and natural gas properties
|
|
$
|
91,948
|
|
|
$
|
1,840
|
|
Net operating losses
|
|
12,961
|
|
|
—
|
|
Interest expense
|
|
6,668
|
|
|
—
|
|
Other
|
|
—
|
|
|
1,176
|
|
Total deferred tax assets
|
|
111,577
|
|
|
3,016
|
|
Deferred tax liabilities
|
|
|
|
|
Hedging activities
|
|
(15,934
|
)
|
|
(32
|
)
|
Other
|
|
(1,585
|
)
|
|
(11
|
)
|
Total deferred tax liabilities
|
|
(17,519
|
)
|
|
(43
|
)
|
|
|
|
|
|
Valuation allowance
|
|
(94,058
|
)
|
|
—
|
|
|
|
|
|
|
Net deferred tax assets
|
|
$
|
—
|
|
|
$
|
2,973
|
|
At December 31,
2018
, Legacy had a federal net operating loss carry forward of
$57 million
, which are subject to an
80%
taxable income limitation under the Tax Act. Legacy also has a net interest expense carryover of
$29 million
under Section 163(j) of the Code subject to indefinite carryover. Legacy has state net operating loss carry forwards of approximately
$21 million
which will expire in varying amounts beginning in 2023. Legacy has recorded a full valuation allowance against the federal net operating losses, the state net operating losses, the net interest expense carryover and other deferred tax assets and liabilities because it is probable that these attributes will not be realized.
In assessing the realizability of net deferred tax assets, Legacy's management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax assets. On the basis of this evaluation, as of December 31,
2018
, a full valuation allowance has been recorded as management has determined that it is more likely than not that the net deferred tax asset will not be realized. The full valuation allowance could be adjusted in future periods if objective negative evidence is no longer present and additional weight is given to subjective evidence.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In accordance with the applicable accounting standards, Legacy recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions to identify any material uncertain tax positions, Legacy developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is Legacy’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31,
2018
.
The tax years 2010 through 2018 remain subject to examination by the major tax jurisdictions.
(17) Guarantors
Legacy LP's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. Legacy LP's 2021 Senior Notes were issued in
two
separate private offerings on May 28, 2013 and May 8, 2014.
$250 million
aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining
$300 million
of aggregate principal amount of Legacy's 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. Legacy LP's 2023 Convertible Notes were issued in exchange for portions of the 2020 Senior Notes and 2021 Senior Notes on September 20, 2018. The 2020 Senior Notes, the 2021 Senior Notes and the 2023 Convertible Notes are guaranteed by Legacy LP's
100%
owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services LLC, Legacy Reserves Energy Services LLC, Legacy Marketing LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future
100%
owned subsidiaries that guarantee the Partnership's 2020 Senior Notes, 2021 Senior Notes and the 2023 Convertible Notes, the “Subsidiaries”) as well as Legacy Inc. and the General Partner, as parent guarantors (the "Parent Guarantors"). The Subsidiaries are
100%
owned, directly or indirectly, by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in “—Footnote 2—Debt.” Legacy LP is
100%
owned, directly or indirectly, by the Parent Guarantors and the guarantees by the Parent Guarantors are full and unconditional, except for customary release provisions described in “—Footnote 3—Debt.” Legacy LP has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors and Parent Guarantors.
