Delaware
|
95-2636730
|
(State of incorporation)
|
(I.R.S. Employer Identification No.)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common Stock, par value $0.01 per share
|
|
NASDAQ Global Select Market
|
Large accelerated filer
x
|
Accelerated filer
o
|
Non-accelerated filer
£
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
|
Emerging growth company
o
|
|
PART I
|
|
Page
|
|
|
|
|
|
|||
|
|||
|
|||
|
|||
|
|||
|
|
|
|
|
PART II
|
|
|
|
|
|
|
|
|||
|
|||
|
|||
|
|||
|
|||
|
|||
|
|||
|
|||
|
|
|
|
|
PART III
|
|
|
|
|
|
|
|
|||
|
|||
|
|||
|
|||
|
|||
|
|
|
|
|
PART IV
|
|
|
|
|
|
|
|
|||
|
|||
|
|
|
|
|
|
||
|
|
|
|
|
|
•
|
changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for products we produce;
|
•
|
volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;
|
•
|
reductions in the borrowing base under our revolving credit facility;
|
•
|
impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations;
|
•
|
declines in the value of our crude oil, natural gas, and NGLs properties resulting in further impairments;
|
•
|
changes in estimates of proved reserves;
|
•
|
inaccuracy of estimated reserves and production rates;
|
•
|
production decline rates from our wells being greater than expected;
|
•
|
timing and extent of our success in discovering, acquiring, developing, and producing reserves;
|
•
|
availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;
|
•
|
timing and receipt of necessary regulatory permits;
|
•
|
risks incidental to the drilling and operation of crude oil and natural gas wells;
|
•
|
losses from our gas marketing business exceeding our expectations;
|
•
|
difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges;
|
•
|
increases or changes in expenses;
|
•
|
availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells;
|
•
|
potential losses of acreage or zones due to partial or complete lease expirations or otherwise;
|
•
|
increases or adverse changes in construction costs and procurement costs associated with future build out of mid-stream related assets;
|
•
|
future cash flows, liquidity, and financial condition;
|
•
|
possibility that the sale of the Utica Shale properties will not close as expected;
|
•
|
competition within the oil and gas industry;
|
•
|
availability and cost of capital;
|
•
|
our success in marketing crude oil, natural gas, and NGLs;
|
•
|
effect of crude oil and natural gas derivatives activities;
|
•
|
impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
|
•
|
cost of pending or future litigation;
|
•
|
effect that acquisitions we may pursue have on our capital requirements;
|
•
|
our ability to retain or attract senior management and key technical employees; and
|
•
|
success of strategic plans, expectations and objectives for our future operations.
|
•
|
Multi-year project inventory in premier crude oil, natural gas, and NGL plays.
We have a significant operational presence in two premier U.S. onshore basins, the Wattenberg Field in Weld County, Colorado, and the Delaware Basin in Reeves and Culberson Counties, Texas. The company has identified a significant inventory of horizontal drilling locations in each basin which will allow us to continue to grow our proved reserves and production at attractive rates of return based on our current internal long-term commodity price projections and our current expected cost structure. Our 2018 drilling and completion operations are expected to focus on the Kersey area of the Wattenberg Field and in our oilier eastern and north central areas of the Delaware Basin, where we expect to deliver our strongest economic results.
|
•
|
Strong liquidity position.
As of
December 31, 2017
, we had a total liquidity position of
$880.7 million
, comprised of
$180.7 million
of cash and cash equivalents and
$700.0 million
available for borrowing under our revolving credit facility. In November 2017, we issued $600 million principal amount of 5.75 percent unsecured senior notes due in 2026 (the "2026 Senior Notes"). The net proceeds from the offering were used to redeem our $500 million 7.75 percent senior notes due in 2022 (the "2022 Senior Notes"), fund a portion of the Bayswater Acquisition, which closed in early January 2018, and for general corporate purposes. If the Bayswater Acquisition had closed in December 2017, our liquidity position as of December 31, 2017 would have been approximately
$700 million
. We intend to continue to manage our liquidity position through investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative program, and access to capital markets from time to time.
|
•
|
Balanced and diversified portfolio across two premier U.S. onshore basins.
Having drilling opportunities in both the Wattenberg Field and the Delaware Basin allows us to allocate capital between the two basins to diversify our risk. We believe this will improve overall economic results and drive our future production and reserve growth. Additionally, we believe the geographical diversity of our portfolio aids in the mitigation of risks associated with a single dominant producing area, as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity, and regulatory and political considerations.
|
•
|
Significant operational control in our core areas.
We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquiring and consolidating largely concentrated acreage positions with high working interests, we operate and manage approximately
87
percent of all wells in which we have an interest across all of our operating basins. Our control allows us to manage our drilling, production, operating and administrative costs, and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria.
|
•
|
Utilizing technology to focus on efficiency.
In the Wattenberg Field, we have a proven track record of continuing improvement in both costs and productivity of our existing operations. Our efficiencies have historically been driven by a focus on the use of multi-well pad drilling, extended-reach lateral well development, increased fracture stimulation stage density, enhanced fracture stimulation completion design, and improved drilling efficiencies. In 2017, approximately 65 percent of our horizontal well spuds were mid- or extended-reach laterals that ranged from approximately 6,000 to 10,000 horizontal feet in length. We also use a mono-bore drilling design to reduce drill times and well costs. Through the combination of these techniques, our drilling team has improved our drilling efficiencies with average drill results increasing to approximately 2,700 feet drilled per day in 2017 from approximately 2,200 feet drilled per day in 2016.
|
•
|
Strong environmental, health and safety compliance programs, and community outreach.
We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies, and public officials. This is an important part of our strategy and in competing in today’s intensive regulatory and public debate climate. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships.
|
•
|
Commodity derivative program.
Our active use of commodity derivative instruments to protect our investment returns and cash flows was particularly important through the recent commodity price downturns. We have continued this program and entered into commodity derivative instruments to mitigate a portion of our short-term future exposure to commodity price fluctuations, including fixed-price swaps, crude oil and natural gas collars, basis swaps, and rollfactor swap contracts. While our commodity derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing base, and liquidity during periods of depressed commodity prices. We strive to scale our overall hedging position to be appropriate relative to our current and expected level of indebtedness and consistent with our goals of preserving balance sheet strength and substantial liquidity, as well as our internal price view.
|
•
|
Strong management team and operational capabilities.
We have strong and stable management, led by our executive management team. Each member of the team has between 10 and 30 years of experience in the energy and natural resource industry. This experience collectively spans expertise in land, reservoir analysis, operations, accounting, strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure and cost inflation, and other challenging environments.
|
|
|
SRL
|
|
MRL
|
|
XRL
|
Estimated average lateral length (in feet)
|
|
4,200
|
|
6,900
|
|
9,500
|
Expected drilling days (spud-to-spud)
|
|
6
|
|
8
|
|
10
|
Estimated percentage of 2018 wells spud
|
|
25%
|
|
45%
|
|
30%
|
Estimated percentage of 2018 wells turned-in-line
|
|
50%
|
|
35%
|
|
15%
|
Estimated cost per well (in millions)
|
|
$2.6
|
|
$3.5
|
|
$4.4
|
|
SRL
|
|
MRL
|
|
XRL
|
Estimated average lateral length (in feet)
|
5,000
|
|
8,000
|
|
10,000
|
Expected drilling days (spud-to-rig release)
|
30
|
|
31
|
|
36
|
Estimated percentage of 2018 wells spud
|
10%
|
|
40%
|
|
50%
|
Estimated percentage of 2018 wells turned-in-line
|
25%
|
|
45%
|
|
30%
|
Estimated cost per well (in millions)
|
$9.2
|
|
$10.8
|
|
$13.2
|
|
|
Productive Wells
|
||||||||||||||||
|
|
As of December 31, 2017
|
||||||||||||||||
|
|
Crude Oil
|
|
Natural Gas
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field (1)
|
|
811
|
|
|
551.6
|
|
|
1,893
|
|
|
1,660.7
|
|
|
2,704
|
|
|
2,212.3
|
|
Delaware Basin (2)
|
|
47
|
|
|
43.1
|
|
|
4
|
|
|
4.0
|
|
|
51
|
|
|
47.1
|
|
Utica Shale (3)
|
|
27
|
|
|
22.2
|
|
|
3
|
|
|
3.0
|
|
|
30
|
|
|
25.2
|
|
Total productive wells
|
|
885
|
|
|
616.9
|
|
|
1,900
|
|
|
1,667.7
|
|
|
2,785
|
|
|
2,284.6
|
|
|
Proved Reserves at December 31, 2017
|
|
|
|
|
|
|
||||||||
|
Proved Reserves (MMBoe)
|
|
% of Total Proved Reserves
|
|
% Proved Developed
|
|
% Liquids
|
|
Proved Reserves to Production Ratio (in years)(1)
|
|
2017 Production (MBoe)
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
||||
Wattenberg Field
|
350.8
|
|
77
|
%
|
|
33
|
%
|
|
55
|
%
|
|
13.1
|
|
26,815
|
|
Delaware Basin
|
97.9
|
|
22
|
%
|
|
23
|
%
|
|
67
|
%
|
|
23.4
|
|
4,184
|
|
Utica Shale (2)
|
4.2
|
|
1
|
%
|
|
100
|
%
|
|
51
|
%
|
|
5.1
|
|
831
|
|
Total proved reserves
|
452.9
|
|
100
|
%
|
|
32
|
%
|
|
58
|
%
|
|
14.2
|
|
31,830
|
|
|
|
As of December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
|
|
|
||||||
Crude oil (SEC NYMEX - $/Bbl)
|
|
$
|
51.34
|
|
|
$
|
42.75
|
|
|
$
|
50.28
|
|
Natural gas (SEC NYMEX - $/MMBtu)
|
|
$
|
2.98
|
|
|
$
|
2.48
|
|
|
$
|
2.59
|
|
|
As of December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Proved reserves
|
|
|
|
|
|
||||||
Crude oil and condensate
(MMBbls)
|
155
|
|
|
118
|
|
|
99
|
|
|||
Natural gas
(Bcf)
|
1,154
|
|
|
834
|
|
|
661
|
|
|||
NGLs
(MMBbls)
|
106
|
|
|
84
|
|
|
64
|
|
|||
Total proved reserves
(MMBoe)
|
453
|
|
|
341
|
|
|
273
|
|
|||
Proved developed reserves
(MMBoe)
|
143
|
|
|
98
|
|
|
70
|
|
|||
Estimated undiscounted future net cash flows
(in millions)
(1)
|
$
|
5,453
|
|
|
$
|
2,681
|
|
|
$
|
2,259
|
|
|
|
|
|
|
|
||||||
Standardized measure
(in millions)
|
$
|
2,880
|
|
|
$
|
1,421
|
|
|
$
|
1,097
|
|
|
|
|
|
|
|
||||||
PV-10 (
in millions)
(2) (3)
|
$
|
3,212
|
|
|
$
|
1,675
|
|
|
$
|
1,338
|
|
(1)
|
Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately
$6.2 billion
,
$3.3 billion
, and
$2.8 billion
as of December 31,
2017
,
2016
, and
2015
, respectively, less an internally-estimated undiscounted future income tax expense of approximately
$0.7 billion
,
$0.6 billion
, and
$0.5 billion
, respectively.
|
(2)
|
PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.
|
(3)
|
Of the PV-10 amounts, $31.6 million, $21.6 million, and $26.6 million represent amounts attributable to our Utica Shale properties as of December 31, 2017, 2016, and 2015, respectively. In February 2018, we entered into a PSA to sell these properties.
