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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Legacy Reserves Inc. (MM) | NASDAQ:LGCY | NASDAQ | Common Stock |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 0.0395 | 0.0341 | 0.035 | 0 | 01:00:00 |
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
For the fiscal year ended December 31, 2018
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
For the transition period from to
|
Delaware
|
82-4919553
|
(State or other jurisdiction of
|
(I.R.S. Employer
|
incorporation or organization)
|
Identification No.)
|
|
|
303 W. Wall Street, Suite 1800
|
79701
|
Midland, Texas
|
(Zip Code)
|
(Address of principal executive offices)
|
|
Large accelerated filer
o
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|
Accelerated filer
þ
|
Non-accelerated filer
o
|
|
Smaller reporting company
o
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Emerging growth company
o
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PART I
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ITEM 1.
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ITEM 1A.
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ITEM 1B.
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ITEM 2.
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ITEM 3.
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||
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ITEM 4.
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PART II
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ITEM 5.
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ITEM 6.
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ITEM 7.
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ITEM 7A.
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ITEM 8.
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ITEM 9.
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ITEM 9A.
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ITEM 9B.
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PART III
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ITEM 10.
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ITEM 11.
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ITEM 12.
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ITEM 13.
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ITEM 14.
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PART IV
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ITEM 15.
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||
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ITEM 16.
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•
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our ability to pursue financial, transactional and other strategic alternatives to address our liquidity and capital structure;
|
•
|
the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, debt refinancing or extensions, exchanges or repurchases of debt, issuances of debt or equity securities, access to additional borrowing capacity and our ability to generate sufficient cash flow from operations to fund our capital expenditures and meeting working capital needs;
|
•
|
our ability to comply with, renegotiate or receive waivers of debt covenants under our Credit Agreement (as defined below) and our Term Loan Credit Agreement (as defined below);
|
•
|
our business strategy;
|
•
|
the amount of oil and natural gas we produce;
|
•
|
the price at which we are able to sell our oil and natural gas production;
|
•
|
our ability to identify, acquire, exploit and appropriately finance additional oil and natural gas properties at economically attractive prices;
|
•
|
our ability to replace reserves and increase reserve value;
|
•
|
our drilling locations and our ability to continue our development activities at economically attractive costs;
|
•
|
the level of our lease operating expenses, general and administrative costs and finding and development costs;
|
•
|
the level of our capital expenditures;
|
•
|
our ability to divest non-core assets at economically attractive prices;
|
•
|
our future operating results; and
|
•
|
our plans, objectives, expectations and intentions.
|
ITEM 1.
|
BUSINESS
|
•
|
we had proved reserves of approximately
164.9
MMBoe, of which
63%
were natural gas,
37%
were oil and natural gas liquids (“NGLs”) and
96%
were classified as proved developed producing; and
|
•
|
our proved reserves to production ratio was approximately
9.5
years based on the annualized production volumes for the three months ended
December 31, 2018
.
|
•
|
Legacy, which prior to the Corporate Reorganization, was a wholly owned subsidiary of the General Partner, acquired all of the issued and outstanding limited liability company interests in the General Partner and became the sole member of the General Partner with the General Partner becoming a subsidiary of Legacy; and
|
•
|
Legacy LP merged with Merger Sub, with Legacy LP continuing as the surviving entity and as a subsidiary of Legacy, the limited partner interests of Legacy LP, other than the incentive distribution units in Legacy LP, were exchanged for shares of Legacy’s common stock, par value $0.01 (“common stock”) and the general partner interest remained outstanding.
|
•
|
Deployed
$229.5 million
of development capital expenditures, primarily focused on the drilling and completion of our Permian Basin horizontal development assets;
|
•
|
Increased revenue
27%
, relative to
2017
, to
$554.9 million
;
|
•
|
Increased oil production
32%
relative to
2017
, to
18,162
Bbls/d;
|
•
|
Completed our transition to a corporation and commenced trading as Legacy Reserves Inc.
|
•
|
In March 2019, we extended the term on our Credit Agreement through May 31, 2019.
|
•
|
Prudently deploy capital in development opportunities that maximize value;
|
•
|
Identify, acquire and exploit additional opportunities to broaden our operational footprint and enrich our future growth potential;
|
•
|
Utilize our extensive Permian portfolio of small-tract acreage to increase our drillable footprint;
|
•
|
Maintain efficient operations to minimize production declines, improve lifting costs and well economics;
|
•
|
Rationalize our asset base by regularly reviewing our asset portfolio and divesting non-core assets; and
|
•
|
Maintain capital budget flexibility to preserve liquidity.
|
|
|||||||||||||||||||||
Proved Reserves by Operating Region as of December 31, 2018
|
|||||||||||||||||||||
Operating Regions
|
|
Oil (MBbls)
|
|
Natural
Gas (MMcf)
|
|
NGLs(MBbls)
|
|
Total (MBoe)
|
|
% Liquids
|
|
% PDP
|
|
% Total
|
|||||||
Permian Basin
|
|
44,671
|
|
|
116,879
|
|
|
660
|
|
|
64,811
|
|
|
70
|
%
|
|
90
|
%
|
|
39
|
%
|
East Texas
|
|
103
|
|
|
292,249
|
|
|
211
|
|
|
49,022
|
|
|
1
|
%
|
|
100
|
%
|
|
30
|
%
|
Rocky Mountain
|
|
6,479
|
|
|
206,541
|
|
|
7,257
|
|
|
48,160
|
|
|
29
|
%
|
|
100
|
%
|
|
29
|
%
|
Mid-Continent
|
|
824
|
|
|
6,051
|
|
|
1,083
|
|
|
2,916
|
|
|
65
|
%
|
|
92
|
%
|
|
2
|
%
|
Total
|
|
52,077
|
|
|
621,720
|
|
|
9,211
|
|
|
164,909
|
|
|
37
|
%
|
|
|
|
|
100
|
%
|
|
Gross Locations
|
|
Net Locations
|
|
Net Volume (MBoe)
|
|||
Balance, December 31, 2017
|
40
|
|
|
20.1
|
|
|
7,963
|
|
PUDs converted to PDP by drilling
|
(19
|
)
|
|
(9.5
|
)
|
|
(5,807
|
)
|
PUDs removed due to performance (a)
|
(2
|
)
|
|
(0.3
|
)
|
|
(89
|
)
|
PUDs removed from future drilling schedule (b)
|
(3
|
)
|
|
(1.0
|
)
|
|
(570
|
)
|
Extensions and discoveries (a)
|
16
|
|
|
10.8
|
|
|
4,659
|
|
Other
|
—
|
|
|
0.3
|
|
|
40
|
|
Balance, December 31, 2018
|
32
|
|
|
20.4
|
|
|
6,196
|
|
(a)
|
PUDs removed due to performance or added due to extensions and discoveries are those PUDs removed or added, as applicable, due to new or revised engineering, geologic and economic evaluations such as offset well production data, the drilling of offset wells, new geologic data or changes in projected capital costs or product prices. PUDs are removed or added depending on whether the technical criteria for the proved undeveloped reserve classification is satisfied and, in the case of additions due to performance, whether the well is scheduled to be drilled within five years after initial recognition as proved reserves.
|
(b)
|
These PUD locations were removed from our PUD inventory because of non-consenting working interest owners. Due to their ownership level, their consent is required in order to develop the PUD.
|
|
2018
|
|
2017
|
|
2016
|
Plains Marketing, LP
|
20%
|
|
10%
|
|
6%
|
Rio Energy International Inc
|
13%
|
|
9%
|
|
3%
|
•
|
require the acquisition of various permits before drilling commences;
|
•
|
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;
|
•
|
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
|
•
|
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
|
•
|
the location of wells;
|
•
|
the method of drilling and casing wells;
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
•
|
the plugging and abandoning of wells; and
|
•
|
notice to surface owners and other third parties.
|
ITEM 1A.
|
RISK FACTORS
|
•
|
third parties’ confidence in our ability to develop oil and natural gas properties could erode, which could impact our ability to execute on our business strategy;
|
•
|
it may become more difficult to retain, attract or replace key employees;
|
•
|
employees could be distracted from performance of their duties or more easily attracted to other career opportunities;
|
•
|
we could lose some or a significant portion of our liquidity, either due to stricter credit terms from vendors, or, in the event we undertake a Chapter 11 proceeding and conclude that we need to procure debtor-in-possession financing, an inability to obtain any needed debtor-in-possession financing or to provide adequate protection to certain secured lenders to permit us to access some or all of our cash; and
|
•
|
our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.
|
•
|
the domestic and foreign supply of and demand for oil and natural gas;
|
•
|
market expectations about future prices of oil and natural gas;
|
•
|
the price and quantity of imports of crude oil and natural gas;
|
•
|
overall domestic and global economic conditions;
|
•
|
political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
|
•
|
the willingness and ability of members of the Organization of Petroleum Exporting Countries and other petroleum producing countries to agree to and maintain oil price and production controls;
|
•
|
trading in oil and natural gas derivative contracts;
|
•
|
the level of consumer product demand;
|
•
|
weather conditions and natural disasters;
|
•
|
technological advances affecting energy production and consumption;
|
•
|
domestic and foreign governmental regulations and taxes;
|
•
|
the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;
|
•
|
the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
|
•
|
the price and availability of alternative fuels.