(18) Subsequent Events
Amendments to Credit Agreement and Term Loan Credit Agreement
On March 21, 2019, we entered into the Twelfth Amendment (the “Twelfth Amendment”) to our Credit Agreement. The Twelfth Amendment provides for, among other things, (i) an extension of the maturity of the Credit Agreement to May 31, 2019, (ii) an increase in the applicable interest rate by
2.25%
, (iii) the payment of a fee equal to
0.35%
of the amount of the current borrowing base under the Credit Agreement, payable on the effective date of the Twelfth Amendment, (iv) the mandatory termination of our derivative contracts three days prior to the maturity of the Credit Agreement, (vi) the reduction in the borrowing base from
$575 million
to
$570 million
, effective May 22, 2019, (vii) the reduction in the maximum consolidated cash balance we can maintain without prepaying the loans to
$15 million
, effective April 1, 2019 and (viii) the payment of a fee equal to
0.15%
of the amount of the current borrowing base under the Credit Agreement, payable on the earliest to occur of (x) May 31, 2019 or (y) an acceleration of the outstanding indebtedness under the Credit Agreement. Additionally, the Amendment waives certain deviations from the requirements of the Credit Agreement, including the delivery of fiscal year 2018 audited financial statements with a “going concern” or like qualification or exception and non-compliance with the current ratio covenant for the fourth quarter of 2018.
On March 21, 2019, we entered into the Seventh Amendment (the “Seventh Amendment”) to our Term Loan Credit Agreement. The Seventh Amendment waives, through May 31, 2019, the requirement of the Term Loan Credit Agreement that the delivery of fiscal year 2018 audited financial statements not include a “going concern” or like qualification or exception. The Seventh Amendment also provides for, among other things, (i) an increase in the applicable interest rate by
2.25%
, (ii) a fee equal to
0.35%
of the aggregate amount of term loans currently outstanding under the Term Loan Credit Agreement, to be paid in kind by increasing the aggregate amount of term loans outstanding as of the effective date of the Seventh Amendment and (iii) a fee equal to
0.15%
of the aggregate amount of term loans currently outstanding under the Term Loan Credit Agreement, to be paid in kind by increasing the aggregate amount of term loans outstanding on the earliest to occur of (x) May 31, 2019 or (y) an acceleration of the outstanding indebtedness under the Term Loan Credit Agreement.
SUPPLEMENTARY INFORMATION
Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities (Unaudited)
Costs incurred by Legacy in oil and natural gas property acquisition and development are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Development costs
|
$
|
229,556
|
|
|
$
|
176,827
|
|
|
$
|
29,499
|
|
Exploration costs
|
—
|
|
|
—
|
|
|
—
|
|
Acquisition costs:
|
|
|
|
|
|
Proved properties
|
7,456
|
|
|
148,776
|
|
|
11,998
|
|
Unproved properties
|
6,007
|
|
|
14,575
|
|
|
24
|
|
Total acquisition, development and exploration costs
|
$
|
243,019
|
|
|
$
|
340,178
|
|
|
$
|
41,521
|
|
Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Please see page F-3 for total capitalized costs and associated accumulated depletion.
SUPPLEMENTARY INFORMATION — (Continued)
Net Proved Oil, NGL and Natural Gas Reserves (Unaudited)
The proved oil, NGL and natural gas reserves of Legacy have been estimated by an independent petroleum engineer, LaRoche, as of December 31,
2018
,
2017
and
2016
. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month unweighted first-day-of-the-month average price for December 31,
2018
,
2017
and
2016
.