|
|
|
As of December 31, 2017
|
|||||||||||||
Operating Region/Area
|
|
Crude Oil and Condensate (MMBbls)
|
|
Natural Gas
(Bcf) |
|
NGLs
(MMBbls)
|
|
Crude Oil
Equivalent (MMBoe) |
|
Percent
|
|||||
Proved developed
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
36.3
|
|
|
301.9
|
|
|
29.2
|
|
|
115.9
|
|
|
26
|
%
|
Delaware Basin
|
|
9.5
|
|
|
50.6
|
|
|
4.9
|
|
|
22.9
|
|
|
5
|
%
|
Utica Shale (1)
|
|
1.0
|
|
|
12.8
|
|
|
1.1
|
|
|
4.2
|
|
|
1
|
%
|
Total proved developed
|
|
46.8
|
|
|
365.3
|
|
|
35.2
|
|
|
143.0
|
|
|
32
|
%
|
Proved undeveloped
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
69.7
|
|
|
644.5
|
|
|
57.8
|
|
|
234.9
|
|
|
51
|
%
|
Delaware Basin
|
|
38.3
|
|
|
144.5
|
|
|
12.7
|
|
|
75.0
|
|
|
17
|
%
|
Total proved undeveloped
|
|
108.0
|
|
|
789.0
|
|
|
70.5
|
|
|
309.9
|
|
|
68
|
%
|
Total proved reserves
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
106.0
|
|
|
946.4
|
|
|
87.0
|
|
|
350.8
|
|
|
77
|
%
|
Delaware Basin
|
|
47.8
|
|
|
195.1
|
|
|
17.6
|
|
|
97.9
|
|
|
22
|
%
|
Utica Shale (1)
|
|
1.0
|
|
|
12.8
|
|
|
1.1
|
|
|
4.2
|
|
|
1
|
%
|
Total proved reserves
|
|
154.8
|
|
|
1,154.3
|
|
|
105.7
|
|
|
452.9
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing Scenario - NYMEX
|
|||||||||||||||||
|
Crude Oil (per Bbl)
|
|
Natural Gas (per MMBtu)
|
|
Proved Reserves (MMBoe)
|
|
% Change from December 31, 2017 Estimated Reserves
|
PV-10 (in Millions)
|
PV-10 % Change from December 31, 2017 Estimate Reserves
|
|||||||||
2017 SEC Reserve Report (1)
|
$
|
51.34
|
|
|
$
|
2.98
|
|
|
452.9
|
|
|
—
|
|
$
|
3,212.0
|
|
—
|
|
Alternate Price Scenario
|
$
|
30.00
|
|
|
$
|
2.98
|
|
|
424.9
|
|
|
(6
|
)%
|
$
|
1,021.0
|
|
(68
|
)%
|
(1)
|
These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.
|
|
|
As of December 31, 2017
|
||||||||||||||||
|
|
Developed
|
|
Undeveloped
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field (1) (2)
|
|
114,200
|
|
|
109,200
|
|
|
8,800
|
|
|
7,600
|
|
|
123,000
|
|
|
116,800
|
|
Delaware Basin (3)
|
|
31,900
|
|
|
29,500
|
|
|
36,600
|
|
|
30,400
|
|
|
68,500
|
|
|
59,900
|
|
Utica Shale (4)
|
|
5,300
|
|
|
4,500
|
|
|
44,600
|
|
|
41,100
|
|
|
49,900
|
|
|
45,600
|
|
Total acreage
|
|
151,400
|
|
|
143,200
|
|
|
90,000
|
|
|
79,100
|
|
|
241,400
|
|
|
222,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Development Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|||||||||
Wattenberg Field, operated wells
|
|
130
|
|
|
87
|
|
|
—
|
|
|
140
|
|
|
64
|
|
|
2
|
|
|
136
|
|
|
78
|
|
|
4
|
|
Wattenberg Field, non-operated wells
|
|
12
|
|
|
14
|
|
|
1
|
|
|
24
|
|
|
12
|
|
|
—
|
|
|
58
|
|
|
19
|
|
|
—
|
|
Delaware Basin
|
|
11
|
|
|
18
|
|
|
—
|
|
|
1
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica Shale (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
5
|
|
|
—
|
|
Total gross development wells
|
|
153
|
|
|
119
|
|
|
1
|
|
|
170
|
|
|
81
|
|
|
2
|
|
|
198
|
|
|
102
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
|
(2)
|
In February 2018, we entered into a PSA to sell the Utica Shale properties.
|
|
|
Net Development Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|
Productive
|
|
In-Process
|
|
Non-Productive (1)
|
|||||||||
Wattenberg Field, operated wells
|
|
112.8
|
|
|
80.1
|
|
|
—
|
|
|
109.7
|
|
|
52.7
|
|
|
1.7
|
|
|
110.8
|
|
|
54.6
|
|
|
2.7
|
|
Wattenberg Field, non-operated wells
|
|
1.6
|
|
|
2.6
|
|
|
0.1
|
|
|
5.0
|
|
|
2.8
|
|
|
—
|
|
|
9.3
|
|
|
4.3
|
|
|
—
|
|
Delaware Basin
|
|
10.5
|
|
|
10.4
|
|
|
—
|
|
|
1.0
|
|
|
4.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica Shale (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.5
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
|
4.5
|
|
|
—
|
|
Total net development wells
|
|
124.9
|
|
|
93.1
|
|
|
0.1
|
|
|
120.2
|
|
|
60.3
|
|
|
1.7
|
|
|
123.1
|
|
|
63.4
|
|
|
2.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents mechanical failures that resulted in the plugging and abandonment of the respective wells.
|
(2)
|
In February 2018, we entered into a PSA to sell the Utica Shale properties.
|
|
|
Gross Exploratory Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Non-Productive
|
|
Productive
|
|
In-Process
|
|
Non-Productive
|
|
Productive
|
|
In-Process
|
|
Non-Productive
|
|||||||||
Wattenberg Field, operated wells
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wattenberg Field, non-operated wells
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Delaware Basin
|
|
5
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total gross development wells
|
|
5
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exploratory Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Non-Productive
|
|
Productive
|
|
In-Process
|
|
Non-Productive
|
|
Productive
|
|
In-Process
|
|
Non-Productive
|
|||||||||
Wattenberg Field, operated wells
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wattenberg Field, non-operated wells
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Delaware Basin
|
|
3.1
|
|
|
2.8
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Utica Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total gross development wells
|
|
3.1
|
|
|
2.8
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
•
|
our revenue, profitability and cash flows;
|
•
|
our liquidity;
|
•
|
the quantity and present value of our reserves;
|
•
|
the borrowing base under our revolving credit facility and access to other sources of capital; and
|
•
|
the nature and scale of our operations.
|
•
|
relatively minor changes in regional, national, or global supply and demand;
|
•
|
regional, national, or global economic conditions, and perceived trends in those conditions;
|
•
|
geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or ("OPEC"); and
|
•
|
regulatory changes.
|
•
|
Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;
|
•
|
Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; and
|
•
|
Some upstream energy companies have recently sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure.
|
•
|
fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area;
|
•
|
natural disasters such as the flooding that occurred in northern Colorado in September 2013;
|
•
|
restrictive governmental regulations; and
|
•
|
curtailment of production or interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells.
|
•
|
Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves.
|
•
|
Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other greenhouse gases ("GHGs"). For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the United States is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program.
|
•
|
From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, during 2016, interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, advanced two initiatives: (i) a “local control” initiative that would have amended the state constitution to give city, town, and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level, and (ii) a “setback” initiative that would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern”. If implemented, the setback initiative would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. These proposals ultimately did not appear on the November 2016 ballot but it is likely that similar proposals will be made in 2018 and in future years. Similar proposals may also be made in other states.
|
•
|
A recently-adopted ballot initiative that would make it more difficult to implement certain types of ballot initiatives in the future is currently the subject of a legal challenge and may be invalidated.
|
•
|
Proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.
|
•
|
The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage, and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays,
|
•
|
the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties;
|
•
|
future depreciation, depletion, and amortization (“DD&A”) rates and amounts;
|
•
|
impairments in the value of our assets;
|
•
|
the classifications of reserves based on risk of recovery;
|
•
|
estimates of future net cash flows;
|
•
|
timing of our capital expenditures; and
|
•
|
the amount of funds available for us to borrow under our revolving credit facility.
|
•
|
crude oil, natural gas, and NGL prices;
|
•
|
the availability and cost of capital;
|
•
|
drilling and production costs;
|
•
|
availability of drilling services and equipment;
|
•
|
drilling results;
|
•
|
lease expirations or limitations as to depth;
|
•
|
midstream constraints;
|
•
|
access to and availability of water sourcing and distribution systems;
|
•
|
regulatory approvals; and
|
•
|
other factors.
|
•
|
unusual or unexpected geological formations;
|
•
|
pressures;
|
•
|
fires;
|
•
|
floods;
|
•
|
loss of well control;
|
•
|
loss of drilling fluid circulation;
|
•
|
title problems;
|
•
|
facility or equipment malfunctions;
|
•
|
unexpected operational events;
|
•
|
shortages or delays in the delivery of equipment and services;
|
•
|
unanticipated environmental liabilities;
|
•
|
compliance with environmental and other governmental requirements; and
|
•
|
adverse weather conditions.
|
•
|
our proved reserves;
|
•
|
the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells;
|
•
|
the prices at which crude oil, natural gas, and NGLs are sold;
|
•
|
the costs to produce crude oil, natural gas, and NGLs; and
|
•
|
our ability to acquire, locate and produce new reserves.
|
•
|
incur additional debt;
|
•
|
pay dividends on, redeem or repurchase stock;
|
•
|
create liens;
|
•
|
make specified types of investments;
|
•
|
apply net proceeds from certain asset sales;
|
•
|
engage in transactions with our affiliates;
|
•
|
engage in sale and leaseback transactions;
|
•
|
merge or consolidate;
|
•
|
restrict dividends or other payments from restricted subsidiaries;
|
•
|
sell equity interests of restricted subsidiaries; and
|
•
|
sell, assign, transfer, lease, convey or dispose of assets.
|
•
|
changes in production volumes, worldwide demand and prices for crude oil and natural gas;
|
•
|
changes in market prices of crude oil and natural gas;
|
•
|
inability to hedge future production at the same pricing level as our current or prior hedges;
|
•
|
changes in securities analysts’ estimates of our financial performance;
|
•
|
fluctuations in stock market prices and volumes, particularly among securities of energy companies;
|
•
|
changes in market valuations and valuation multiples of similar companies;
|
•
|
changes in interest rates;
|
•
|
announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing crude oil and natural gas resources;
|
•
|
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;
|
•
|
decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate;
|
•
|
operating results that fall below market expectations or variations in our quarterly operating results;
|
•
|
loss of a major customer;
|
•
|
loss of a relationship with a partner;
|
•
|
the identification of and severity of environmental events and governmental and other third-party responses to the events; or
|
•
|
additions or departures of key personnel.
|
•
|
The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
|
•
|
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.
|
•
|
Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.