|
•
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;
|
•
|
covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
|
•
|
our access to the capital markets may be limited;
|
•
|
we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
|
•
|
our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
|
•
|
our proved reserves;
|
•
|
the level of oil and natural gas we are able to produce from existing wells;
|
•
|
capital and lending market conditions;
|
•
|
the prices at which our oil and natural gas are sold; and
|
•
|
our ability to identify, acquire and exploit new reserves.
|
•
|
the high cost, shortages or delivery delays of equipment, materials, and services;
|
•
|
unexpected operational events;
|
•
|
adverse weather conditions or events;
|
•
|
facility or equipment malfunctions;
|
•
|
title disputes;
|
•
|
regulatory changes and approvals;
|
•
|
pipeline ruptures or spills;
|
•
|
collapses of wellbore, casing or other tubulars;
|
•
|
unusual or unexpected geological formations;
|
•
|
loss of drilling fluid circulation;
|
•
|
formations with abnormal pressures;
|
•
|
fires;
|
•
|
blowouts, craterings and explosions;
|
•
|
interference from new well stimulation;
|
•
|
offset operations causing irregularities or interruptions in production; and
|
•
|
uncontrollable flows of oil, natural gas or well fluids.
|
•
|
the validity of our assumptions about recoverable reserves, development potential, future production, revenues, capital expenditures, future oil and natural gas prices, operating costs and potential environmental and other liabilities;
|
•
|
an inability to successfully integrate the assets and businesses we acquire;
|
•
|
a decrease in our liquidity by using a portion of our available cash or borrowing capacity under our Credit Agreement and our Term Loan Credit Agreement to finance acquisitions;
|
•
|
a lack of capital could cause the development of any acquisitions to be slower than forecasted;
|
•
|
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
|
•
|
the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
|
•
|
the diversion of management’s attention from other business concerns;
|
•
|
the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges; and
|
•
|
the loss of key purchasers.
|
•
|
sell assets, including equity interests in our restricted subsidiaries;
|
•
|
pay distributions on, redeem or purchase our equity or redeem or purchase our subordinated debt;
|
•
|
make investments;
|
•
|
incur or guarantee additional indebtedness or issue preferred units;
|
•
|
create or incur certain liens;
|
•
|
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
|
•
|
consolidate, merge or transfer all or substantially all of our assets;
|
•
|
engage in transactions with affiliates;
|
•
|
create unrestricted subsidiaries; and
|
•
|
engage in certain business activities.
|
ITEM 1B.
|
UNRESOLVED STAFF COMMENTS
|
ITEM 2.
|
PROPERTIES
|
|
As of December 31, 2018
|
||||||||||||||
|
Proved Reserves
|
|
PV-10 (b)
|
||||||||||||
Field or Region
|
MMBoe
|
|
R/P (a)
|
|
% Oil and NGLs
|
|
Amount
|
|
% of Total
|
||||||
|
|
|
|
|
|
|
($ in Millions)
|
|
|
||||||
Spraberry Field (c)
|
25.6
|
|
|
8.4
|
|
|
72
|
%
|
|
$
|
445.5
|
|
|
33
|
%
|
Lea Field
|
9.4
|
|
|
5.0
|
|
|
74
|
|
|
187.5
|
|
|
14
|
|
|
East Texas (d)
|
48.5
|
|
|
12.1
|
|
|
—
|
|
|
175.9
|
|
|
13
|
|
|
Piceance Basin (e)
|
41.9
|
|
|
10.6
|
|
|
18
|
|
|
108.8
|
|
|
8
|
|
|
Total — Top 4
|
125.4
|
|
|
9.7
|
|
|
27
|
%
|
|
$
|
917.7
|
|
|
68
|
%
|
All others
|
39.5
|
|
|
8.9
|
|
|
71
|
|
|
432.3
|
|
|
32
|
|
|
Total
|
164.9
|
|
|
9.5
|
|
|
37
|
%
|
|
$
|
1,350.0
|
|
|
100
|
%
|
(a)
|
Reserves as of
December 31, 2018
divided by annualized fourth quarter production volumes.
|
(b)
|
PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. The below table provides a reconciliation of the GAAP standardized measure to PV-10 (non-GAAP) at December 31, 2018. As Legacy was a pass-through entity not subject to income taxes in 2017 and 2016, no income taxes were included in the computation of standardized measure for those years.
|
|
|
December 31,
|
||
|
|
2018
|
||
|
|
(In millions)
|
||
Standardized measure of discounted net cash flows
|
|
$
|
1,197,613
|
|
Present value of future income taxes discounted at 10%
|
|
152,361
|
|
|
PV-10
|
|
1,349,974
|
|
(c)
|
As the Spraberry Field contains
25,585
MBoe, or
15.5%
of total proved reserves of
164,895
MBoe, the following table presents the production, by product, for the Spraberry Field for
2018
,
2017
and
2016
.
|
(d)
|
As East Texas contains
48,490
MBoe, or
29.4%
of total proved reserves of
164,895
MBoe, the following table presents the production, by product, for East Texas for
2018
,
2017
and
2016
.
|
|
|
Year Ended December 31,
|
|||||||
|
|
2018
|
|
2017
|
|
2016
|
|||
|
|
(In thousands, except daily production)
|
|||||||
Oil (MBbls)
|
|
10
|
|
|
15
|
|
|
17
|
|
Natural gas liquids (Mgal)
|
|
986
|
|
|
1,139
|
|
|
1,117
|
|
Natural gas (MMcf)
|
|
24,517
|
|
|
27,737
|
|
|
30,315
|
|
Total (Mboe)
|
|
4,120
|
|
|
4,665
|
|
|
5,097
|
|
Average daily production (Boe per day)
|
|
11,288
|
|
|
12,781
|
|
|
13,926
|
|
(e)
|
As the Piceance Basin contains
41,886
MBoe, or
25.4%
of total proved reserves of
164,895
MBoe, the following table presents the production, by product, for the Piceance Basin for
2018
,
2017
and
2016
.
|
|
|
Year Ended December 31,
|
|||||||
|
|
2018
|
|
2017
|
|
2016
|
|||
|
|
(In thousands, except daily production)
|
|||||||
Oil (MBbls)
|
|
38
|
|
|
48
|
|
|
52
|
|
Natural gas liquids (Mgal)
|
|
31,237
|
|
|
22,110
|
|
|
22,288
|
|
Natural gas (MMcf)
|
|
19,387
|
|
|
22,065
|
|
|
24,206
|
|
Total (Mboe)
|
|
4,013
|
|
|
4,252
|
|
|
4,617
|
|
Average daily production (Boe per day)
|
|
10,995
|
|
|
11,649
|
|
|
12,615
|
|
|
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.”
|
(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.
|
|
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.
|
|
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
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.
|
|
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
|
—
|
|
|
—
|
|
|
—
|
|
ITEM 3.
|
LEGAL PROCEEDINGS
|
ITEM 4.
|
MINE SAFETY DISCLOSURES
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
ITEM 6.