An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)(a)
|
|
Natural Gas
(MMcf)(a)
|
|
Total
(MBoe)
|
Total Proved Reserves:
|
|
|
|
|
|
|
|
Balance, December 31, 2015
|
36,143
|
|
|
7,750
|
|
|
721,633
|
|
|
164,166
|
|
Purchases of minerals-in-place
|
13
|
|
|
—
|
|
|
156
|
|
|
39
|
|
Sales of minerals-in-place
|
(1,185
|
)
|
|
(40
|
)
|
|
(5,573
|
)
|
|
(2,154
|
)
|
Revisions from ownership changes
|
(142
|
)
|
|
5
|
|
|
180
|
|
|
(107
|
)
|
Extensions and discoveries
|
4,458
|
|
|
54
|
|
|
6,909
|
|
|
5,664
|
|
Revisions of previous estimates due to price
|
(3,358
|
)
|
|
746
|
|
|
(12,987
|
)
|
|
(4,777
|
)
|
Revisions of previous estimates due to performance
|
548
|
|
|
203
|
|
|
(16,474
|
)
|
|
(1,995
|
)
|
Production
|
(4,019
|
)
|
|
(875
|
)
|
|
(66,824
|
)
|
|
(16,032
|
)
|
Balance, December 31, 2016
|
32,458
|
|
|
7,843
|
|
|
627,020
|
|
|
144,804
|
|
Purchases of minerals-in-place
|
6,363
|
|
|
—
|
|
|
9,971
|
|
|
8,025
|
|
Sales of minerals-in-place
|
(442
|
)
|
|
—
|
|
|
(1,121
|
)
|
|
(629
|
)
|
Revisions from ownership changes
|
998
|
|
|
15
|
|
|
1,751
|
|
|
1,305
|
|
Extensions and discoveries
|
10,219
|
|
|
339
|
|
|
16,647
|
|
|
13,332
|
|
Revisions of previous estimates due to price
|
5,387
|
|
|
672
|
|
|
51,975
|
|
|
14,722
|
|
Revisions of previous estimates due to performance
|
1,195
|
|
|
1,490
|
|
|
72,722
|
|
|
14,807
|
|
Production
|
(5,032
|
)
|
|
(909
|
)
|
|
(62,833
|
)
|
|
(16,413
|
)
|
Balance, December 31, 2017
|
51,146
|
|
|
9,450
|
|
|
716,132
|
|
|
179,953
|
|
Purchases of minerals-in-place
|
68
|
|
|
1
|
|
|
665
|
|
|
180
|
|
Sales of minerals-in-place
|
(1,801
|
)
|
|
(1,975
|
)
|
|
(22,717
|
)
|
|
(7,562
|
)
|
Revisions from ownership changes
|
178
|
|
|
39
|
|
|
522
|
|
|
304
|
|
Revisions from drilling and recompletions
|
12,672
|
|
|
45
|
|
|
22,100
|
|
|
16,400
|
|
Revisions of previous estimates due to price
|
3,079
|
|
|
(276
|
)
|
|
(19,769
|
)
|
|
(492
|
)
|
Revisions of previous estimates due to performance
|
(6,637
|
)
|
|
2,916
|
|
|
(16,756
|
)
|
|
(6,514
|
)
|
Production
|
(6,629
|
)
|
|
(989
|
)
|
|
(58,457
|
)
|
|
(17,361
|
)
|
Balance, December 31, 2018
|
52,076
|
|
|
9,211
|
|
|
621,720
|
|
|
164,908
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
December 31, 2015
|
34,297
|
|
|
7,729
|
|
|
718,094
|
|
|
161,708
|
|
December 31, 2016
|
28,092
|
|
|
7,743
|
|
|
619,959
|
|
|
139,162
|
|
December 31, 2017
|
45,045
|
|
|
9,333
|
|
|
705,679
|
|
|
171,991
|
|
December 31, 2018
|
47,407
|
|
|
9,094
|
|
|
613,284
|
|
|
158,715
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
December 31, 2015
|
1,846
|
|
|
21
|
|
|
3,539
|
|
|
2,457
|
|
December 31, 2016
|
4,366
|
|
|
100
|
|
|
7,061
|
|
|
5,643
|
|
December 31, 2017
|
6,101
|
|
|
117
|
|
|
10,453
|
|
|
7,959
|
|
December 31, 2018
|
4,669
|
|
|
117
|
|
|
8,436
|
|
|
6,195
|
|
____________________
|
|
(a)
|
We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content in those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, Legacy's realized natural gas prices in the Permian Basin are substantially higher than NYMEX Henry Hub natural gas prices due to NGL content.
|
The primary drivers behind the changes to our proved reserves in each of
2016
,
2017
and
2018
are described in more detail below.
SUPPLEMENTARY INFORMATION — (Continued)
2016
:
The decrease in proved reserve quantities for the year ended
December 31, 2016
was due primarily to production of the assets, the decline in average NYMEX-WTI oil and Henry Hub natural gas prices during
2016
which decreased the economic life of our properties and divestitures of low-production, high-cost properties.