|
|
|
||||||
|
High
|
|
Low
|
||||
|
|
|
|
||||
January 1 - March 31, 2016
|
$
|
60.56
|
|
|
$
|
42.68
|
|
April 1 - June 30, 2016
|
65.86
|
|
|
51.92
|
|
||
July 1 - September 30, 2016
|
71.00
|
|
|
50.12
|
|
||
October 1 - December 31, 2016
|
84.88
|
|
|
59.82
|
|
||
January 1 - March 31, 2017
|
78.61
|
|
|
60.27
|
|
||
April 1 - June 30, 2017
|
65.99
|
|
|
40.12
|
|
||
July 1 - September 30, 2017
|
50.51
|
|
|
36.74
|
|
||
October 1 - December 31, 2017
|
53.41
|
|
|
41.13
|
|
Period
|
|
Total Number of Shares Purchased (1)
|
|
Average Price Paid per Share
|
|||
|
|
|
|
|
|||
October 1 - 31, 2017
|
|
5,636
|
|
|
$
|
48.88
|
|
November 1 - 30, 2017
|
|
—
|
|
|
—
|
|
|
December 1 - 31, 2017
|
|
21,301
|
|
|
50.68
|
|
|
Total fourth quarter 2017 purchases
|
|
26,937
|
|
|
50.30
|
|
(1)
|
Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans.
|
|
|
Year Ended/As of December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016 (1)
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
|
(in millions, except per share data and as noted)
|
||||||||||||||||||
Statement of Operations (From Continuing Operations) (2):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, natural gas, and NGLs sales
|
|
$
|
913.1
|
|
|
$
|
497.4
|
|
|
$
|
378.7
|
|
|
$
|
471.4
|
|
|
$
|
340.8
|
|
Commodity price risk management gain (loss), net
|
|
(3.9
|
)
|
|
(125.7
|
)
|
|
203.2
|
|
|
310.3
|
|
|
(23.9
|
)
|
|||||
Total revenues
|
|
921.6
|
|
|
382.9
|
|
|
595.3
|
|
|
856.2
|
|
|
392.7
|
|
|||||
Income (loss) from continuing operations
|
|
(127.5
|
)
|
|
(245.9
|
)
|
|
(68.3
|
)
|
|
107.3
|
|
|
(21.1
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
(1.94
|
)
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.65
|
)
|
Diluted
|
|
(1.94
|
)
|
|
(5.01
|
)
|
|
(1.74
|
)
|
|
2.93
|
|
|
(0.65
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows from:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
588.6
|
|
|
$
|
486.3
|
|
|
$
|
411.1
|
|
|
$
|
236.7
|
|
|
$
|
159.2
|
|
Investing activities
|
|
(717.0
|
)
|
|
(1,509.1
|
)
|
|
(604.3
|
)
|
|
(474.1
|
)
|
|
(217.1
|
)
|
|||||
Financing activities
|
|
65.0
|
|
|
1,266.1
|
|
|
178.0
|
|
|
60.3
|
|
|
248.7
|
|
|||||
Capital expenditures from development and exploration activities (3)
|
|
737.2
|
|
|
436.9
|
|
|
599.5
|
|
|
623.8
|
|
|
384.7
|
|
|||||
Acquisitions of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition
|
|
15.6
|
|
|
1,073.7
|
|
|
—
|
|
|
—
|
|
|
9.7
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
4,419.9
|
|
|
$
|
4,485.8
|
|
|
$
|
2,370.5
|
|
|
$
|
2,331.1
|
|
|
$
|
1,991.7
|
|
Working capital (deficit)
|
|
(16.4
|
)
|
|
129.2
|
|
|
30.7
|
|
|
89.5
|
|
|
90.0
|
|
|||||
Total debt,
net of unamortized discount and debt issuance costs
|
|
1,151.9
|
|
|
1,044.0
|
|
|
642.4
|
|
|
655.5
|
|
|
593.9
|
|
|||||
Total equity
|
|
2,507.6
|
|
|
2,622.8
|
|
|
1,287.2
|
|
|
1,137.4
|
|
|
967.6
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Average Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for production taxes):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales price (excluding net settlements on derivatives)
|
|
$
|
28.69
|
|
|
$
|
22.43
|
|
|
$
|
24.64
|
|
|
$
|
50.72
|
|
|
$
|
52.23
|
|
Lease operating expenses
|
|
$
|
2.82
|
|
|
$
|
2.70
|
|
|
$
|
3.71
|
|
|
$
|
4.56
|
|
|
$
|
5.18
|
|
Transportation, gathering, and processing
|
|
$
|
1.04
|
|
|
$
|
0.83
|
|
|
$
|
0.66
|
|
|
$
|
0.49
|
|
|
$
|
0.79
|
|
Production taxes
|
|
$
|
1.91
|
|
|
$
|
1.42
|
|
|
$
|
1.20
|
|
|
$
|
2.76
|
|
|
$
|
3.33
|
|
Production taxes as a percent of sales
|
|
6.6
|
%
|
|
6.3
|
%
|
|
4.9
|
%
|
|
5.4
|
%
|
|
6.4
|
%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production (MBoe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production from continuing operations
|
|
31,830
|
|
|
22,176
|
|
|
15,369
|
|
|
9,294
|
|
|
6,525
|
|
|||||
Production from discontinued operations
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,093
|
|
|
2,032
|
|
|||||
Total production
|
|
31,830
|
|
|
22,176
|
|
|
15,369
|
|
|
10,387
|
|
|
8,557
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total proved reserves (MMBoe) (4)
|
|
452.9
|
|
|
341.4
|
|
|
272.8
|
|
|
250.1
|
|
|
265.8
|
|
(1)
|
In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately
$1.76 billion
. See footnotes titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding this acquisition.
|
(2)
|
In 2014, we completed the sale of our ownership interest in PDC Mountaineer, LLC ("PDCM"). Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations.
|
(3)
|
Includes impact of change in accounts payable related to capital expenditures.
|
(4)
|
Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe as of December 31, 2013. PDCM, which owned these reserves, was sold in late 2014.
|
|
|
Wells Operated by PDC
|
||||||||||||||||
|
|
Wattenberg Field
|
|
Delaware Basin
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
In-process as of December 31, 2016
|
|
64
|
|
|
52.7
|
|
|
5
|
|
|
4.8
|
|
|
69
|
|
|
57.5
|
|
Wells spud
|
|
153
|
|
|
140.2
|
|
|
26
|
|
|
22.7
|
|
|
179
|
|
|
162.9
|
|
Wells turned-in-line
|
|
(130
|
)
|
|
(112.8
|
)
|
|
(16
|
)
|
|
(15.2
|
)
|
|
(146
|
)
|
|
(128.0
|
)
|
Exploratory dry holes
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2.0
|
)
|
|
(2
|
)
|
|
(2.0
|
)
|
In-process as of December 31, 2017
|
|
87
|
|
|
80.1
|
|
|
13
|
|
|
10.3
|
|
|
100
|
|
|
90.4
|
|
|
|
Wells Operated by Others
|
||||||||||||||||
|
|
Wattenberg Field
|
|
Delaware Basin
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
In-process as of December 31, 2016
|
|
18
|
|
|
3.4
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
3.4
|
|
Wells spud
|
|
94
|
|
|
13.1
|
|
|
10
|
|
|
1.5
|
|
|
104
|
|
|
14.5
|
|
Wells turned-in-line
|
|
(12
|
)
|
|
(1.6
|
)
|
|
(2
|
)
|
|
(0.4
|
)
|
|
(14
|
)
|
|
(2.0
|
)
|
Wells interest exchanged
|
|
(85
|
)
|
|
(12.2
|
)
|
|
—
|
|
|
—
|
|
|
(85
|
)
|
|
(12.2
|
)
|
Exploratory dry holes
|
|
(1
|
)
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(0.1
|
)
|
In-process as of December 31, 2017
|
|
14
|
|
|
2.6
|
|
|
8
|
|
|
1.1
|
|
|
22
|
|
|
3.6
|
|
|
Low
|
|
High
|
||||
Operating Expenses
|
|||||||
Lease operating expenses ($/Boe)
|
$
|
2.75
|
|
|
$
|
3.00
|
|
Transportation, gathering, and processing expenses ("TGP") ($/Boe)
|
$
|
0.60
|
|
|
$
|
0.80
|
|
Production taxes (% of crude oil, natural gas, and NGL sales)
|
6
|
%
|
|
8
|
%
|
||
General and administrative expense ($/Boe)
|
$
|
3.40
|
|
|
$
|
3.70
|
|
|
|
|
|
||||
Estimated Price Realizations (% of NYMEX, excludes TGP)
|
|||||||
Crude oil
|
91%
|
|
95%
|
||||
Natural gas
|
55%
|
|
60%
|
||||
NGLs
|
30%
|
|
35%
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
|
|
Percent Change
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2017-2016
|
|
2016-2015
|
||||||||
|
(dollars in millions, except per unit data)
|
|
|
|
|
||||||||||||
Production
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (MBbls)
|
12,902
|
|
|
8,728
|
|
|
6,984
|
|
|
47.8
|
%
|
|
25.0
|
%
|
|||
Natural gas (MMcf)
|
71,689
|
|
|
51,730
|
|
|
33,302
|
|
|
38.6
|
%
|
|
55.3
|
%
|
|||
NGLs (MBbls)
|
6,981
|
|
|
4,826
|
|
|
2,835
|
|
|
44.7
|
%
|
|
70.2
|
%
|
|||
Crude oil equivalent (MBoe)
|
31,830
|
|
|
22,176
|
|
|
15,369
|
|
|
43.5
|
%
|
|
44.3
|
%
|
|||
Average Boe per day (Boe)
|
87,206
|
|
|
60,590
|
|
|
42,108
|
|
|
43.9
|
%
|
|
43.9
|
%
|
|||
Crude Oil, Natural Gas and NGLs Sales
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil
|
$
|
625.0
|
|
|
$
|
348.9
|
|
|
$
|
280.3
|
|
|
79.1
|
%
|
|
24.5
|
%
|
Natural gas
|
158.3
|
|
|
91.6
|
|
|
68.0
|
|
|
72.8
|
%
|
|
34.7
|
%
|
|||
NGLs
|
129.8
|
|
|
56.9
|
|
|
30.4
|
|
|
128.1
|
%
|
|
87.2
|
%
|
|||
Total crude oil, natural gas, and NGLs sales
|
$
|
913.1
|
|
|
$
|
497.4
|
|
|
$
|
378.7
|
|
|
83.6
|
%
|
|
31.3
|
%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Settlements on Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil
|
$
|
(2.7
|
)
|
|
$
|
165.2
|
|
|
$
|
208.9
|
|
|
(101.6
|
)%
|
|
(20.9
|
)%
|
Natural gas
|
23.3
|
|
|
42.9
|
|
|
30.0
|
|
|
(45.7
|
)%
|
|
43.0
|
%
|
|||
NGLs (propane portion)
|
(7.3
|
)
|
|
—
|
|
|
—
|
|
|
*
|
|
|
*
|
|
|||
Total net settlements on derivatives
|
$
|
13.3
|
|
|
$
|
208.1
|
|
|
$
|
238.9
|
|
|
(93.6
|
)%
|
|
(12.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price (excluding net settlements on derivatives)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (per Bbl)
|
$
|
48.45
|
|
|
$
|
39.96
|
|
|
$
|
40.14
|
|
|
21.2
|
%
|
|
(0.4
|
)%
|
Natural gas (per Mcf)
|
2.21
|
|
|
1.77
|
|
|
2.04
|
|
|
24.9
|
%
|
|
(13.2
|
)%
|
|||
NGLs (per Bbl)
|
18.59
|
|
|
11.80
|
|
|
10.72
|
|
|
57.5
|
%
|
|
10.1
|
%
|
|||
Crude oil equivalent (per Boe)
|
28.69
|
|
|
22.43
|
|
|
24.64
|
|
|
27.9
|
%
|
|
(9.0
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Costs and Expenses (per Boe)
|
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
$
|
2.82
|
|
|
$
|
2.70
|
|
|
$
|
3.71
|
|
|
4.4
|
%
|
|
(27.2
|
)%
|
Production taxes
|
1.91
|
|
|
1.42
|
|
|
1.20
|
|
|
34.5
|
%
|
|
18.3
|
%
|
|||
Transportation, gathering, and processing expenses
|
1.04
|
|
|
0.83
|
|
|
0.66
|
|
|
25.3
|
%
|
|
25.8
|
%
|
|||
General and administrative expense
|
3.78
|
|
|
5.07
|
|
|
5.85
|
|
|
(25.4
|
)%
|
|
(13.3
|
)%
|
|||
Depreciation, depletion, and amortization
|
14.74
|
|
|
18.80
|
|
|
19.73
|
|
|
(21.6
|
)%
|
|
(4.7
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Lease Operating Expenses by Operating Region (per Boe)
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
$
|
2.48
|
|
|
$
|
2.70
|
|
|
$
|
3.78
|
|
|
(8.1
|
)%
|
|
(28.6
|
)%
|
Delaware Basin
|
5.16
|
|
|
8.79
|
|
|
*
|
|
|
(41.3
|
)%
|
|
*
|
|
|||
Utica Shale (1)
|
1.66
|
|
|
1.75
|
|
|
2.78
|
|
|
(5.1
|
)%
|
|
(37.1
|
)%
|
*
|
Percentage change is not meaningful or equal to or greater than 300% or not applicable.