|
SELECTED FINANCIAL DATA
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017(a)
|
|
2016
|
|
2015(b)
|
|
2014(c)
|
||||||||||
|
(In thousands, except per share/unit data)
|
||||||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil sales
|
$
|
375,444
|
|
|
$
|
239,448
|
|
|
$
|
152,507
|
|
|
$
|
199,841
|
|
|
$
|
396,774
|
|
Natural gas liquids sales
|
27,750
|
|
|
24,796
|
|
|
15,406
|
|
|
16,645
|
|
|
27,483
|
|
|||||
Natural gas sales
|
151,667
|
|
|
172,057
|
|
|
146,444
|
|
|
122,293
|
|
|
108,042
|
|
|||||
Total revenues
|
554,861
|
|
|
436,301
|
|
|
314,357
|
|
|
338,779
|
|
|
532,299
|
|
|||||
Expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and natural gas production
|
200,285
|
|
|
183,219
|
|
|
179,333
|
|
|
194,491
|
|
|
198,801
|
|
|||||
Production and other taxes
|
29,532
|
|
|
19,825
|
|
|
14,267
|
|
|
16,383
|
|
|
31,534
|
|
|||||
General and administrative
|
73,039
|
|
|
49,372
|
|
|
43,639
|
|
|
46,511
|
|
|
38,980
|
|
|||||
Depletion, depreciation, amortization
|
|
|
|
|
|
|
|
|
|
||||||||||
and accretion
|
159,998
|
|
|
126,938
|
|
|
150,414
|
|
|
177,258
|
|
|
173,686
|
|
|||||
Impairment of long-lived assets
|
67,978
|
|
|
37,283
|
|
|
61,796
|
|
|
633,805
|
|
|
448,714
|
|
|||||
(Gain) loss on disposal of assets
|
(23,803
|
)
|
|
1,606
|
|
|
(50,095
|
)
|
|
(3,972
|
)
|
|
(2,479
|
)
|
|||||
Total expenses
|
507,029
|
|
|
418,243
|
|
|
399,354
|
|
|
1,064,476
|
|
|
889,236
|
|
|||||
Operating income (loss)
|
47,832
|
|
|
18,058
|
|
|
(84,997
|
)
|
|
(725,697
|
)
|
|
(356,937
|
)
|
|||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest income
|
36
|
|
|
64
|
|
|
67
|
|
|
329
|
|
|
873
|
|
|||||
Interest expense
|
(117,008
|
)
|
|
(89,206
|
)
|
|
(79,060
|
)
|
|
(76,891
|
)
|
|
(67,218
|
)
|
|||||
Gain on extinguishment of debt
|
66,066
|
|
|
—
|
|
|
150,802
|
|
|
—
|
|
|
—
|
|
|||||
Equity in income (loss) of equity method investees
|
(19
|
)
|
|
17
|
|
|
—
|
|
|
126
|
|
|
428
|
|
|||||
Net gains (losses) on commodity derivatives
|
49,172
|
|
|
17,776
|
|
|
(41,224
|
)
|
|
98,253
|
|
|
138,092
|
|
|||||
Other
|
722
|
|
|
792
|
|
|
(179
|
)
|
|
841
|
|
|
258
|
|
|||||
Income (loss) before income taxes
|
46,801
|
|
|
(52,499
|
)
|
|
(54,591
|
)
|
|
(703,039
|
)
|
|
(284,504
|
)
|
|||||
Income tax (expense) benefit
|
(2,968
|
)
|
|
(1,398
|
)
|
|
(1,229
|
)
|
|
1,498
|
|
|
859
|
|
|||||
Net loss attributable to stockholders/unitholders
|
$
|
43,833
|
|
|
$
|
(53,897
|
)
|
|
$
|
(55,820
|
)
|
|
$
|
(701,541
|
)
|
|
$
|
(283,645
|
)
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017(a)
|
|
2016
|
|
2015(b)
|
|
2014(c)
|
||||||||||
Income/(Loss) per share (a)
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic and diluted
|
$
|
0.42
|
|
|
$
|
(0.54
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(7.26
|
)
|
|
$
|
(3.23
|
)
|
Distributions paid per unit
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.46
|
|
|
$
|
2.41
|
|
(a)
|
In accordance with ASC 805, income (loss) per share amounts for historical periods have been recomputed to reflect shares issued in the Corporate Reorganization.
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
$
|
175,941
|
|
|
$
|
99,795
|
|
|
$
|
3,296
|
|
|
$
|
2,046
|
|
|
$
|
207,216
|
|
Net cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|||||||||
investing activities
|
$
|
(188,128
|
)
|
|
$
|
(279,236
|
)
|
|
$
|
119,989
|
|
|
$
|
(377,420
|
)
|
|
$
|
(632,414
|
)
|
Net cash provided by (used in)
|
|
|
|
|
|
|
|
|
|
|
|||||||||
financing activities
|
$
|
12,110
|
|
|
$
|
177,718
|
|
|
$
|
(119,130
|
)
|
|
$
|
376,655
|
|
|
$
|
423,339
|
|
Capital expenditures
|
$
|
228,261
|
|
|
$
|
314,491
|
|
|
$
|
41,932
|
|
|
$
|
579,463
|
|
|
$
|
640,414
|
|
|
Historical As of December 31,
|
||||||||||||||||||
|
2018
|
|
2017(a)
|
|
2016
|
|
2015(b)
|
|
2014(c)
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
1,098
|
|
|
$
|
1,246
|
|
|
$
|
2,555
|
|
|
$
|
2,006
|
|
|
$
|
725
|
|
Other current assets
|
149,994
|
|
|
111,358
|
|
|
80,217
|
|
|
127,453
|
|
|
191,529
|
|
|||||
Oil and natural gas properties, net of
|
|
|
|
|
|
|
|
|
|
||||||||||
accumulated depletion, depreciation,
|
|
|
|
|
|
|
|
|
|
||||||||||
amortization and impairment
|
1,314,313
|
|
|
1,353,356
|
|
|
1,181,909
|
|
|
1,408,956
|
|
|
1,639,974
|
|
|||||
Other assets
|
9,526
|
|
|
27,122
|
|
|
35,145
|
|
|
74,705
|
|
|
66,378
|
|
|||||
Total assets
|
$
|
1,474,931
|
|
|
$
|
1,493,082
|
|
|
$
|
1,299,826
|
|
|
$
|
1,613,120
|
|
|
$
|
1,898,606
|
|
Current liabilities
|
$
|
984,650
|
|
|
$
|
144,810
|
|
|
$
|
86,609
|
|
|
$
|
81,093
|
|
|
$
|
97,576
|
|
Long-term debt
|
432,923
|
|
|
1,346,769
|
|
|
1,161,394
|
|
|
1,427,614
|
|
|
938,876
|
|
|||||
Other long-term liabilities
|
249,989
|
|
|
273,190
|
|
|
273,902
|
|
|
284,090
|
|
|
224,949
|
|
|||||
Stockholders'/Partners’ equity(deficit)
|
(192,631
|
)
|
|
(271,687
|
)
|
|
(222,079
|
)
|
|
(179,677
|
)
|
|
637,205
|
|
|||||
Total liabilities and stockholders'/partners’ equity (deficit)
|
$
|
1,474,931
|
|
|
$
|
1,493,082
|
|
|
$
|
1,299,826
|
|
|
$
|
1,613,120
|
|
|
$
|
1,898,606
|
|
(a)
|
Includes the production and operating results of the properties acquired as a part of our assets acquired in conjunction with Acceleration Payment from the closing date on August 1, 2017 through December 31, 2017 and thereafter.
|
(b)
|
Includes Legacy’s purchase of the oil and natural gas properties acquired in the Anadarko Acquisitions as of the closing date of the acquisition on July 31, 2015. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition through December 31, 2015 and thereafter.
|
(c)
|
Includes Legacy’s purchase of the oil and natural gas properties acquired in the Piceance Acquisition as of the closing date of the acquisition on June 4, 2014. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition through December 31, 2014 and thereafter.
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
reposition our balance sheet by evaluating and opportunistically pursuing strategic alternatives to materially reduce our outstanding indebtedness and restructure our near term maturity indebtedness.
|
•
|
minimize production declines and operating costs through efficient operations; and
|
•
|
efficiently develop our horizontal inventory in the Permian Basin to generate strong cash-on-cash investment returns.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017(b)
|
|
2016
|
||||||
|
(In thousands, except per unit data and production)
|
||||||||||
Revenues
|
|
|
|
|
|
||||||
Oil sales
|
$
|
375,444
|
|
|
$
|
239,448
|
|
|
$
|
152,507
|
|
Natural gas liquids sales
|
27,750
|
|
|
24,796
|
|
|
15,406
|
|
|||
Natural gas sales
|
151,667
|
|
|
172,057
|
|
|
146,444
|
|
|||
Total revenues
|
$
|
554,861
|
|
|
$
|
436,301
|
|
|
$
|
314,357
|
|
Expenses:
|
|
|
|
|
|
||||||
Oil and natural gas production
|
$
|
191,345
|
|
|
$
|
173,599
|
|
|
$
|
169,755
|
|
Ad valorem taxes
|
8,940
|
|
|
9,620
|
|
|
9,578
|
|
|||
Total
|
$
|
200,285
|
|
|
$
|
183,219
|
|
|
$
|
179,333
|
|
Production and other taxes
|
$
|
29,532
|
|
|
$
|
19,825
|
|
|
$
|
14,267
|
|
General and administrative, excluding transaction costs and LTIP
|
$
|
39,041
|
|
|
$
|
34,006
|
|
|
$
|
31,196
|
|
Transaction costs
|
5,635
|
|
|
8,769
|
|
|
5,245
|
|
|||
LTIP expense
|
28,362
|
|
|
6,597
|
|
|
7,198
|
|
|||
Total general and administrative
|
$
|
73,038
|
|
|
$
|
49,372
|
|
|
$
|
43,639
|
|
Depletion, depreciation, amortization and accretion
|
$
|
159,998
|
|
|
$
|
126,938
|
|
|
$
|
150,414
|
|
Commodity derivative cash settlements:
|
|
|
|
|
|
||||||
Oil derivative cash settlements (paid)/received
|
(16,845
|
)
|
|
11,840
|
|
|
37,464
|
|
|||
Natural gas derivative cash settlements received
|
5,130
|
|
|
12,316
|
|
|
27,041
|
|
|||
Total commodity derivative cash settlements
|
(11,715
|
)
|
|
24,156
|
|
|
64,505
|
|
|||
Production:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
6,629
|
|
|
5,032
|
|
|
4,019
|
|
|||
Natural gas liquids (MGal)
|
41,549
|
|
|
38,159
|
|
|
36,757
|
|
|||
Natural gas (MMcf)
|
58,457
|
|
|
62,833
|
|
|
66,824
|
|
|||
Total (MBoe)
|
17,361
|
|
|
16,413
|
|
|
16,032
|
|
|||
Average daily production (Boe/d)
|
47,564
|
|
|
44,967
|
|
|
43,803
|
|
|||
Average sales price per unit (excluding commodity derivative cash settlements):
|
|
|
|
|
|
||||||
Oil price (per Bbl)
|
$
|
56.64
|
|
|
$
|
47.59
|
|
|
$
|
37.95
|
|
Natural gas liquids price (per Gal)
|
$
|
0.67
|
|
|
$
|
0.65
|
|
|
$
|
0.42
|
|
Natural gas price (per Mcf)(a)
|
$
|
2.59
|
|
|
$
|
2.74
|
|
|
$
|
2.19
|
|
Combined (per Boe)
|
$
|
31.96
|
|
|
$
|
26.58
|
|
|
$
|
19.61
|
|
Average sales price per unit (including commodity derivative cash settlements):
|
|
|
|
|
|
||||||
Oil price (per Bbl)
|
$
|
54.10
|
|
|
$
|
49.94
|
|
|
$
|
47.27
|
|
Natural gas liquids price (per Gal)
|
$
|
0.67
|
|
|
$
|
0.65
|
|
|
$
|
0.42
|
|
Natural gas price (per Mcf)(a)
|
$
|
2.68
|
|
|
$
|
2.93
|
|
|
$
|
2.60
|
|
Combined (per Boe)
|
$
|
31.29
|
|
|
$
|
28.05
|
|
|
$
|
23.63
|
|
Average WTI oil spot price (per Bbl)
|
$
|
65.23
|
|
|
$
|
50.80
|
|
|
$
|
43.29
|
|
Average Henry Hub natural gas spot price (per MMBtu)
|
$
|
3.15
|
|
|
$
|
2.99
|
|
|
$
|
2.52
|
|
Average unit costs per Boe:
|
|
|
|
|
|
||||||
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, amortization and accretion
|
$
|
9.22
|
|
|
$
|
7.73
|
|
|
$
|
9.38
|
|
(a)
|
We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin and for Legacy as a whole are higher than Henry Hub natural gas index prices due to this NGL content.