2017
:
The increase in proved reserve quantities for the year ended
December 31, 2017
was due primarily to the development of our unproved assets, the increase in average NYMEX-WTI oil and Henry Hub natural gas prices during
2017
which increased the economic life of our properties and the acquisition of producing oil and natural gas properties.
2018
:
The decrease in proved reserve quantities for the year ended
December 31, 2018
was due primarily to production of the assets and sales of oil and natural gas properties partially offset by the development of our unproved assets during
2018
.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)
Summarized in the following table is information for Legacy with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying the 12-month unweighted first-day-of-the-month average price for the years ended December 31,
2018
,
2017
and
2016
. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Future production revenues
|
$
|
5,093,812
|
|
|
$
|
4,657,406
|
|
|
$
|
2,814,259
|
|
Future costs:
|
|
|
|
|
|
Production
|
(2,453,520
|
)
|
|
(2,347,759
|
)
|
|
(1,618,241
|
)
|
Development
|
(190,126
|
)
|
|
(148,936
|
)
|
|
(202,304
|
)
|
Future income tax expense (a)
|
(238,940
|
)
|
|
—
|
|
|
—
|
|
Future net cash flows before income taxes
|
2,211,226
|
|
|
2,160,711
|
|
|
993,714
|
|
10% annual discount for estimated timing of cash flows
|
(1,013,613
|
)
|
|
(988,563
|
)
|
|
(418,088
|
)
|
Standardized measure of discounted net cash flows
|
$
|
1,197,613
|
|
|
$
|
1,172,148
|
|
|
$
|
575,626
|
|
____________________
|
|
(a)
|
For the years ended December 31,
2017
and
2016
, federal income taxes were not deducted from future production revenues in the calculation of standardized measure as each partner was separately taxed on their share of Legacy's taxable income.
|
The standardized measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2018
|
|
2017
|
|
2016
|
Oil (per Bbl) (a)
|
$
|
65.56
|
|
|
$
|
47.79
|
|
|
$
|
39.25
|
|
Natural Gas (per MMBtu) (b)
|
$
|
3.10
|
|
|
$
|
2.98
|
|
|
$
|
2.48
|
|
____________________
|
|
(a)
|
The quoted oil price for all fiscal years is the 12-month unweighted average first-day-of-the-month West Texas Intermediate price, as posted by Plains Marketing, L.P., for each month of
2018
,
2017
and
2016
.
|
|
|
(b)
|
The quoted gas price for all fiscal years is the 12-month unweighted average first-day-of-the-month Henry Hub price, as posted by Platts Gas Daily, for each month of
2018
,
2017
and
2016
.
|
SUPPLEMENTARY INFORMATION — (Continued)
The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
2018
|
|
2017
|
|
2016
|
|
(In thousands)
|
Increase (decrease):
|
|
|
|
|
|
Sales, net of production costs
|
$
|
(325,044
|
)
|
|
$
|
(233,257
|
)
|
|
$
|
(120,757
|
)
|
Net change in sales prices, net of production costs
|
194,100
|
|
|
310,206
|
|
|
(109,125
|
)
|