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Increase in production
|
$
|
227.5
|
|
|
$
|
129.0
|
|
Increase (decrease) in average crude oil price
|
109.6
|
|
|
(1.6
|
)
|
||
Increase (decrease) in average natural gas price
|
31.2
|
|
|
(14.0
|
)
|
||
Increase in average NGLs price
|
47.4
|
|
|
5.2
|
|
||
Total increase in crude oil, natural gas and NGLs sales revenue
|
$
|
415.7
|
|
|
$
|
118.6
|
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
|
|
|
|
|
|
Change
|
|||||||
Production by Operating Region
|
|
2017
|
|
2016
|
|
2015
|
|
2017-2016
|
|
2016-2015
|
|||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
10,922
|
|
|
8,230
|
|
|
6,490
|
|
|
32.7
|
%
|
|
26.8
|
%
|
Delaware Basin
|
|
1,699
|
|
|
79
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale (1)
|
|
281
|
|
|
419
|
|
|
494
|
|
|
(32.9
|
)%
|
|
(15.2
|
)%
|
Total
|
|
12,902
|
|
|
8,728
|
|
|
6,984
|
|
|
47.8
|
%
|
|
25.0
|
%
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
60,106
|
|
|
48,889
|
|
|
30,753
|
|
|
22.9
|
%
|
|
59.0
|
%
|
Delaware Basin
|
|
9,410
|
|
|
373
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale (1)
|
|
2,173
|
|
|
2,468
|
|
|
2,549
|
|
|
(12.0
|
)%
|
|
(3.2
|
)%
|
Total
|
|
71,689
|
|
|
51,730
|
|
|
33,302
|
|
|
38.6
|
%
|
|
55.3
|
%
|
NGLs (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
5,876
|
|
|
4,568
|
|
|
2,616
|
|
|
28.6
|
%
|
|
74.6
|
%
|
Delaware Basin
|
|
917
|
|
|
36
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale (1)
|
|
188
|
|
|
222
|
|
|
219
|
|
|
(15.3
|
)%
|
|
1.4
|
%
|
Total
|
|
6,981
|
|
|
4,826
|
|
|
2,835
|
|
|
44.7
|
%
|
|
70.2
|
%
|
Crude oil equivalent (MBoe)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
26,815
|
|
|
20,945
|
|
|
14,231
|
|
|
28.0
|
%
|
|
47.2
|
%
|
Delaware Basin
|
|
4,184
|
|
|
178
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale (1)
|
|
831
|
|
|
1,053
|
|
|
1,138
|
|
|
(21.1
|
)%
|
|
(7.5
|
)%
|
Total
|
|
31,830
|
|
|
22,176
|
|
|
15,369
|
|
|
43.5
|
%
|
|
44.3
|
%
|
Average crude oil equivalent per day (Boe)
|
|
|
|
|
|
|
|
|
|||||||
Wattenberg Field
|
|
73,466
|
|
|
57,227
|
|
|
38,990
|
|
|
28.4
|
%
|
|
46.8
|
%
|
Delaware Basin
|
|
11,463
|
|
|
486
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Utica Shale (1)
|
|
2,277
|
|
|
2,877
|
|
|
3,118
|
|
|
(20.9
|
)%
|
|
(7.7
|
)%
|
Total
|
|
87,206
|
|
|
60,590
|
|
|
42,108
|
|
|
43.9
|
%
|
|
43.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
Weighted-Average Sales Price by Operating Region
|
|
|
|
|
|
|
|
Change
|
||||||||||
(excluding net settlements on derivatives)
|
|
2017
|
|
2016
|
|
2015
|
|
2017-2016
|
|
2016-2015
|
||||||||
Crude oil (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
$
|
48.48
|
|
|
$
|
39.99
|
|
|
$
|
40.03
|
|
|
21.2
|
%
|
|
(0.1
|
)%
|
Delaware Basin
|
|
48.68
|
|
|
49.28
|
|
|
—
|
|
|
(1.2
|
)%
|
|
*
|
|
|||
Utica Shale (1)
|
|
45.63
|
|
|
37.62
|
|
|
41.59
|
|
|
21.3
|
%
|
|
(9.5
|
)%
|
|||
Weighted-average price
|
|
48.45
|
|
|
39.96
|
|
|
40.14
|
|
|
21.2
|
%
|
|
(0.4
|
)%
|
|||
Natural gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
2.19
|
|
|
1.77
|
|
|
2.06
|
|
|
23.7
|
%
|
|
(14.1
|
)%
|
|||
Delaware Basin
|
|
2.26
|
|
|
2.78
|
|
|
—
|
|
|
(18.7
|
)%
|
|
*
|
|
|||
Utica Shale (1)
|
|
2.40
|
|
|
1.58
|
|
|
1.85
|
|
|
51.9
|
%
|
|
(14.6
|
)%
|
|||
Weighted-average price
|
|
2.21
|
|
|
1.77
|
|
|
2.04
|
|
|
24.9
|
%
|
|
(13.2
|
)%
|
|||
NGLs (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
17.75
|
|
|
11.59
|
|
|
10.58
|
|
|
53.1
|
%
|
|
9.5
|
%
|
|||
Delaware Basin
|
|
22.64
|
|
|
17.87
|
|
|
—
|
|
|
26.7
|
%
|
|
*
|
|
|||
Utica Shale (1)
|
|
25.06
|
|
|
15.11
|
|
|
12.43
|
|
|
65.9
|
%
|
|
21.6
|
%
|
|||
Weighted-average price
|
|
18.59
|
|
|
11.80
|
|
|
10.72
|
|
|
57.5
|
%
|
|
10.1
|
%
|
|||
Crude oil equivalent (per Boe)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
28.55
|
|
|
22.38
|
|
|
24.64
|
|
|
27.6
|
%
|
|
(9.2
|
)%
|
|||
Delaware Basin
|
|
29.80
|
|
|
31.50
|
|
|
—
|
|
|
(5.4
|
)%
|
|
*
|
|
|||
Utica Shale (1)
|
|
27.36
|
|
|
21.88
|
|
|
24.59
|
|
|
25.0
|
%
|
|
(11.0
|
)%
|
|||
Weighted-average price
|
|
28.69
|
|
|
22.43
|
|
|
24.64
|
|
|
27.9
|
%
|
|
(9.0
|
)%
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
2017
|
|
Average NYMEX Price
|
|
Average Realized Price Before Transportation, Gathering and Processing Expenses
|
|
Average Realization Percentage Before Transportation, Gathering and Processing Expenses
|
|
Average Transportation, Gathering and Processing Expenses
|
|
Average Realized Price After Transportation, Gathering and Processing Expenses
|
|
Average Realization Percentage After Transportation, Gathering and Processing Expenses
|
||||||||||
Crude oil (per Bbl)
|
|
$
|
50.95
|
|
|
$
|
48.45
|
|
|
95
|
%
|
|
$
|
1.41
|
|
|
$
|
47.04
|
|
|
92
|
%
|
Natural gas (per MMBtu)
|
|
3.11
|
|
|
2.21
|
|
|
71
|
%
|
|
0.17
|
|
|
2.04
|
|
|
66
|
%
|
||||
NGLs (per Bbl)
|
|
50.95
|
|
|
18.59
|
|
|
36
|
%
|
|
0.30
|
|
|
18.29
|
|
|
36
|
%
|
||||
Crude oil equivalent (per Boe)
|
|
38.83
|
|
|
28.69
|
|
|
74
|
%
|
|
1.04
|
|
|
27.65
|
|
|
71
|
%
|
2016
|
|
Average NYMEX Price
|
|
Average Realized Price Before Transportation, Gathering and Processing Expenses
|
|
Average Realization Percentage Before Transportation, Gathering and Processing Expenses
|
|
Average Transportation, Gathering and Processing Expenses
|
|
Average Realized Price After Transportation, Gathering and Processing Expenses
|
|
Average Realization Percentage After Transportation, Gathering and Processing Expenses
|
||||||||||
Crude oil (per Bbl)
|
|
$
|
43.32
|
|
|
$
|
39.96
|
|
|
92
|
%
|
|
$
|
1.51
|
|
|
$
|
38.45
|
|
|
89
|
%
|
Natural gas (per MMBtu)
|
|
2.46
|
|
|
1.77
|
|
|
72
|
%
|
|
0.07
|
|
|
1.70
|
|
|
69
|
%
|
||||
NGLs (per Bbl)
|
|
43.32
|
|
|
11.80
|
|
|
27
|
%
|
|
0.28
|
|
|
11.52
|
|
|
27
|
%
|
||||
Crude oil equivalent (per Boe)
|
|
32.22
|
|
|
22.43
|
|
|
70
|
%
|
|
0.83
|
|
|
21.60
|
|
|
67
|
%
|
2015
|
|
Average NYMEX Price
|
|
Average Realized Price Before Transportation, Gathering and Processing Expenses
|
|
Average Realization Percentage Before Transportation, Gathering and Processing Expenses
|
|
Average Transportation, Gathering and Processing Expenses
|
|
Average Realized Price After Transportation, Gathering and Processing Expenses
|
|
Average Realization Percentage After Transportation, Gathering and Processing Expenses
|
||||||||||
Crude oil (per Bbl)
|
|
$
|
48.80
|
|
|
$
|
40.14
|
|
|
82
|
%
|
|
$
|
0.67
|
|
|
$
|
39.47
|
|
|
81
|
%
|
Natural gas (per MMBtu)
|
|
2.66
|
|
|
2.04
|
|
|
77
|
%
|
|
0.12
|
|
|
1.92
|
|
|
72
|
%
|
||||
NGLs (per Bbl)
|
|
48.80
|
|
|
10.72
|
|
|
22
|
%
|
|
0.55
|
|
|
10.17
|
|
|
21
|
%
|
||||
Crude oil equivalent (per Boe)
|
|
36.94
|
|
|
24.64
|
|
|
67
|
%
|
|
0.66
|
|
|
23.98
|
|
|
65
|
%
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Commodity price risk management gain (loss), net:
|
|
|
|
|
|
||||||
Net settlements of commodity derivative instruments:
|
|
|
|
|
|
||||||
Crude oil fixed price swaps and collars
|
$
|
(2.7
|
)
|
|
$
|
165.2
|
|
|
$
|
208.9
|
|
Natural gas fixed price swaps and collars
|
19.5
|
|
|
41.9
|
|
|
31.0
|
|
|||
Natural gas basis protection swaps
|
3.8
|
|
|
1.0
|
|
|
(1.0
|
)
|
|||
NGLs (propane portion) fixed price swaps
|
(7.3
|
)
|
|
—
|
|
|
—
|
|
|||
Total net settlements of commodity derivative instruments
|
13.3
|
|
|
208.1
|
|
|
238.9
|
|
|||
Change in fair value of unsettled commodity derivative instruments:
|
|
|
|
|
|
||||||
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments
|
44.8
|
|
|
(220.0
|
)
|
|
(186.9
|
)
|
|||
Crude oil fixed price swaps, collars, and rollfactors
|
(77.9
|
)
|
|
(78.6
|
)
|
|
99.3
|
|
|||
Natural gas fixed price swaps and collars
|
14.7
|
|
|
(37.1
|
)
|
|
53.3
|
|
|||
Natural gas basis protection swaps
|
5.7
|
|
|
1.9
|
|
|
(1.4
|
)
|
|||
NGLs (propane portion) fixed price swaps
|
(4.6
|
)
|
|
—
|
|
|
—
|
|
|||