|
(b)
|
Includes the production and operating results of the properties acquired as a part of our asset acquisition in conjunction with the Acceleration Payment from the closing date on August 1, 2017 through December 31, 2017 and thereafter.
|
•
|
Interest expense;
|
•
|
(Gain) loss on extinguishment of debt;
|
•
|
Income tax expense (benefit);
|
•
|
Depletion, depreciation, amortization and accretion;
|
•
|
Impairment of long-lived assets;
|
•
|
Loss (gain) on disposal of assets;
|
•
|
Equity in (income) loss of equity method investees;
|
•
|
Share-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;
|
•
|
Minimum payments received in excess of overriding royalty interest earned;
|
•
|
Net (gains) losses on commodity derivatives;
|
•
|
Net cash settlements received (paid) on commodity derivatives; and
|
•
|
Transaction costs.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Net income (loss)
|
$
|
43,833
|
|
|
$
|
(53,897
|
)
|
|
$
|
(55,820
|
)
|
Plus:
|
|
|
|
|
|
||||||
Interest expense
|
117,008
|
|
|
89,206
|
|
|
79,060
|
|
|||
Gain on extinguishment of debt
|
(66,066
|
)
|
|
—
|
|
|
(150,802
|
)
|
|||
Income tax expense (benefit)
|
2,968
|
|
|
1,398
|
|
|
1,229
|
|
|||
Depletion, depreciation, amortization and accretion
|
159,998
|
|
|
126,938
|
|
|
150,414
|
|
|||
Impairment of long-lived assets
|
67,978
|
|
|
37,283
|
|
|
61,796
|
|
|||
Loss (gain) on disposal of assets
|
(23,803
|
)
|
|
1,606
|
|
|
(50,095
|
)
|
|||
Equity income (loss) of equity method investees
|
19
|
|
|
(17
|
)
|
|
—
|
|
|||
Unit-based compensation expense
|
28,362
|
|
|
6,597
|
|
|
7,198
|
|
|||
Minimum payments received in excess of overriding royalty interest earned(a)
|
1,902
|
|
|
1,936
|
|
|
1,659
|
|
|||
Net (gains) losses on commodity derivatives
|
(49,172
|
)
|
|
(17,776
|
)
|
|
41,224
|
|
|||
Net cash settlements received on commodity derivatives
|
(11,715
|
)
|
|
24,156
|
|
|
64,505
|
|
|||
Transaction costs
|
5,636
|
|
|
8,769
|
|
|
5,245
|
|
|||
Adjusted EBITDA
|
$
|
276,948
|
|
|
$
|
226,199
|
|
|
$
|
155,613
|
|
(a)
|
A portion of minimum payments received in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments are recognized in net income.
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Price per Bbl
|
|
Price Range per Bbl
|
||
2019
|
|
3,285,000
|
|
$61.33
|
|
$57.15
|
-
|
$67.65
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Price per Bbl
|
|
Price Range per Bbl
|
||
2019
|
|
2,193,000
|
|
$(3.62)
|
|
$(5.60)
|
-
|
$(1.15)
|
|
|
|
|
Average Long
|
|
Average Short
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Put Price per Bbl
|
|
Call Price per Bbl
|
2019
|
|
1,460,000
|
|
$70.00
|
|
(2.91)
|
|
|
|
|
Average
|
|
Price Range per
|
||
Calendar Year
|
|
Volumes (MMBtu)
|
|
Price per MMBtu
|
|
MMBtu
|
||
2019
|
|
37,175,000
|
|
$3.36
|
|
$3.05
|
-
|
$4.40
|
|
|
|
|
Average
|
|
Price Range per
|
||
Calendar Year
|
|
Volumes (MMBtu)
|
|
Price per MMBtu
|
|
MMBtu
|
||
2019
|
|
3,600,000
|
|
$(0.47)
|
|
$(0.46)
|
-
|
$(0.49)
|
•
|
with respect to ABR loans, the alternate base rate equals the highest of the prime rate, the Federal funds effective rate plus
0.50%
, or the one-month London Interbank Offered Rate (“LIBOR”) plus
1.00%
, plus an applicable margin ranging from and including
1.00%
to
2.00%
per annum, determined by the percentage of the borrowing base then in effect that is utilized, provided, that if the ratio of our first lien debt as of the last day of any fiscal quarter to our EBITDA (as defined in the Credit Agreement) for the four fiscal quarters ending on such day is greater than 3.00 to 1.00, then the applicable margin shall be increased by 0.50% during the next succeeding fiscal quarter, or
|
•
|
with respect to any Eurodollar loans, one-, two-, three- or six-month LIBOR plus an applicable margin ranging from and including
2.00%
to
3.00%
per annum, determined by the percentage of the borrowing base then in effect that is utilized.
|
•
|
incur indebtedness;
|
•
|
enter into certain leases;
|
•
|
grant certain liens;
|
•
|
enter into certain derivatives;
|
•
|
make certain loans, acquisitions, capital expenditures and investments;
|
•
|
make distributions other than from available cash;
|
•
|
merge, consolidate or allow certain material changes in the character of our business;
|
•
|
repurchase Senior Notes or repay second lien term loans;
|
•
|
engage in certain asset dispositions, including a sale of all or substantially all of our assets; or
|
•
|
maintain a consolidated cash balance in excess of $20 million, or, effective April 1, 2019, $15 million, without prepaying the loans in an amount equal to such excess.
|
•
|
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: 2.50 to 1.00;
|
•
|
as of the last day of any fiscal quarter, secured debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination to not be greater than 4.50 to 1.00 beginning with the fiscal quarter ending 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 2.00 to 1.00;
|
•
|
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 1.00 to 1.00, excluding current maturities under the Credit Agreement and non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives;
|
•
|
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 our proved developed producing oil and gas properties (“PDP PV-10”), as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be, beginning with the reserve report to be delivered on July 1, 2017 (giving pro forma effect to material acquisitions or dispositions since the date of such reports), (ii) the net mark to market value of our swap agreements and (iii) our cash and cash equivalents to (b) Secured Debt to not be equal to or less than 1.00 to 1.00 .