Changes in estimated future development costs
|
(8,109
|
)
|
|
(591
|
)
|
|
99
|
|
Revisions of previous estimates due to infill drilling,
|
|
|
|
|
|
recompletions and stimulations
|
284,354
|
|
|
135,700
|
|
|
15,632
|
|
Revisions of previous quantity estimates due to performance
|
(81,337
|
)
|
|
89,941
|
|
|
57,188
|
|
Previously estimated development costs incurred
|
43,061
|
|
|
16,328
|
|
|
2,097
|
|
Purchases of minerals-in-place
|
1,315
|
|
|
206,038
|
|
|
294
|
|
Sales of minerals-in-place
|
(43,657
|
)
|
|
(2,861
|
)
|
|
(14,781
|
)
|
Ownership interest changes
|
2,492
|
|
|
14,533
|
|
|
(3,886
|
)
|
Other
|
(776
|
)
|
|
5,534
|
|
|
(9,028
|
)
|
Accretion of discount
|
111,427
|
|
|
54,951
|
|
|
62,952
|
|
Future income tax expense
|
(152,361
|
)
|
|
—
|
|
|
—
|
|
Net increase (decrease)
|
25,465
|
|
|
596,522
|
|
|
(119,315
|
)
|
Standardized measure of discounted future net cash flows:
|
|
|
|
|
|
Beginning of year
|
1,172,148
|
|
|
575,626
|
|
|
694,941
|
|
End of year
|
$
|
1,197,613
|
|
|
$
|
1,172,148
|
|
|
$
|
575,626
|
|
The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
SUPPLEMENTARY INFORMATION — (Continued)
Selected Quarterly Financial Data (Unaudited)
For the three-month periods ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
2018
|
(In thousands, except per share data)
|
Revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
93,411
|
|
|
$
|
99,799
|
|
|
$
|
98,779
|
|
|
$
|
83,455
|
|
Natural gas liquids sales
|
7,396
|
|
|
5,735
|
|
|
7,771
|
|
|
6,848
|
|
Natural gas sales
|
36,672
|
|
|
33,747
|
|
|
38,657
|
|
|
42,591
|
|
Total revenues
|
137,479
|
|
|
139,281
|
|
|
145,207
|
|
|
132,894
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas production
|
47,967
|
|
|
49,431
|
|
|
51,304
|
|
|
51,583
|
|
Production and other taxes
|
7,326
|
|
|
7,658
|
|
|
7,721
|
|
|
6,827
|
|
General and administrative
|
24,090
|
|
|
22,496
|
|
|
17,778
|
|
|
8,675
|
|
Depletion, depreciation, amortization and accretion
|
36,547
|
|
|
38,139
|
|
|
39,588
|
|
|
45,724
|
|
Impairment of long-lived assets
|
—
|
|
|
35,381
|
|
|
18,994
|
|
|
13,603
|
|
(Gain) loss on disposal of assets
|
(20,395
|
)
|
|
(1,145
|
)
|
|
7,368
|
|
|
(9,631
|
)
|
Total expenses
|
95,535
|
|
|
151,960
|
|
|
142,753
|
|
|
116,781
|
|
Operating income (loss)
|
41,944
|
|
|
(12,679
|
)
|
|
2,454
|
|
|
16,113
|
|
Interest income
|
12
|
|
|
3
|
|
|
16
|
|
|
5
|
|
Interest expense
|
(27,368
|
)
|
|
(28,589
|
)
|
|
(29,383
|
)
|
|
(31,668
|
)
|
Gain on extinguishment of debt
|
51,693
|
|
|
—
|
|
|
12,107
|
|
|
2,266
|
|
Equity in income of equity method investee
|
17
|
|
|
3
|
|
|
(30
|
)
|
|
(9
|
)
|
Net gains (losses) on commodity derivatives
|
(1,704
|
)
|
|
(9,315
|
)
|
|
(30,867
|
)
|
|
91,058
|
|
Other
|
275
|
|
|
(2
|
)
|
|
350
|
|
|
99
|
|
Incomes (loss) before income taxes
|
64,869
|
|
|
(50,579
|
)
|
|
(45,353
|
)
|
|
77,864