Net change in fair value of unsettled commodity derivative instruments
|
(17.3
|
)
|
|
(333.8
|
)
|
|
(35.7
|
)
|
|||
Total commodity price risk management gain (loss), net
|
$
|
(4.0
|
)
|
|
$
|
(125.7
|
)
|
|
$
|
203.2
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Exploratory dry hole costs
|
|
$
|
41.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Geological and geophysical costs
|
|
3.9
|
|
|
3.5
|
|
|
—
|
|
|||
Operating, personnel and other
|
|
2.1
|
|
|
1.2
|
|
|
1.1
|
|
|||
Total exploration expense
|
|
$
|
47.3
|
|
|
$
|
4.7
|
|
|
$
|
1.1
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
$
|
285.5
|
|
|
$
|
5.6
|
|
|
$
|
154.6
|
|
Amortization of individually insignificant unproved properties
|
0.4
|
|
|
1.4
|
|
|
7.0
|
|
|||
Land and buildings
|
—
|
|
|
3.0
|
|
|
—
|
|
|||
Total impairment of properties and equipment
|
$
|
285.9
|
|
|
$
|
10.0
|
|
|
$
|
161.6
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2017 - 2016
|
|
2016 - 2015
|
||||
|
|
(in millions)
|
||||||
Increase in production
|
|
$
|
144.7
|
|
|
$
|
132.3
|
|
Decrease in weighted-average depreciation, depletion and amortization rates
|
|
(95.3
|
)
|
|
(18.0
|
)
|
||
Total increase in DD&A expense related to crude oil and natural gas properties
|
|
$
|
49.4
|
|
|
$
|
114.3
|
|
|
|
Year Ended December 31,
|
||||||||||
Operating Region/Area
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(per Boe)
|
||||||||||
Wattenberg Field
|
|
$
|
14.67
|
|
|
$
|
19.11
|
|
|
$
|
20.13
|
|
Delaware Basin (1)
|
|
14.89
|
|
|
8.34
|
|
|
—
|
|
|||
Utica Shale (2)
|
|
8.09
|
|
|
10.66
|
|
|
10.74
|
|
|||
Total weighted-average
|
|
14.53
|
|
|
18.63
|
|
|
19.44
|
|
|
|
Payments due by period
|
||||||||||||||||||
|
|
|
|
Less than
|
|
1-3
|
|
3-5
|
|
More than
|
||||||||||
Contractual Obligations and Contingent Commitments
|
|
Total
|
|
1 year
|
|
years
|
|
years
|
|
5 years
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
Long-term liabilities reflected on the consolidated balance sheet (1)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt (2)
|
|
$
|
1,200
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
200
|
|
|
$
|
1,000
|
|
Commodity derivative contracts (3)
|
|
101
|
|
|
79
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|||||
Capital leases (4)
|
|
4
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|||||
Production tax liability
|
|
85
|
|
|
38
|
|
|
47
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
87
|
|
|
16
|
|
|
32
|
|
|
32
|
|
|
7
|
|
|||||
Other liabilities (5)
|
|
8
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|||||
|
|
1,485
|
|
|
136
|
|
|
106
|
|
|
234
|
|
|
1,009
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commitments, contingencies and other arrangements (6)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest on long-term debt (7)
|
|
552
|
|
|
87
|
|
|
172
|
|
|
135
|
|
|
158
|
|
|||||
Operating leases
|
|
23
|
|
|
4
|
|
|
8
|
|
|
8
|
|
|
3
|
|
|||||
Firm transportation and processing agreements (8)
|
|
262
|
|
|
23
|
|
|
86
|
|
|
66
|
|
|
87
|
|
|||||
|
|
837
|
|
|
114
|
|
|
266
|
|
|
209
|
|
|
248
|
|
|||||
Total
|
|
$
|
2,322
|
|
|
$
|
250
|
|
|
$
|
372
|
|
|
$
|
443
|
|
|
$
|
1,257
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Table does not include deferred income tax liability to taxing authorities of
$192.0 million
due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
(2)
|
Amount presented does not agree with the consolidated balance sheets in that it excludes
$30.3 million
of unamortized debt discount and
$17.7 million
of unamortized debt issuance costs.
|
(3)
|
Represents our gross liability related to the fair value of derivative positions.
|
(4)
|
Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.
|
(5)
|
Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.
|
(6)
|
The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
(7)
|
Amounts presented include $288.9 million to the holders of our 2026 Senior Notes, $164.2 million to the holders of our 2024 Senior Notes, and $90.7 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $8.4 million related to unutilized commitments at a rate of 0.50 percent per annum.
|
(8)
|
Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. This includes anticipated and estimated commitments associated with two new gas processing facilities by our primary mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencement of operations by the midstream provider.
|
•
|
operating performance and return on capital as compared to our peers;
|
•
|
financial performance of our assets and our valuation without regard to financing methods, capital structure, or historical cost basis;
|
•
|
our ability to generate sufficient cash to service our debt obligations; and
|
•
|
the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Adjusted cash flows from operations:
|
|
|
|
|
|
||||||
Net cash from operating activities
|
$
|
588.6
|
|
|
$
|
486.3
|
|
|
$
|
411.1
|
|
Changes in assets and liabilities
|
(6.5
|
)
|
|
(19.5
|
)
|
|
9.7
|
|
|||
Adjusted cash flows from operations
|
$
|
582.1
|
|
|
$
|
466.8
|
|
|
$
|
420.8
|
|
|
|
|
|
|
|
||||||
Adjusted net loss:
|
|
|
|
|
|
||||||
Net loss
|
$
|
(127.5
|
)
|
|
$
|
(245.9
|
)
|
|
$
|
(68.3
|
)
|
(Gain) loss on commodity derivative instruments
|
3.9
|
|
|
125.7
|
|
|
(203.2
|
)
|
|||
Net settlements on commodity derivative instruments
|
13.3
|
|
|
208.1
|
|
|
238.9
|
|
|||
Tax effect of above adjustments
|
(4.1
|
)
|
|
(124.9
|
)
|
|
(13.6
|
)
|
|||
Adjusted net loss
|
$
|
(114.4
|
)
|
|
$
|
(37.0
|
)
|
|
$
|
(46.2
|
)
|
|
|
|
|
|
|
||||||
Net loss to adjusted EBITDAX:
|
|
|
|
|
|
||||||
Net loss
|
$
|
(127.5
|
)
|
|
$
|
(245.9
|
)
|
|
$
|
(68.3
|
)
|
(Gain) loss on commodity derivative instruments
|
3.9
|
|
|
125.7
|
|
|
(203.2
|
)
|
|||
Net settlements on commodity derivative instruments
|
13.3
|
|
|
208.1
|
|
|
238.9
|
|
|||
Non-cash stock-based compensation
|
19.4
|
|
|
19.5
|
|
|
20.1
|
|
|||
Interest expense, net
|
76.4
|
|
|
61.0
|
|
|
42.8
|
|
|||
Income tax benefit
|
(211.9
|
)
|
|
(147.2
|
)
|
|
(38.3
|
)
|
|||
Impairment of properties and equipment
|
285.9
|
|
|
10.0
|
|
|
161.6
|
|
|||
Impairment of goodwill
|
75.1
|
|
|
—
|
|
|
—
|
|
|||
Exploration, geologic, and geophysical expense
|
47.3
|
|
|
4.7
|
|
|
1.1
|
|
|||
Depreciation, depletion, and amortization
|
469.1
|
|
|
416.9
|
|
|
303.3
|
|
|||
Accretion of asset retirement obligations
|
6.4
|
|
|
7.0
|
|
|
6.3
|
|
|||
Loss on extinguishment of debt
|
24.7
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDAX
|
$
|
682.1
|
|
|
$
|
459.8
|
|
|
$
|
464.3
|
|
|
|
|
|
|
|
||||||
Cash from operating activities to adjusted EBITDAX:
|
|
|
|
|
|
||||||
Net cash from operating activities
|
$
|
588.6
|
|
|
$
|
486.3
|
|
|
$
|
411.1
|
|
Interest expense, net
|
76.4
|
|
|
61.0
|
|
|
42.8
|
|
|||
Amortization of debt discount and issuance costs
|
(12.9
|
)
|
|
(16.2
|
)
|
|
(7.0
|
)
|
|||
Gain on sale of properties and equipment
|
0.7
|
|
|
—
|
|
|
0.4
|
|
|||
Exploration, geologic, and geophysical expense
|
47.3
|
|
|
4.7
|
|
|
1.1
|
|
|||
Exploratory dry hole expense
|
(41.3
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
29.8
|
|
|
(56.5
|
)
|
|
6.2
|
|
|||
Changes in assets and liabilities
|
(6.5
|
)
|
|
(19.5
|
)
|
|
9.7
|
|
|||
Adjusted EBITDAX
|
$
|
682.1
|
|
|
$
|
459.8
|
|
|
$
|
464.3
|
|
|
|
|
|
|
|
||||||
PV-10:
|
|
|
|
|
|
||||||
PV-10
|
$
|
3,212.0
|
|
|
$
|
1,675.0
|
|
|
$
|
1,337.5
|
|
Present value of estimated future income tax discounted at 10%
|
(331.9
|
)
|
|
(254.4
|
)
|
|
(240.6
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
2,880.1
|
|
|
$
|
1,420.6
|
|
|
$
|
1,096.9
|
|
(1)
|
Approximately ten percent of the fair value of our commodity derivative assets and 11
percent
of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).
|
(2)
|
These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month (the "trade month roll").