|
•
|
failure to pay any principal when due or any reimbursement amount, interest, fees or other amount within certain grace periods;
|
•
|
a representation or warranty is proven to be incorrect when made;
|
•
|
failure to perform or otherwise comply with the covenants or conditions contained in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
|
•
|
default by us on the payment of any other indebtedness in excess of $15.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;
|
•
|
bankruptcy or insolvency events involving us or any of our subsidiaries;
|
•
|
the loan documents cease to be in full force and effect;
|
•
|
our failing to create a valid lien, except in limited circumstances;
|
•
|
a change in control, which will occur upon (a) Legacy Inc. ceasing to (i) be the beneficial owner of 100% of the equity interests of the General Partner, (ii) control the General Partner or (iii) be the beneficial owner of 100% of the limited partner equity interests in Legacy LP; (b) the General Partner ceases to be the sole general partner of Legacy LP; (c) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or greater than 50% of the properties or assets of Legacy LP and its subsidiaries taken as a whole; (d) the adoption of a plan relating to the liquidation or dissolution of Legacy Inc. or Legacy LP; (e) the consummation of any transaction that results in any person becoming the beneficial owner of more than 50% of the aggregate voting power of Legacy Inc.; or (f) the first day on which a majority of the members of the Board are not continuing directors;
|
•
|
the entry of, and failure to pay, one or more adverse judgments in excess of $15.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;
|
•
|
specified ERISA events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.0 million in any year;
|
•
|
the Intercreditor Agreement (as defined below) ceases to be in effect, except to the extent permitted by the terms thereof; and
|
•
|
if an “Event of Default” occurs under the Term Loan Credit Agreement (as defined below).
|
•
|
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 shares; 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.
|
•
|
not permit, as of the last day of the fiscal quarter, the ratio of the sum of (i) PDP PV-10, (ii) the net mark to market value of our swap agreements and (iii) our cash and cash equivalents to Secured Debt to be less than (i) 0.85 to 1.00 through and including the fiscal quarter ended December 31, 2018 and (ii) 1.00 to 1.00 thereafter;
|
•
|
not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, our 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;
|
•
|
We are required to mortgage 95% of the total value of all of its Oil and Gas Properties set forth in the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin; and
|
•
|
require us to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions.
|
•
|
permit the issuance of the 2023 Convertible Notes;
|
•
|
provide that the 2023 Convertible Notes constitute debt that is permitted refinancing of debt;
|
•
|
allow for the payment of a cash conversion incentive in connection with the early cashless conversion of the 2023 Convertible Notes into common shares; 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.
|
Early Conversion Date
|
|
Early Conversion Payment
|
December 1, 2018 through May 31, 2019
|
|
$64.22
|
June 1, 2019 through September 19, 2019
|
|
$24.22
|
|
Obligations Due in Period
|
||||||||||||||||||
Contractual Cash Obligations
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
Thereafter
|
|
Total
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
||||||||||
Revolving credit facility(a)
|
$
|
541,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
541,000
|
|
Interest on revolving credit facility(b)
|
7,362
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,362
|
|
|||||
Second Lien Term Loans
|
338,626
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
338,626
|
|
|||||
Interest on Second Lien Term Loans
|
40,635
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40,635
|
|
|||||
Senior Notes
|
—
|
|
|
208,885
|
|
|
259,382
|
|
|
—
|
|
|
468,267
|
|
|||||
Interest on Senior Notes
|
35,656
|
|
|
48,136
|
|
|
17,735
|
|
|
—
|
|
|
101,527
|
|
|||||
Office lease
|
1,376
|
|
|
1,024
|
|
|
—
|
|
|
—
|
|
|
2,400
|
|
|||||
Total contractual cash obligations
|
$
|
964,655
|
|
|
$
|
258,045
|
|
|
$
|
277,117
|
|
|
$
|
—
|
|
|
$
|
1,499,817
|
|
(a)
|
Represents amounts outstanding under our revolving credit facility as of
December 31, 2018
.
|
(b)
|
Based upon our weighted average interest rate of
5.44%
under our revolving credit facility as of
December 31, 2018
.
|
•
|
it requires assumptions to be made that were uncertain at the time the estimate was made, and
|
•
|
changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
•
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
•
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our board of directors; and
|
•
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or disposition of our assets that could have a material effect on our financial statements.
|
|
/s/ BDO USA, LLP
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
ITEM 11.
|
EXECUTIVE COMPENSATION
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
ITEM 14.
|
PRINCIPAL ACCOUNTING FEES AND SERVICES
|
ITEM 15.
|
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
|
Exhibit
|
|
|
Number
|
|
Description
|
3.1
|
—
|
Amended and Restated Certificate of Incorporation of Legacy Reserves Inc. (filed as Exhibit 3.1 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference).
|
3.2
|
—
|
Second Amended and Restated Bylaws of Legacy Reserves Inc. (filed as Exhibit 3.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference).
|
4.1
|
—
|
Indenture, dated as of December 4, 2012, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (including form of the 8% senior notes due 2020) (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed December 10, 2012, Exhibit 4.1)
|
4.2
|
—
|
First Supplemental Indenture, dated as of August 25, 2015, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 8% Senior Notes due 2020) (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed November 6, 2015, Exhibit 10.2)
|
4.3
|
—
|
Second Supplemental Indenture, dated as of April 2, 2018, by and among Legacy Reserves LP, Legacy Reserves Inc., Legacy Reserves GP, LLC, Legacy Reserves Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 8% Senior Notes due 2020) (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed April 2, 2018, Exhibit 4.1)
|
4.4*
|
—
|
|
4.5
|
—
|
Indenture, dated as of May 28, 2013, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (including form of 6.625% senior notes due 2021) (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed May 31, 2013, Exhibit 4.1)
|
4.6
|
—
|
First Supplemental Indenture, dated as of August 25, 2015, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 6.625% Senior Notes due 2021) (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed November 6, 2015, Exhibit 10.3)
|
4.7
|
—
|
Second Supplemental Indenture, dated as of April 2, 2018, by and among Legacy Reserves LP, Legacy Reserves Inc., Legacy Reserves GP, LLC, Legacy Reserves Finance Corporation, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 6.625% Senior Notes due 2021) (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed April 2, 2018, Exhibit 4.2)
|
4.8*
|
—
|
|
4.9
|
—
|
Indenture dated September 20, 2018, between Legacy Reserves LP, Legacy Reserves Finance Corporation, the guarantors party thereto and Wilmington Trust, National Association (including form of 8% convertible senior notes due 2023) (filed as Exhibit 4.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
4.10*
|
—
|
|
10.1
|
—
|
Third Amended and Restated Credit Agreement, among Legacy Reserves LP, as Borrower, 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, dated as of April 1, 2014 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed April 2, 2014, Exhibit 10.1)
|
10.2
|
—
|
First Amendment to Third Amended and Restated Credit Agreement, dated April 17, 2014, by and between Legacy Reserves LP, Wells Fargo Bank, National Association, as administrative agent and certain other financial institutions party thereto as lenders (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed October 31, 2014, Exhibit 10.1)
|
Exhibit
|
|
|
Number
|
|
Description
|
10.3
|
—
|
Second Amendment to Third Amended and Restated Credit Agreement, dated May 22, 2014, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed May 28, 2014, Exhibit 10.1)
|
10.4
|
—
|
Third Amendment to Third Amended and Restated Credit Agreement, dated December 29, 2014, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.11)
|
10.5
|
—
|
Fourth Amendment to Third Amended and Restated Credit Agreement, dated February 23, 2015, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.12)
|
10.6
|
—
|
Fifth Amendment to Third Amended and Restated Credit Agreement, dated August 5, 2015, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed August 7, 2015, Exhibit 10.2)
|
10.7
|
—
|
Sixth Amendment to Third Amended and Restated Credit Agreement, dated November 13, 2015, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 26, 2016, Exhibit 10.14)
|
10.8
|
—
|
Seventh Amendment to Third Amended and Restated Credit Agreement, dated February 19, 2016, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on February 24, 2016, Exhibit 10.1)
|
10.9
|
—
|
Eighth Amendment to Third Amended and Restated Credit Agreement, dated October 25, 2016, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed October 28, 2016, Exhibit 10.2)
|
10.1
|
—
|
Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of March 23, 2018, by and among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed March 26, 2018, Exhibit 10.1)
|
10.11
|
—
|
Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of September 14, 2018, by and among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 333-224182) on September 14, 2018, and incorporated herein by reference).