|
|
Income taxes
|
(487
|
)
|
|
(130
|
)
|
|
(2,499
|
)
|
|
148
|
|
Net income (loss)
|
$
|
64,382
|
|
|
$
|
(50,709
|
)
|
|
$
|
(47,852
|
)
|
|
$
|
78,012
|
|
Net income (loss) per share — basic and diluted
|
$
|
0.62
|
|
|
$
|
(0.49
|
)
|
|
$
|
(0.46
|
)
|
|
$
|
0.73
|
|
Production volumes:
|
|
|
|
|
|
|
|
Oil (MBbl)
|
1,547
|
|
|
1,629
|
|
|
1,739
|
|
|
1,714
|
|
Natural gas liquids (Mgal)
|
9,244
|
|
|
11,332
|
|
|
11,427
|
|
|
9,546
|
|
Natural gas (MMcf)
|
14,280
|
|
|
14,555
|
|
|
15,026
|
|
|
14,596
|
|
Total (MBoe)
|
4,147
|
|
|
4,325
|
|
|
4,515
|
|
|
4,374
|
|
SUPPLEMENTARY INFORMATION — (Continued)
For the three-month periods ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
2017
|
(In thousands, except per share data)
|
Revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
49,142
|
|
|
$
|
46,096
|
|
|
$
|
59,060
|
|
|
$
|
85,150
|
|
Natural gas liquids sales
|
5,050
|
|
|
4,921
|
|
|
6,720
|
|
|
8,105
|
|
Natural gas sales
|
45,355
|
|
|
41,830
|
|
|
41,035
|
|
|
43,837
|
|
Total revenues
|
99,547
|
|
|
92,847
|
|
|
106,815
|
|
|
137,092
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas production
|
51,217
|
|
|
44,802
|
|
|
42,079
|
|
|
45,121
|
|
Production and other taxes
|
4,159
|
|
|
4,145
|
|
|
5,475
|
|
|
6,046
|
|
General and administrative
|
10,552
|
|
|
8,581
|
|
|
10,023
|
|
|
20,216
|
|
Depletion, depreciation, amortization and accretion
|
28,796
|
|
|
27,689
|
|
|
33,715
|
|
|
36,738
|
|
Impairment of long-lived assets
|
8,062
|
|
|
1,821
|
|
|
14,665
|
|
|
12,735
|
|
(Gain) loss on disposal of assets
|
(5,524
|
)
|
|
11,049
|
|
|
(2,034
|
)
|
|
(1,885
|
)
|
Total expenses
|
97,262
|
|
|
98,087
|
|
|
103,923
|
|
|
118,971
|
|
Operating income (loss)
|
2,285
|
|
|
(5,240
|
)
|
|
2,892
|
|
|
18,121
|
|
Interest income
|
1
|
|
|
8
|
|
|
35
|
|
|
20
|
|
Interest expense
|
(20,133
|
)
|
|
(20,614
|
)
|
|
(23,621
|
)
|
|
(24,838
|
)
|
Gain on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity in income of equity method investee
|
11
|
|
|
1
|
|
|
—
|
|
|
5
|
|
Net gains (losses) on commodity derivatives
|
34,669
|
|
|
14,516
|
|
|
(13,309
|
)
|
|
(18,100
|
)
|
Other
|
(40
|
)
|
|
402
|
|
|
403
|
|
|
27
|
|
Income (loss) before income taxes
|
$
|
16,793
|
|
|
$
|
(10,927
|
)
|
|
$
|
(33,600
|
)
|
|
$
|
(24,765
|
)
|
Income taxes
|
(421
|
)
|
|
(150
|
)
|
|
(266
|
)
|
|
(561
|
)
|
Net income (loss)
|
$
|
16,372
|
|
|
$
|
(11,077
|
)
|
|
$
|
(33,866
|
)
|
|
$
|
(25,326
|
)
|
Net income (loss) per share — basic and diluted
|
$
|
0.16
|
|
|
$
|
(0.11
|
)
|
|
$
|
(0.34
|
)
|
|
$
|
(0.25
|
)
|
Production volumes:
|
|
|
|
|
|
|
|
Oil (MBbl)
|
1,037
|
|
|
1,044
|
|
|
1,323
|
|
|
1,628
|
|
Natural gas liquids (Mgal)
|
7,653
|
|
|
8,514
|
|
|
11,375
|
|
|
10,617
|
|
Natural gas (MMcf)
|
15,592
|
|
|
15,604
|
|
|
15,771
|
|
|
15,866
|
|
Total (MBoe)
|
3,818
|
|
|
3,847
|
|
|
4,222
|
|
|
4,525
|
|