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Average NYMEX Index Price:
|
|
|
|
||||
Crude oil (per Bbl)
|
|
|
|
||||
NYMEX
|
$
|
50.95
|
|
|
$
|
43.32
|
|
Natural gas (per MMBtu)
|
|
|
|
||||
NYMEX
|
$
|
3.11
|
|
|
$
|
2.46
|
|
|
|
|
|
||||
Average Sales Price Realized:
|
|
|
|
||||
Excluding net settlements on commodity derivatives
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
48.45
|
|
|
$
|
39.96
|
|
Natural gas (per Mcf)
|
2.21
|
|
|
1.77
|
|
||
NGLs (per Bbl)
|
18.59
|
|
|
11.80
|
|
Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
|
||
|
|
|
Financial Statements:
|
|
|
|
||
|
||
Consolidated Statements of Operations - Years Ended December 31, 2
017, 2016, and 2015
|
|
|
Consolidated Statements of Cash Flows - Years Ended December 31, 201
7, 2016, and 2015
|
|
|
Consolidated Statements of Equity - Years Ended December 31, 201
7, 2016, and 2015
|
|
|
|
||
|
|
|
Supplemental Information - Unaudited:
|
|
|
|
||
|
||
|
|
|
Financial Statement Schedule:
|
|
|
Schedule II - Valuation and Qualifying Accounts
- Years Ended December 31, 2017, 2016, and 2015
|
|
|
|
|
|
As of December 31,
|
|
2017
|
|
2016
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
180,675
|
|
|
$
|
244,100
|
|
Accounts receivable, net
|
|
197,598
|
|
|
143,392
|
|
||
Fair value of derivatives
|
|
14,338
|
|
|
8,791
|
|
||
Prepaid expenses and other current assets
|
|
8,613
|
|
|
3,542
|
|
||
Total current assets
|
|
401,224
|
|
|
399,825
|
|
||
Properties and equipment, net
|
|
3,933,467
|
|
|
4,002,994
|
|
||
Assets held-for-sale, net
|
|
40,084
|
|
|
5,272
|
|
||
Fair value of derivatives
|
|
—
|
|
|
2,386
|
|
||
Goodwill
|
|
—
|
|
|
62,041
|
|
||
Other assets
|
|
45,116
|
|
|
13,324
|
|
||
Total Assets
|
|
$
|
4,419,891
|
|
|
$
|
4,485,842
|
|
|
|
|
|
|
||||
Liabilities and Stockholders' Equity
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
150,067
|
|
|
$
|
66,322
|
|
Production tax liability
|
|
37,654
|
|
|
24,767
|
|
||
Fair value of derivatives
|
|
79,302
|
|
|
53,595
|
|
||
Funds held for distribution
|
|
95,811
|
|
|
71,339
|
|
||
Accrued interest payable
|
|
11,815
|
|
|
15,930
|
|
||
Other accrued expenses
|
|
42,987
|
|
|
38,625
|
|
||
Total current liabilities
|
|
417,636
|
|
|
270,578
|
|
||
Long-term debt
|
|
1,151,932
|
|
|
1,043,954
|
|
||
Deferred income taxes
|
|
191,992
|
|
|
400,867
|
|
||
Asset retirement obligations
|
|
71,006
|
|
|
82,612
|
|
||
Fair value of derivatives
|
|
22,343
|
|
|
27,595
|
|
||
Other liabilities
|
|
57,333
|
|
|
37,482
|
|
||
Total liabilities
|
|
1,912,242
|
|
|
1,863,088
|
|
||
|
|
|
|
|
||||
Commitments and contingent liabilities
|
|
|
|
|
||||
|
|
|
|
|
||||
Stockholders' equity
|
|
|
|
|
||||
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,955,080 and 65,704,568 issued as of December 31, 2017 and 2016, respectively
|
|
659
|
|
|
657
|
|
||
Additional paid-in capital
|
|
2,503,294
|
|
|
2,489,557
|
|
||
Retained earnings
|
|
6,704
|
|
|
134,208
|
|
||
Treasury shares - at cost, 55,927 and 28,763 as of December 31, 2017 and 2016, respectively
|
|
(3,008
|
)
|
|
(1,668
|
)
|
||
Total stockholders' equity
|
|
2,507,649
|
|
|
2,622,754
|
|
||
Total Liabilities and Stockholders' Equity
|
|
$
|
4,419,891
|
|
|
$
|
4,485,842
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Crude oil, natural gas, and NGLs sales
|
|
$
|
913,084
|
|
|
$
|
497,353
|
|
|
$
|
378,713
|
|
Commodity price risk management gain (loss), net
|
|
(3,936
|
)
|
|
(125,681
|
)
|
|
203,183
|
|
|||
Other income
|
|
12,468
|
|
|
11,243
|
|
|
13,430
|
|
|||
Total revenues
|
|
921,616
|
|
|
382,915
|
|
|
595,326
|
|
|||
Costs, expenses and other
|
|
|
|
|
|
|
||||||
Lease operating expenses
|
|
89,641
|
|
|
59,950
|
|
|
56,992
|
|
|||
Production taxes
|
|
60,717
|
|
|
31,410
|
|
|
18,443
|
|
|||
Transportation, gathering, and processing expenses
|
|
33,220
|
|
|
18,415
|
|
|
10,151
|
|
|||
Exploration, geologic, and geophysical expense
|
|
47,334
|
|
|
4,669
|
|
|
1,102
|
|
|||
Impairment of properties and equipment
|
|
285,887
|
|
|
9,973
|
|
|
161,620
|
|
|||
Impairment of goodwill
|
|
75,121
|
|
|
—
|
|
|
—
|
|
|||
General and administrative expense
|
|
120,370
|
|
|
112,470
|
|
|
89,959
|
|
|||
Depreciation, depletion and amortization
|
|
469,084
|
|
|
416,874
|
|
|
303,258
|
|
|||
Provision for uncollectible notes receivable
|
|
(40,203
|
)
|
|
44,038
|
|
|
—
|
|
|||
Accretion of asset retirement obligations
|
|
6,306
|
|
|
7,080
|
|
|
6,293
|
|
|||
Gain on sale of properties and equipment
|
|
(766
|
)
|
|
(43
|
)
|
|
(385
|
)
|
|||
Other expenses
|
|
13,157
|
|
|
10,193
|
|
|
11,717
|
|
|||
Total costs, expenses and other
|
|
1,159,868
|
|
|
715,029
|
|
|
659,150
|
|
|||
Loss from operations
|
|
(238,252
|
)
|
|
(332,114
|
)
|
|
(63,824
|
)
|
|||
Loss on extinguishment of debt
|
|
(24,747
|
)
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
|
(78,694
|
)
|
|
(61,972
|
)
|
|
(47,571
|
)
|
|||
Interest income
|
|
2,261
|
|
|
963
|
|
|
4,807
|
|
|||
Loss before income taxes
|
|
(339,432
|
)
|
|
(393,123
|
)
|
|
(106,588
|
)
|
|||
Income tax benefit
|
|
211,928
|
|
|
147,195
|
|
|
38,308
|
|
|||
Net loss
|
|
$
|
(127,504
|
)
|
|
$
|
(245,928
|
)
|
|
$
|
(68,280
|
)
|
|
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(1.94
|
)
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
Diluted
|
|
$
|
(1.94
|
)
|
|
$
|
(5.01
|
)
|
|
$
|
(1.74
|
)
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
||||||
Basic
|
|
65,837
|
|
|
49,052
|
|
|
39,153
|
|
|||
Diluted
|
|
65,837
|
|
|
49,052
|
|
|
39,153
|
|
|||
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Net loss
|
|
$
|
(127,504
|
)
|
|
$
|
(245,928
|
)
|
|
$
|
(68,280
|
)
|
Adjustments to net loss to reconcile to net cash from operating activities:
|
|
|
|
|
|
|
||||||
Net change in fair value of unsettled commodity derivatives
|
|
17,260
|
|
|
333,770
|
|
|
35,791
|
|
|||
Depreciation, depletion and amortization
|
|
469,084
|
|
|
416,874
|
|
|
303,258
|
|
|||
Provision for uncollectible notes receivable
|
|
(40,203
|
)
|
|
44,038
|
|
|
—
|
|
|||
Impairment of properties and equipment
|
|
285,887
|
|
|
9,973
|
|
|
161,620
|
|
|||
Impairment of goodwill
|
|
75,121
|
|
|
—
|
|
|
—
|
|
|||
Exploratory dry hole costs
|
|
41,297
|
|
|
—
|
|
|
—
|
|
|||
Loss on extinguishment of debt
|
|
24,747
|
|
|
—
|
|
|
—
|
|
|||
Accretion of asset retirement obligations
|
|
6,306
|
|
|
7,080
|
|
|
6,293
|
|
|||
Non-cash stock-based compensation
|
|
19,353
|
|
|
19,502
|
|
|
20,068
|
|
|||
Gain on sale of properties and equipment
|
|
(766
|
)
|
|
(43
|
)
|
|
(385
|
)
|
|||
Amortization of debt discount and issuance costs
|
|
12,907
|
|
|
16,167
|
|
|
7,040
|
|
|||
Deferred income taxes
|
|
(203,685
|
)
|
|
(137,249
|
)
|
|
(41,415
|
)
|
|||
Other
|
|
2,265
|
|
|
2,603
|
|
|
(3,216
|
)
|
|||
Total adjustments to net loss to reconcile to net cash from operating activities:
|
|
709,573
|
|
|
712,715
|
|
|
489,054
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
(60,546
|
)
|
|
(32,627
|
)
|
|
24,815
|
|
|||
Other assets
|
|
(5,886
|
)
|
|
2,303
|
|
|
(2,264
|
)
|
|||
Production tax liability
|
|
31,316
|
|
|
9,223
|
|
|
(1,629
|
)
|
|||
Accounts payable and accrued expenses
|
|
31,378
|
|
|
(162
|
)
|
|
(30,310
|
)
|
|||
Funds held for future distribution
|
|
24,472
|
|
|
36,510
|
|
|
2,699
|
|
|||
Asset retirement obligations
|
|
(10,176
|
)
|
|
(4,109
|
)
|
|
(4,458
|
)
|
|||
Other liabilities
|
|
(4,064
|
)
|
|
8,338
|
|
|
1,446
|
|
|||
Total changes in assets and liabilities
|
|
6,494
|
|
|
19,476
|
|
|
(9,701
|
)
|
|||
Net cash from operating activities
|
|
588,563
|
|
|
486,263
|
|
|
411,073
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures for development of crude oil and natural gas properties
|
|
(737,208
|
)
|
|
(436,884
|
)
|
|
(599,546
|
)
|
|||
Capital expenditures for other properties and equipment
|
|
(5,094
|
)
|
|
(3,464
|
)
|
|
(5,122
|
)
|
|||
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition
|
|
(15,628
|
)
|
|
(1,073,723
|
)
|
|
—
|
|
|||
Proceeds from sale of properties and equipment
|
|
9,991
|
|
|
4,945
|
|
|
405
|
|
|||
Sale of promissory note
|
|
40,203
|
|
|
—
|
|
|
—
|
|
|||
Restricted cash
|
|
(9,250
|
)
|
|
—
|
|
|
—
|
|
|||
Sale of short-term investments
|
|
49,890
|
|
|
—
|
|
|
—
|
|
|||
Purchase of short-term investments
|
|
(49,890
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash from investing activities
|
|
(716,986
|
)
|
|
(1,509,126
|
)
|
|
(604,263
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from issuance of equity, net of issuance costs
|
|
—
|
|
|
855,074
|
|
|
202,851
|
|
|||
Proceeds from issuance of senior notes