|
10.12
|
—
|
Eleventh Amendment dated September 20, 2018 to the Third Amended and Restated Credit Agreement, dated as of April 1, 2014 among Legacy Reserves Inc., the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent and the lenders signatory thereto (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.13
|
—
|
Limited Waiver and Letter Agreement, dated October 31, 2018, by and among Legacy Reserves LP, Wells Fargo Bank, National Association and the other parties thereto (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference)
|
10.14
|
—
|
Term Loan Credit Agreement, among Legacy Reserves LP, as Borrower, Cortland Capital Market Services LLC, as Administrative Agent and the lenders party thereto, dated as of October 25, 2016 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed October 28, 2016, Exhibit 10.1)
|
Exhibit
|
|
|
Number
|
|
Description
|
10.15
|
—
|
First Amendment and Waiver to Term Loan Credit Agreement, among Legacy Reserves LP, as Borrower, Cortland Capital Market Services LLC, as Administrative Agent, and the lenders party thereto, dated as of July 31, 2017 (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q (File No. 001-33249) filed on August 4, 2017, Exhibit 10.1)
|
10.16
|
—
|
Second Amendment to Term Loan Credit Agreement, among Legacy Reserves LP, as Borrower, Cortland Capital Market Services LLC, as Administrative Agent, and the lenders party thereto, dated as of October 30, 2017 (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q (File No. 001-33249) filed on November 1, 2017, Exhibit 10.1)
|
10.17
|
—
|
Third Amendment to Term Loan Credit Agreement, among Legacy Reserves LP, as Borrower, Cortland Capital Market Services LLC, as Administrative Agent, and the lenders party thereto, dated as of December 31, 2017 (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed on January 5, 2018, Exhibit 10.1)
|
10.18
|
—
|
Fourth Amendment to Term Loan Credit Agreement, dated as of March 23, 2018, by and among Legacy Reserves LP, Cortland Capital Market Services LLC and the lenders party thereto (Incorporated by reference to Legacy Reserves LP’s Current Report on Form 8-K filed March 26, 2018, Exhibit 10.2)
|
10.19
|
—
|
Fifth Amendment to Term Loan Credit Agreement, dated as of September 14, 2018, by and among Legacy Reserves LP, Cortland Capital Market Services LLC and the lenders party thereto (filed as Exhibit 10.2 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 333-224182) on September 14, 2018, and incorporated herein by reference)
|
10.20
|
—
|
Sixth Amendment dated September 20, 2018 to the Term Loan Credit Agreement, dated as of October 30, 2017, among Legacy Reserves Inc., the guarantors named therein, Cortland Capital Market Services LLC, as administrative agent, and the lenders party thereto (filed as Exhibit 10.2 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.21†
|
—
|
Legacy Reserves Inc. 2018 Omnibus Incentive Plan (filed as Exhibit 10.7 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.22†
|
—
|
Form of Legacy Reserves Inc. Omnibus Incentive Plan Restricted Stock Unit Award Agreement (filed as Exhibit 10.21 to Legacy Reserves Inc.’s Registration Statement on Form S-4 (File No. 333-224182) on May 14, 2018, and incorporated herein by reference)
|
10.23†
|
—
|
Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Paul T. Horne (filed as Exhibit 10.1 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.24†
|
—
|
Amended and Restated Employment Agreement effective, October 31, 2018, between James Daniel Westcott and Legacy Reserves Services LLC and Legacy Reserves Inc. (filed as Exhibit 10.3 to Legacy Reserves Inc.’s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference)
|
10.25†
|
—
|
Amended and Restated Employment Agreement effective, October 31, 2018, between Kyle Hammond and Legacy Reserves Services LLC and Legacy Reserves Inc. (filed as Exhibit 10.4 to Legacy Reserves Inc.’s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference)
|
10.26†
|
—
|
Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Micah C. Foster (filed as Exhibit 10.6 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.27†
|
—
|
Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Kyle A. McGraw (filed as Exhibit 10.4 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.28†
|
—
|
Employment Agreement dated September 20, 2018, between Legacy Reserves Inc., Legacy Reserves Services, Inc. and Dan G. LeRoy (filed as Exhibit 10.5 to Legacy Reserves Inc.’s Current Report on Form 8-K12B (File No. 001-38668) on September 21, 2018, and incorporated herein by reference)
|
10.29†*
|
—
|
|
10.30†*
|
—
|
Exhibit
|
|
|
Number
|
|
Description
|
10.31†
|
—
|
Employment Agreement dated as of February 7, 2019, between Robert L. Norris, Legacy Reserves Services LLC and Legacy Reserves Inc.
|
10.32†
|
—
|
Restricted Stock Unit Award Agreement, dated February 19, 2019, between Robert L. Norris and Legacy Reserves Inc.
|
10.33†
|
—
|
Letter Agreement effective, October 31, 2018, between Paul Horne and Legacy Reserves Services LLC and Legacy Reserves Inc. (filed as Exhibit 10.1 to Legacy Reserves Inc.’s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference)
|
10.34†
|
—
|
Letter Agreement effective, October 31, 2018, between Dan LeRoy and Legacy Reserves Services LLC and Legacy Reserves Inc. (filed as Exhibit 10.5 to Legacy Reserves Inc.’s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference)
|
10.35†
|
—
|
Letter Agreement effective, October 31, 2018, between Kyle McGraw and Legacy Reserves Services LLC and Legacy Reserves Inc. (filed as Exhibit 10.6 to Legacy Reserves Inc.’s Current Report on Form 8-K (File No. 001-38668) on October 31, 2018, and incorporated herein by reference)
|
10.36†
|
—
|
Amended and Restated Legacy Reserves LP Long-Term Incentive Plan effective as of August 17, 2007 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed August 23, 2007, Exhibit 10.1)
|
10.37†
|
—
|
Amendment No. 1 to the Amended and Restated Legacy Reserves LP Long-Term Incentive Plan, dated as of June 12, 2015. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 12, 2015, Exhibit 10.1)
|
10.38†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Restricted Unit Grant Agreement (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 10.6)
|
10.39†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Unit Option Grant Agreement (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit 10.7)
|
10.40†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Unit Grant Agreement (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit 10.8)
|
10.41†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Objective) (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 21, 2014, Exhibit 10.25)
|
10.42†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Subjective) (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 21, 2014, Exhibit 10.26)
|
10.43†
|
—
|
Form of Grant of Phantom Units Under Objective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.1)
|
10.44†
|
—
|
Form of Grant of Phantom Units (Cash) Under Subjective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.2)
|
10.45†
|
—
|
Form of Grant of Phantom Units (Units) Under Subjective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.3)
|
10.46†
|
—
|
Form of Retention Bonus Agreement (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.4)
|
10.47†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Units) Under Subjective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed on February 22, 2017, Exhibit 10.1)
|
10.48†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Cash) Under Subjective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed on February 22, 2017, Exhibit 10.2)
|
Exhibit
|
|
|
Number
|
|
Description
|
10.49†
|
—
|
Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units Under Objective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed on February 22, 2017, Exhibit 10.3)
|
10.50†
|
—
|
Form of Retention Bonus Agreement (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed on February 22, 2017, Exhibit 10.4)
|
10.51†
|
—
|
Form of Amendment to Grant of Phantom Units Agreement (filed as Exhibit 10.1 to Legacy Reserves Inc.'s Current Report on Form 8-K (File No. 333-224182) on September 18, 2018, and incorporated herein by reference)
|
10.52†
|
—
|
Form of Letter Agreement regarding settlement of phantom units under Legacy Reserves LP Long-Term Incentive Plan (filed as Exhibit 10.1 to Legacy Reserves Inc.’s Current Report on Form 8-K (File No. 001-38668) on December 21, 2018, and incorporated herein by reference)
|
10.53*
|
—
|
|
10.54*
|
—
|
|
21.1*
|
—
|
|
23.1*
|
—
|
|
23.2*
|
—
|
|
24.1*
|
—
|
Power of Attorney (included on the Signature pages of this annual report on Form 10-K)
|
31.1*
|
—
|
|
31.2*
|
—
|
|
32.1*
|
—
|
|
99.1*
|
—
|
|
101.INS*
|
—
|
XBRL Instance Document
|
101.SCH*
|
—
|
XBRL Taxonomy Extension Schema Document
|
101.DEF*
|
—
|
XBRL Taxonomy Extension Definition Linkbase Document
|
101.PRE*
|
—
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
101.CAL*
|
—
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
101.LAB*
|
—
|
XBRL Taxonomy Extension Label Linkbase Document
|
*
|
|
Filed herewith
|
†
|
|
Management contract or compensatory plan or arrangement
|
ITEM 16.
|
FORM 10-K SUMMARY
|
|
LEGACY RESERVES INC.
|
||
|
|
|
|
|
|
|
|
|
By:
|
/
S
/ ROBERT L. NORRIS
|
|
|
|
Name:
|
Rober L. Norris
|
|
|
Title:
|
Chief Financial Officer (Principal Financial Officer)
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
/
S
/ J
AMES
D. W
ESTCOTT
|
|
Director and Chief Executive Officer
|
|
March 22, 2019
|
James D. Westcott
|
|
(Principal Executive Officer)
|
|
|
/
S
/ R
OBERT
L. N
ORRIS
|
|
Chief Financial Officer
|
|
March 22, 2019
|
Robert L. Norris
|
|
(Principal Financial Officer)
|
|
|
/
S
/ M
ICAH
C. F
OSTER
|
|
Chief Accounting Officer and Controller
|
|
March 22, 2019
|
Micah C. Foster
|
|
(Principal Accounting Officer)
|
|
|
/
S
/ P
AUL
T. H
ORNE
|
|
Chairman of the Board
|
|
March 22, 2019
|
Paul T. Horne
|
|
|
|
|
/
S
/ W
ILLIAM
R. G
RANBERRY
|
|
Director
|
|
March 22, 2019
|
William R. Granberry
|
|
|
|
|
/
S
/ G. L
ARRY
L
AWRENCE
|
|
Director
|
|
March 22, 2019
|
G. Larry Lawrence
|
|
|
|
|
/
S
/ K
YLE
D. V
ANN
|
|
Director
|
|
March 22, 2019
|
Kyle D. Vann
|
|
|
|
|
/S/
D
OUGLAS
W.