|
|
592,366
|
|
|
392,172
|
|
|
—
|
|
|||
Proceeds from issuance of convertible senior notes
|
|
—
|
|
|
193,935
|
|
|
—
|
|
|||
Proceeds from revolving credit facility
|
|
—
|
|
|
85,000
|
|
|
397,000
|
|
|||
Repayment of revolving credit facility
|
|
—
|
|
|
(122,000
|
)
|
|
(416,000
|
)
|
|||
Redemption of senior notes
|
|
(519,375
|
)
|
|
—
|
|
|
—
|
|
|||
Redemption of convertible notes
|
|
—
|
|
|
(115,000
|
)
|
|
—
|
|
|||
Payment of debt issuance costs
|
|
(50
|
)
|
|
(15,556
|
)
|
|
(974
|
)
|
|||
Purchase of treasury shares
|
|
(6,672
|
)
|
|
(6,935
|
)
|
|
(6,055
|
)
|
|||
Other
|
|
(1,271
|
)
|
|
(577
|
)
|
|
1,152
|
|
|||
Net cash from financing activities
|
|
64,998
|
|
|
1,266,113
|
|
|
177,974
|
|
|||
Net change in cash and cash equivalents
|
|
(63,425
|
)
|
|
243,250
|
|
|
(15,216
|
)
|
|||
Cash and cash equivalents, beginning of year
|
|
244,100
|
|
|
850
|
|
|
16,066
|
|
|||
Cash and cash equivalents, end of year
|
|
$
|
180,675
|
|
|
$
|
244,100
|
|
|
$
|
850
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
Treasury Stock
|
|
|
|
|
||||||||||||||||
|
Shares
|
|
Amount
|
|
Additional Paid-in Capital
|
|
Shares
|
|
Amount
|
|
Retained Earnings
|
|
Total Stockholders' Equity
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Balances, January 1, 2015
|
35,927,985
|
|
|
$
|
359
|
|
|
$
|
689,209
|
|
|
(21,643
|
)
|
|
$
|
(911
|
)
|
|
$
|
448,702
|
|
|
$
|
1,137,359
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(68,280
|
)
|
|
(68,280
|
)
|
|||||
Issuance pursuant to sale of equity
|
4,002,000
|
|
|
40
|
|
|
202,811
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
202,851
|
|
|||||
Purchase of treasury shares
|
—
|
|
|
—
|
|
|
—
|
|
|
(120,864
|
)
|
|
(6,055
|
)
|
|
—
|
|
|
(6,055
|
)
|
|||||
Issuance of treasury shares
|
—
|
|
|
—
|
|
|
(6,206
|
)
|
|
127,159
|
|
|
6,206
|
|
|
—
|
|
|
—
|
|
|||||
Non-employee directors' deferred compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,872
|
)
|
|
(249
|
)
|
|
—
|
|
|
(249
|
)
|
|||||
Issuance of stock awards, net of forfeitures
|
244,791
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Stock-based compensation expense, including tax impact
|
—
|
|
|
—
|
|
|
21,568
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,568
|
|
|||||
Balances, December 31, 2015
|
40,174,776
|
|
|
$
|
402
|
|
|
$
|
907,382
|
|
|
(20,220
|
)
|
|
$
|
(1,009
|
)
|
|
$
|
380,422
|
|
|
$
|
1,287,197
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(245,928
|
)
|
|
(245,928
|
)
|
|||||
Issuance pursuant to acquisition
|
9,386,768
|
|
|
94
|
|
|
690,608
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
690,702
|
|
|||||
Issuance pursuant to sale of equity
|
15,007,500
|
|
|
150
|
|
|
854,933
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
855,083
|
|
|||||
Convertible debt discount, net of issuance costs and tax
|
—
|
|
|
—
|
|
|
23,518
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,518
|
|
|||||
Purchase of treasury shares
|
—
|
|
|
—
|
|
|
—
|
|
|
(116,085
|
)
|
|
(6,935
|
)
|
|
—
|
|
|
(6,935
|
)
|
|||||
Issuance pursuant to note conversion
|
792,406
|
|
|
8
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Issuance of treasury shares
|
(114,697
|
)
|
|
|
|
(6,661
|
)
|
|
114,697
|
|
|
6,661
|
|
|
—
|
|
|
—
|
|
||||||
Non-employee directors' deferred compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,155
|
)
|
|
(385
|
)
|
|
—
|
|
|
(385
|
)
|
|||||
Issuance of stock awards, net of forfeitures
|
411,731
|
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Exercise of stock options
|
46,084
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
19,502
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,502
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
286
|
|
|
—
|
|
|
—
|
|
|
(286
|
)
|
|
—
|
|
|||||
Balances, December 31, 2016
|
65,704,568
|
|
|
$
|
657
|
|
|
$
|
2,489,557
|
|
|
(28,763
|
)
|
|
$
|
(1,668
|
)
|
|
$
|
134,208
|
|
|
$
|
2,622,754
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(127,504
|
)
|
|
(127,504
|
)
|
|||||
Purchase of treasury shares
|
—
|
|
|
—
|
|
|
—
|
|
|
(107,357
|
)
|
|
(6,672
|
)
|
|
—
|
|
|
(6,672
|
)
|
|||||
Issuance of treasury shares
|
—
|
|
|
—
|
|
|
(5,517
|
)
|
|
83,228
|
|
|
5,517
|
|
|
—
|
|
|
—
|
|
|||||
Non-employee directors' deferred compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,035
|
)
|
|
(185
|
)
|
|
—
|
|
|
(185
|
)
|
|||||
Issuance of stock awards, net of forfeitures
|
250,512
|
|
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Stock-based compensation expense
|
—
|
|
|
—
|
|
|
19,353
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,353
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
(97
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(97
|
)
|
|||||
Balance, December 31, 2017
|
65,955,080
|
|
|
$
|
659
|
|
|
$
|
2,503,294
|
|
|
(55,927
|
)
|
|
$
|
(3,008
|
)
|
|
$
|
6,704
|
|
|
$
|
2,507,649
|
|
Transportation, pipeline, and other equipment
|
2 - 30 years
|
Buildings
|
20 - 40 years
|
|
Year Ended December 31, 2016
|
||
Acquisition costs:
|
|
||
Cash, net of cash acquired
|
$
|
905,962
|
|
Retirement of seller's debt
|
40,000
|
|
|
Total cash consideration
|
945,962
|
|
|
Common stock
|
690,702
|
|
|
Other purchase price adjustments
|
426
|
|
|
Total acquisition costs
|
$
|
1,637,090
|
|
|
|
||
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
||
Assets acquired:
|
|
||
Current Assets
|
$
|
6,401
|
|
Crude oil and natural gas properties - proved
|
216,000
|
|
|
Crude oil and natural gas properties - unproved
|
1,697,000
|
|
|
Infrastructure, pipeline, and other
|
33,153
|
|
|
Construction in progress
|
12,323
|
|
|
Goodwill
|
75,121
|
|
|
Total assets acquired
|
2,039,998
|
|
|
Liabilities assumed:
|
|
||
Current liabilities
|
(24,496
|
)
|
|
Asset retirement obligations
|
(3,705
|
)
|
|
Deferred tax liabilities, net
|
(374,707
|
)
|
|
Total liabilities assumed
|
(402,908
|
)
|
|
Total identifiable net assets acquired
|
$
|
1,637,090
|
|
|
Years Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands, except per share amounts)
|
||||||
Total revenue
|
$
|
412,746
|
|
|
$
|
598,932
|
|
Net loss
|
$
|
(270,942
|
)
|
|
$
|
(138,904
|
)
|
|
|
|
|
||||
Earnings per share:
|
|
|
|
||||
Basic and diluted
|
$
|
(4.22
|
)
|
|
$
|
(2.41
|
)
|
|
Amount
|
||
|
(in thousands)
|
||
|
|
||
Preliminary purchase price allocation
|
$
|
62,041
|
|
Adjustments
|
13,080
|
|
|
Final purchase price allocation
|
$
|
75,121
|
|
|
As of December 31,
|
||||||||||||||||||||||
|
2017
|
|
2016
|
||||||||||||||||||||
|
Significant Other
Observable Inputs (Level 2) |
|
Significant
Unobservable Inputs (Level 3) |
|
Total
|
|
Significant Other
Observable Inputs (Level 2) |
|
Significant
Unobservable Inputs (Level 3) |
|
Total
|
||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
Total assets
|
$
|
12,949
|
|
|
$
|
1,389
|
|
|
$
|
14,338
|
|
|
$
|
6,350
|
|
|
$
|
4,827
|
|
|
$
|
11,177
|
|
Total liabilities
|
90,569
|
|
|
11,076
|
|
|
101,645
|
|
|
66,789
|
|
|
14,401
|
|
|
81,190
|
|
||||||
Net liability
|
$
|
(77,620
|
)
|
|
$
|
(9,687
|
)
|
|
$
|
(87,307
|
)
|
|
$
|
(60,439
|
)
|
|
$
|
(9,574
|
)
|
|
$
|
(70,013
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Fair value of Level 3 instruments, net asset (liability) beginning of period
|
|
$
|
(9,574
|
)
|
|
$
|
91,288
|
|
|
$
|
62,356
|
|
Changes in fair value included in consolidated statements of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
6,241
|
|
|
(28,550
|
)
|
|
65,164
|
|
|||
Settlements included in consolidated statements of operations line items:
|
|
|
|
|
|
|
||||||
Commodity price risk management (
loss)
, net
|
|
(6,354
|
)
|
|
(72,312
|
)
|
|
(36,232
|
)
|
|||
Fair value of Level 3 instruments, net asset (liability) end of period
|
|
$
|
(9,687
|
)
|
|
$
|
(9,574
|
)
|
|
$
|
91,288
|
|
|
|
|
|
|
|
|
||||||
Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
$
|
(866
|
)
|
|
$
|
(12,905
|
)
|
|
$
|
43,540
|
|
Total
|
|
$
|
(866
|
)
|
|
$
|
(12,905
|
)
|
|
$
|
43,540
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
% of Par
|
|||
|
(in millions)
|
|
|
|||
Senior notes:
|
|
|
|
|||
2021 Convertible Notes
|
$
|
195.6
|
|
|
97.8
|
%
|
2024 Senior Notes
|
416.0
|
|
|
104.0
|
%
|
|
2026 Senior Notes
|
616.5
|
|
|
102.8
|
%
|
•
|
Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;
|
•
|
Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty;
|
•
|
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. See
Item 7a. - Quantitative and Qualitative Disclosures About Market Risk - Derivative Positions Table
found elsewhere in this report for a detailed list of our basis protection swaps.