Y
ORK
|
|
Director
|
|
March 22, 2019
|
Douglas W. York
|
|
|
|
|
|
Page
|
Report of Independent Registered Public Accounting Firm
|
|
Consolidated Financial Statements:
|
|
Consolidated Balance Sheets — December 31, 2018 and 2017
|
|
Consolidated Statements of Operations — Years Ended December 31, 2018, 2017 and 2016
|
|
Consolidated Statements of Stockholders’ Equity — Years Ended December 31, 2018, 2017 and 2016
|
|
Consolidated Statements of Cash Flows — Years Ended December 31, 2018, 2017 and 2016
|
|
Notes to Consolidated Financial Statements
|
|
Unaudited Supplementary Information
|
/s/ BDO USA, LLP
|
|
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
ASSETS
|
|||||||
Current assets:
|
|
|
|
||||
Cash
|
$
|
1,098
|
|
|
$
|
1,246
|
|
Accounts receivable, net:
|
|
|
|
||||
Oil and natural gas
|
56,615
|
|
|
62,755
|
|
||
Joint interest owners
|
15,370
|
|
|
27,422
|
|
||
Fair value of derivatives (Notes 10 and 11)
|
66,662
|
|
|
13,424
|
|
||
Prepaid expenses and other current assets
|
11,347
|
|
|
7,757
|
|
||
Total current assets
|
151,092
|
|
|
112,604
|
|
||
Oil and natural gas properties, at cost:
|
|
|
|
||||
Proved oil and natural gas properties using the successful efforts method of accounting
|
3,471,456
|
|
|
3,529,971
|
|
||
Unproved properties
|
19,863
|
|
|
28,023
|
|
||
Accumulated depletion, depreciation, amortization and impairment
|
(2,177,006
|
)
|
|
(2,204,638
|
)
|
||
Total oil and natural gas properties, net
|
1,314,313
|
|
|
1,353,356
|
|
||
Other property and equipment, net of accumulated depreciation and amortization of $12,323 and $11,467, respectively
|
2,456
|
|
|
2,961
|
|
||
Operating rights, net of amortization of $6,123 and $5,765, respectively
|
894
|
|
|
1,251
|
|
||
Fair value of derivatives (Notes 10 and 11)
|
3,135
|
|
|
14,099
|
|
||
Other assets
|
3,041
|
|
|
8,811
|
|
||
Total assets
|
$
|
1,474,931
|
|
|
$
|
1,493,082
|
|
LIABILITIES AND STOCKHOLDERS' DEFICIT/PARTNERS’ DEFICIT
|
|||||||
Current liabilities:
|
|
|
|
||||
Current debt, net (Note 3)
|
$
|
856,646
|
|
|
$
|
—
|
|
Accounts payable
|
11,227
|
|
|
13,093
|
|
||
Accrued oil and natural gas liabilities (Note 1)
|
98,886
|
|
|
81,318
|
|
||
Fair value of derivatives (Notes 10 and 11)
|
—
|
|
|
18,013
|
|
||
Asset retirement obligation (Note 13)
|
3,938
|
|
|
3,214
|
|
||
Other (Notes 10 and 15)
|
13,953
|
|
|
29,172
|
|
||
Total current liabilities
|
984,650
|
|
|
144,810
|
|
||
Long-term debt (Note 3)
|
432,923
|
|
|
1,346,769
|
|
||
Asset retirement obligation (Note 13)
|
248,796
|
|
|
271,472
|
|
||
Fair value of derivatives (Notes 10 and 11)
|
550
|
|
|
1,075
|
|
||
Other long-term liabilities
|
643
|
|
|
643
|
|
||
Total liabilities
|
1,667,562
|
|
|
1,764,769
|
|
||
Commitments and contingencies (Note 8)
|
|
|
|
|
|
||
Stockholders'/Partners’ equity (deficit):
|
|
|
|
||||
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2017
|
—
|
|
|
55,192
|
|
||
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2017
|
—
|
|
|
174,261
|
|
||
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2017
|
—
|
|
|
30,814
|
|
||
Limited partners' deficit - 72,594,620 units issued and outstanding at December 31, 2017
|
—
|
|
|
(531,794
|
)
|
||
General partner’s deficit (approximately 0.02%)
|
—
|
|
|
(160
|
)
|
||
Common stock, $0.01 par value; 945,000,000 shares authorized, 109,442,278 shares outstanding at December 31, 2018
|
1,094
|
|
|
—
|
|
||
Additional paid-in capital
|
24,752
|
|
|
—
|
|
||
Accumulated deficit
|
(218,477
|
)
|
|
—
|
|
||
Total stockholders’/partners' deficit
|
(192,631
|
)
|
|
(271,687
|
)
|
||
Total liabilities and stockholders'/partners’ deficit
|
$
|
1,474,931
|
|
|
$
|
1,493,082
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands, except per share data)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
375,444
|
|
|
$
|
239,448
|
|
|
$
|
152,507
|
|
Natural gas liquids (NGL) sales
|
27,750
|
|
|
24,796
|
|
|
15,406
|
|
|||
Natural gas sales
|
151,667
|
|
|
172,057
|
|
|
146,444
|
|
|||
Total revenues
|
554,861
|
|
|
436,301
|
|
|
314,357
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Oil and natural gas production
|
200,285
|
|
|
183,219
|
|
|
179,333
|
|
|||
Production and other taxes
|
29,532
|
|
|
19,825
|
|
|
14,267
|
|
|||
General and administrative
|
73,039
|
|
|
49,372
|
|
|
43,639
|
|
|||
Depletion, depreciation, amortization and accretion
|
159,998
|
|
|
126,938
|
|
|
150,414
|
|
|||
Impairment of long-lived assets
|
67,978
|
|
|
37,283
|
|
|
61,796
|
|
|||
Loss (gain) on disposal of assets
|
(23,803
|
)
|
|
1,606
|
|
|
(50,095
|
)
|
|||
Total expenses
|
507,029
|
|
|
418,243
|
|
|
399,354
|
|
|||
Operating income (loss)
|
47,832
|
|
|
18,058
|
|
|
(84,997
|
)
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest income
|
36
|
|
|
64
|
|
|
67
|
|
|||
Interest expense (Notes 3, 10 and 11)
|
(117,008
|
)
|
|
(89,206
|
)
|
|
(79,060
|
)
|
|||
Gain on extinguishment of debt
|
66,066
|
|
|
—
|
|
|
150,802
|
|
|||
Equity in income of equity method investees
|
(19
|
)
|
|
17
|
|
|
—
|
|
|||
Net gains (losses) on commodity derivatives (Notes 10 and 11)
|
49,172
|
|
|
17,776
|
|
|
(41,224
|
)
|
|||
Other
|
722
|
|
|
792
|
|
|
(179
|
)
|
|||
Income (loss) before income taxes
|
46,801
|
|
|
(52,499
|
)
|
|
(54,591
|
)
|
|||
Income tax expense
|
(2,968
|
)
|
|
(1,398
|
)
|
|
(1,229
|
)
|
|||
Net Income (loss)
|
$
|
43,833
|
|
|
$
|
(53,897
|
)
|
|
$
|
(55,820
|
)
|
|
|
|
|
|
|
||||||
Income (loss) per share — basic and diluted (Note 14)
|
$
|
0.42
|
|
|
$
|
(0.54
|
)
|
|
$
|
(0.57
|
)
|
Weighted average number of shares used in
|
|
|
|
|
|
||||||
computing loss per share —
|
|
|
|
|
|
||||||
Basic and Diluted
|
105,087
|
|
|
100,049
|
|
|
98,249
|
|
|
|
Series A Preferred Equity
|
|
Series B Preferred Equity
|
|
Incentive Distribution Equity
|
|
Unitholders' Equity (Deficit)
|
|
Stockholders' Deficit
|
|||||||||||||||||||||||||||||||||||||||||
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Limited Partner Units
|
|
Limited Partner Amount
|
|
General Partner Amount
|
|
Shares
|
|
Par Value
|
|
APIC
|
|
Acc. Deficit
|
|
Total Deficit
|
|||||||||||||||||||||||
|
|
(In thousands)
|
|||||||||||||||||||||||||||||||||||||||||||||||||
Balance, December 31, 2015
|
|
2,300
|
|
|
$
|
55,192
|
|
|
7,200
|
|
|
$
|
174,261
|
|
|
100
|
|
|
$
|
30,814
|
|
|
68,950
|
|
|
$
|
(439,811
|
)
|
|
$
|
(133
|
)
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Units issued to Legacy Board of Directors for services
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237
|
|
|
614
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,252
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Vesting of restricted and phantom units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Units issued in exchange for retirement of debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,719
|
|
|
6,607
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Distributions to unitholders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
(55,807
|
)
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Balance, December 31, 2016
|
|
2,300
|
|
|
$
|
55,192
|
|
|
7,200
|
|
|
$
|
174,261
|
|
|
100
|
|
|
$
|
30,814
|
|
|
72,056
|
|
|
$
|
(482,200
|
)
|
|
$
|
(146
|
)
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Units issued to Legacy Board of Directors for services
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
287
|
|
|
586
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,703
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Vesting of restricted and phantom units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
252
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(53,883
|
)
|
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Balance, December 31, 2017
|
|
2,300
|
|
|
$
|
55,192
|
|
|
7,200
|
|
|
$
|
174,261
|
|
|
100
|
|
|
$
|
30,814
|
|
|
72,595
|
|
|
$
|
(531,794
|
)
|
|
$
|
(160
|
)
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Units issued to Legacy Board of Directors for services
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
522
|
|
|
—
|
|
|
33
|
|
|
—
|
|
|
162
|
|
|
—
|
|
|
162
|
|
|||||||||
Unit-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,753
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,108
|
|
|
—
|
|
|
4,108
|
|
|||||||||
Vesting of restricted and phantom units
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
339
|
|
|
—
|
|
|
—
|
|
|
1,550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Units issued in exchange for Standstill Fee
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,800
|
|
|
5,928
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Debt exchange
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,422
|
|
|
34
|
|
|
23,815
|
|
|
—
|
|
|
23,849
|
|
|||||||||
Corporate Reorganization
|
|
(2,300
|
)
|
|
(55,192
|
)
|
|
(7,200
|
)
|
|
(174,261
|
)
|
|
(100
|
)
|
|
(30,814
|
)
|
|
(76,794
|
)
|
|
521,591
|
|
|
160
|
|
|
104,437
|
|
|
1,060
|
|
|
(3,333
|
)
|
|
(262,310
|
)
|
|
(264,583
|
)
|
|||||||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,833
|
|
|
43,833
|
|
|||||||||
Balance, December 31, 2018
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
109,442
|
|
|
$
|
1,094
|
|
|
$
|
24,752
|
|
|
$
|
(218,477
|
)
|
|
$
|
(192,631
|
)
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
43,833
|
|
|
$
|
(53,897
|
)
|
|
$
|
(55,820
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
||||||
Depletion, depreciation, amortization and accretion
|
159,998
|
|
|
126,938
|
|
|
150,414
|
|
|||
Amortization of debt discount and issuance costs
|
20,604
|
|
|
7,657
|
|
|
10,319
|
|
|||
Gain on extinguishment of debt
|
(66,066
|
)
|
|
—
|
|
|
(150,802
|
)
|
|||
Impairment of long-lived assets
|
67,978
|
|
|
37,283
|
|
|
61,796
|
|
|||
(Gain) loss on derivatives
|
(49,099
|
)
|
|
(19,711
|
)
|
|
40,679
|
|
|||
Equity in income of equity method investees
|
19
|
|
|
(17
|
)
|
|
—
|
|
|||
Unit-based compensation
|
6,619
|
|
|
6,011
|
|
|
7,035
|
|
|||
Loss (gain) on disposal of assets
|
(23,803
|
)
|
|
1,606
|
|
|
(50,095
|
)
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, oil and natural gas
|
6,140
|
|
|
(19,563
|
)
|
|
(9,248
|
)
|
|||
(Increase) decrease in accounts receivable, joint interest owners
|
12,039
|
|
|
(4,006
|
)
|
|
1,964
|
|
|||
Decrease in accounts receivable, other
|
12
|
|
|
—
|
|
|
84
|
|
|||
(Increase) decrease in other assets
|
2,157
|
|
|
3
|
|
|
2,666
|
|
|||
Increase (decrease) in accounts payable
|
(1,865
|
)
|
|
4,001
|
|
|
(4,489
|
)
|
|||
Increase (decrease) in accrued oil and natural gas liabilities
|
9,540
|
|
|
1,891
|
|
|
2,675
|
|
|||
Increase (decrease) in other liabilities
|
(12,165
|
)
|
|
11,599
|
|
|
(3,882
|
)
|
|||
Total adjustments
|
132,108
|
|
|
153,692
|
|
|
59,116
|
|
|||
Net cash provided by (used in) operating activities
|
175,941
|
|
|
99,795
|
|
|
3,296
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Investment in oil and natural gas properties
|
(227,855
|
)
|
|
(313,898
|
)
|
|
(41,496
|
)
|
|||
Proceeds from sale of assets
|
54,968
|
|
|
11,099
|
|
|
97,416
|
|
|||
Investment in other equipment
|
(406
|
)
|
|
(593
|
)
|
|
(436
|
)
|
|||
Corporate Reorganization
|
(3,120
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash settlements on commodity derivatives
|
(11,715
|
)
|
|
24,156
|
|
|
64,505
|
|
|||
Net cash (used in) provided by investing activities
|
(188,128
|
)
|
|
(279,236
|
)
|
|
119,989
|
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from long-term debt
|
659,626
|
|
|
538,000
|
|
|
266,000
|
|
|||
Payments of long-term debt
|
(619,384
|
)
|
|
(357,000
|
)
|
|
(376,402
|
)
|
|||
Payments of debt issuance costs
|
(28,132
|
)
|
|
(3,282
|
)
|
|
(8,728
|
)
|
|||
Net cash provided by (used in) financing activities
|
12,110
|
|
|
177,718
|
|
|
(119,130
|
)
|
|||
Net (decrease) increase in cash
|
(77
|
)
|
|
(1,723
|
)
|
|
4,155
|
|
|||
Cash and restricted cash, beginning of period (1)
|
4,438
|
|
|
6,161
|
|
|
2,006
|
|
|||
Cash and restricted cash, end of period (1)
|
$
|
4,361
|
|
|
$
|
4,438
|
|
|
$
|
6,161
|
|
Non-Cash Investing and Financing Activities:
|
|
|
|
|
|
||||||
Asset retirement obligation costs and liabilities
|
$
|
65
|
|
|
$
|
39
|
|
|
$
|
1
|
|
Asset retirement obligations associated with property acquisitions
|
$
|
226
|
|
|
$
|
62
|
|
|
$
|
24
|
|
Asset retirement obligations associated with properties sold
|
$
|
(27,673
|
)
|
|
$
|
(8,464
|
)
|
|
$
|
(24,605
|
)
|
Debt exchange
|
$
|
23,849
|
|
|
$
|
—
|
|
|
$
|
6,607
|
|
Change in accrued capital expenditures
|
$
|
8,029
|
|
|
$
|
26,179
|
|
|
$
|
—
|
|
Units issued in exchange for Standstill Agreement
|
$
|
5,928
|
|
|
|
|
|
•
|
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.
|
|
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
|
|
|
|
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
|
|
•
|
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
.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
Early Conversion Date
|
|
Early Conversion Payment
|
December 1, 2018 through May 31, 2019
|
|
$64.22
|
June 1, 2019 through September 19, 2019
|
|
$24.22
|
(4)
|
Impact of ASC 606 Adoption
|
|
|
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
|
|
|
$
|
—
|
|
(5)
|
Revenue from Contracts with Customers
|
|
|
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
|
|
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.
|
|
|
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
|
|
|
|
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
|
|
|
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.
|
|
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
|
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Price per Bbl
|
|
Price Range per Bbl
|
||
2019
|
|
3,285,000
|
|
$61.33
|
|
$57.15
|
-
|
$67.65
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Price per Bbl
|
|
Price Range per Bbl
|
||
2019
|
|
2,193,000
|
|
$(3.62)
|
|
$(5.60)
|
-
|
$(1.15)
|
Calendar Year
|
|
Volumes (Bbls)
|
|
Average Short Call Price per Bbl
|
|
Average Swap Price per Bbl
|
2019
|
|
$1,460,000
|
|
$70.00
|
|
$(2.91)
|
|
|
|
|
Average
|
|
Price Range
|
||
Calendar Year
|
|
Volumes (MMBtu)
|
|
Price per MMBtu
|
|
per MMBtu
|
||
2019
|
|
37,175,000
|
|
$3.36
|
|
$3.05
|
-
|
$4.40
|
|
|
|
|
Average
|
|
Price Range
|
||
Calendar Year
|
|
Volumes (MMBtu)
|
|
Price per MMBtu
|
|
per MMBtu
|
||
2019
|
|
3,600,000
|
|
$(0.47)
|
|
$(0.46)
|
-
|
$(0.49)
|
|
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
|
|
|
|
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
|
|
|
2018
|
|
2017
|
|
2016
|
Plains Marketing, LP
|
20%
|
|
10%
|
|
6%
|
Rio Energy International Inc
|
13%
|
|
9%
|
|
3%
|
|
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
|
|
|
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
|
)
|
|
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
|
|
$
|
—
|
|
|
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
|
—
|
|
|
$
|
—
|
|
|
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
|
|
|
|
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
|
|
|
|
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
|
)%
|
|
|
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
|
|
|
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
|
|
|
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.
|
|
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.
|
|
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
.
|
|
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
|
|
|
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
|
|
|
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
|
|
1 Year Legacy Reserves Inc. (MM) Chart |
1 Month Legacy Reserves Inc. (MM) Chart |
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