|
Derivative instruments:
|
|
Consolidated balance sheet line item
|
|
2017
|
|
2016
|
|||||
|
|
|
|
|
(in thousands)
|
||||||
Derivative assets:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts
|
|
Fair value of derivatives
|
|
$
|
7,340
|
|
|
$
|
8,490
|
|
|
Basis protection derivative contracts
|
|
Fair value of derivatives
|
|
6,998
|
|
|
301
|
|
||
|
|
|
|
|
14,338
|
|
|
8,791
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts
|
|
Fair value of derivatives
|
|
—
|
|
|
1,123
|
|
||
|
Basis protection derivative contracts
|
|
Fair value of derivatives
|
|
—
|
|
|
1,263
|
|
||
|
|
|
|
|
—
|
|
|
2,386
|
|
||
Total derivative assets
|
|
|
|
|
$
|
14,338
|
|
|
$
|
11,177
|
|
|
|
|
|
|
|
|
|
||||
Derivative liabilities:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts
|
|
Fair value of derivatives
|
|
$
|
77,999
|
|
|
53,565
|
|
|
|
Basis protection derivative contracts
|
|
Fair value of derivatives
|
|
234
|
|
|
30
|
|
||
|
Rollfactor derivative contracts
|
|
Fair value of derivatives
|
|
1,069
|
|
|
—
|
|
||
|
|
|
|
|
79,302
|
|
|
53,595
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity derivative contracts
|
|
Fair value of derivatives
|
|
22,343
|
|
|
27,595
|
|
||
Total derivative liabilities
|
|
|
|
|
$
|
101,645
|
|
|
$
|
81,190
|
|
|
|
Year Ended December 31,
|
||||||||||
Consolidated statements of operations line item
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Commodity price risk management gain (loss), net
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
13,324
|
|
|
$
|
208,103
|
|
|
$
|
238,935
|
|
Net change in fair value of unsettled derivatives
|
|
(17,260
|
)
|
|
(333,784
|
)
|
|
(35,752
|
)
|
|||
Total commodity price risk management gain (loss), net
|
|
$
|
(3,936
|
)
|
|
$
|
(125,681
|
)
|
|
$
|
203,183
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
Derivative instruments, gross
|
|
Effect of master netting agreements
|
|
Derivative instruments, net
|
||||||
|
|
(in thousands)
|
||||||||||
Asset derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
14,338
|
|
|
$
|
(14,173
|
)
|
|
$
|
165
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
101,645
|
|
|
$
|
(14,173
|
)
|
|
$
|
87,472
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
Derivative instruments, gross
|
|
Effect of master netting agreements
|
|
Derivative instruments, net
|
||||||
|
|
(in thousands)
|
||||||||||
Asset derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
11,177
|
|
|
$
|
(10,930
|
)
|
|
$
|
247
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
81,190
|
|
|
$
|
(10,930
|
)
|
|
$
|
70,260
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Crude oil, natural gas, and NGLs sales
|
$
|
154,260
|
|
|
$
|
97,520
|
|
Joint interest billings (1)
|
34,576
|
|
|
20,118
|
|
||
Derivative counterparties
|
(18
|
)
|
|
10,266
|
|
||
Income tax receivable
|
6,015
|
|
|
11,505
|
|
||
Other
|
5,893
|
|
|
6,173
|
|
||
Allowance for doubtful accounts
|
(3,128
|
)
|
|
(2,190
|
)
|
||
Accounts receivable, net
|
$
|
197,598
|
|
|
$
|
143,392
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
Customer
|
|
2017
|
|
2016
|
|
2015
|
|||
|
|
|
|
|
|
|
|||
DCP Midstream, LP
|
|
19.6
|
%
|
|
20.2
|
%
|
|
13.2
|
%
|
Suncor Energy Marketing, Inc.
|
|
16.4
|
%
|
|
22.3
|
%
|
|
14.3
|
%
|
Aka Energy Group, LLC
|
|
—
|
%
|
|
13.4
|
%
|
|
—
|
%
|
Concord Energy, LLC
|
|
—
|
%
|
|
13.4
|
%
|
|
23.2
|
%
|
Bridger Energy, LLC
|
|
—
|
%
|
|
11.5
|
%
|
|
—
|
%
|
Shell Trading Company
|
|
—
|
%
|
|
—
|
%
|
|
13.8
|
%
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Employee benefits
|
$
|
22,383
|
|
|
$
|
22,282
|
|
Asset retirement obligations
|
15,801
|
|
|
9,775
|
|
||
Environmental expenses
|
1,374
|
|
|
3,238
|
|
||
Other
|
3,429
|
|
|
3,330
|
|
||
Other accrued expenses
|
$
|
42,987
|
|
|
$
|
38,625
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
Properties and equipment, net:
|
|
|
|
||||
Crude oil and natural gas properties
|
|
|
|
||||
Proved
|
$
|
4,356,922
|
|
|
$
|
3,499,718
|
|
Unproved
|
1,097,317
|
|
|
1,874,671
|
|
||
Total crude oil and natural gas properties
|
5,454,239
|
|
|
5,374,389
|
|
||
Infrastructure, pipeline, and other
|
109,359
|
|
|
62,093
|
|
||
Land and buildings
|
10,960
|
|
|
6,392
|
|
||
Construction in progress
|
196,024
|
|
|
122,591
|
|
||
Properties and equipment, at cost
|
5,770,582
|
|
|
5,565,465
|
|
||
Accumulated DD&A
|
(1,837,115
|
)
|
|
(1,562,471
|
)
|
||
Properties and equipment, net
|
$
|
3,933,467
|
|
|
$
|
4,002,994
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in thousands)
|
||||||
Assets
|
|
|
|
||||
Properties and equipment, net
|
$
|
40,583
|
|
|
$
|
5,272
|
|
Total assets
|
$
|
40,583
|
|
|
$
|
5,272
|
|
|
|
|
|
||||
Liabilities
|
|
|
|
||||
Asset retirement obligation
|
$
|
499
|
|
|
$
|
—
|
|
Total liabilities
|
$
|
499
|
|
|
$
|
—
|
|
|
|
|
|
||||
Net assets
|
$
|
40,084
|
|
|
$
|
5,272
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
$
|
285,465
|
|
|
$
|
5,562
|
|
|
$
|
154,608
|
|
Amortization of individually insignificant unproved properties
|
422
|
|
|
1,379
|
|
|
7,012
|
|
|||
Land and buildings
|
—
|
|
|
3,032
|
|
|
—
|
|
|||
Total impairment of properties and equipment
|
$
|
285,887
|
|
|
$
|
9,973
|
|
|
$
|
161,620
|
|
|
|
|
|
|
|
|
2017
|
||
|
(in thousands, except for number of wells)
|
||
|
|
||
Beginning balance
|
$
|
—
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
51,776
|
|
|
Reclassifications to proved properties
|
(36,328
|
)
|
|
Balance at December 31,
|
$
|
15,448
|
|
|
|
||
Number of wells pending determination at December 31,
|
3
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Exploratory dry hole costs
|
$
|
41,297
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Geological and geophysical costs, including seismic purchases
|
3,881
|
|
|
3,472
|
|
|
—
|
|
|||
Operating, personnel and other
|
2,156
|
|
|
1,197
|
|
|
1,102
|
|
|||
Total exploration, geologic, and geophysical expense
|
$
|
47,334
|
|
|
$
|
4,669
|
|
|
$
|
1,102
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
Senior notes:
|
|
|
|
||||
1.125% Convertible Notes due 2021:
|
|
|
|
||||
Principal amount
|
$
|
200,000
|
|
|
$
|
200,000
|
|
Unamortized discount
|
(30,328
|
)
|
|
(37,475
|
)
|
||
Unamortized debt issuance costs
|
(3,615
|
)
|
|
(4,584
|
)
|
||
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs
|
166,057
|
|
|
157,941
|
|
||
|
|
|
|
||||
6.125% Senior Notes due 2024:
|
|
|
|
||||
Principal amount
|
400,000
|
|
|
400,000
|
|
||
Unamortized debt issuance costs
|
(6,570
|
)
|
|
(7,544
|
)
|
||
6.125% Senior Notes due 2024, net of unamortized debt issuance costs
|
393,430
|
|
|
392,456
|
|
||
|
|
|
|
||||
5.75% Senior Notes due 2026:
|
|
|
|
||||
Principal amount
|
600,000
|
|
|
—
|
|
||
Unamortized debt issuance costs
|
(7,555
|
)
|
|
—
|
|
||
5.75% Senior Notes due 2026, net of unamortized debt issuance costs
|
592,445
|
|
|
—
|
|
||
|
|
|
|
||||
7.75% Senior notes redeemed 2017:
|
|
|
|
||||
Principal amount
|
—
|
|
|
500,000
|
|
||
Unamortized debt issuance costs
|
—
|
|
|
(6,443
|
)
|
||
7.75% Senior notes redeemed 2017, net of unamortized debt issuance costs
|
—
|
|
|
493,557
|
|
||
|
|
|
|
||||
Total senior notes
|
1,151,932
|
|
|
1,043,954
|
|
||
|
|
|
|
||||
Revolving credit facility
|
—
|
|
|
—
|
|
||
Total long-term debt, net of unamortized discount and debt issuance costs
|
1,151,932
|
|
|
1,043,954
|
|
||
Less current portion of long-term debt
|
—
|
|
|
—
|
|
||
Long-term debt
|
$
|
1,151,932
|
|
|
$
|
1,043,954
|
|
|
|
As of December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
|
|
(in thousands)
|
||||||
Vehicles
|
|
$
|
6,249
|
|
|
$
|
2,975
|
|
Accumulated depreciation
|
|
(1,882
|
)
|
|
(776
|
)
|
||
|
|
$
|
4,367
|
|
|
$
|
2,199
|
|
For the Twelve Months Ending December 31,
|
|
Amount
|
||
|
|
(in thousands)
|
||
2018
|
|
$
|
2,075
|
|
2019
|
|
1,623
|
|
|
2020
|
|
1,507
|
|
|
|
|
5,205
|
|
|
Less executory cost
|
|
(235
|
)
|
|
Less amount representing interest
|
|
(537
|
)
|
|
Present value of minimum lease payments
|
|
$
|
4,433
|
|
|
|
|
|
|
Short-term capital lease obligations
|
|
$
|
1,672
|
|
Long-term capital lease obligations
|
|
2,761
|
|
|
|
|
$
|
4,433
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
8,443
|
|
|
$
|
9,646
|
|
|
$
|
(2,944
|
)
|
State
|
(200
|
)
|
|
300
|
|
|
(163
|
)
|
|||
Total current income tax (expense) benefit
|
8,243
|
|
|
9,946
|
|
|
(3,107
|
)
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
193,809
|
|
|
118,427
|
|
|
37,352
|
|
|||
State
|
9,876
|
|
|
18,822
|
|
|
4,063
|
|
|||
Total deferred income tax benefit
|
203,685
|
|
|
137,249
|
|
|
41,415
|
|
|||
Income tax benefit from continuing operations
|
$
|
211,928
|
|
|
$
|
147,195
|
|
|
$
|
38,308
|
|
|
Year Ended December, 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
|
|
|
|
|
|
|||
Statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State income tax, net
|
1.8
|
|
|
2.6
|
|
|
2.7
|
|
Effect of state income tax rate changes
|
—
|
|
|
0.6
|
|
|
(0.3
|
)
|
Percentage depletion
|
—
|
|
|
—
|
|
|
0.3
|
|
Non-deductible compensation
|
(0.3
|
)
|
|
(0.5
|
)
|
|
(1.2
|
)
|
Federal tax reform rate reduction
|
33.7
|
|
|
—
|
|
|
—
|
|
Non-deductible goodwill impairment
|
(7.7
|
)
|
|
—
|
|
|
—
|
|
Other
|
(0.1
|
)
|
|
(0.3
|
)
|
|
(0.6
|
)
|
Effective tax rate
|
62.4
|
%
|
|
37.4
|
%
|
|
35.9
|
%
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Deferred compensation
|
$
|
6,059
|
|
|
$
|
9,338
|
|
Asset retirement obligations
|
21,760
|
|
|
34,359
|
|
||
Federal NOL carryforward
|
19,386
|
|
|
29,988
|
|
||
State NOL and tax credit carryforwards, net
|
7,815
|
|
|
5,189
|
|
||
Federal tax - credit carryforwards
|
4,366
|
|
|
5,184
|
|
||
Allowance for note receivable
|
—
|
|
|
17,292
|
|
||
Net change in fair value of unsettled derivatives
|
20,929
|
|
|
26,262
|
|
||
Other
|
2,453
|
|
|
4,716
|
|
||
Total gross deferred tax assets
|
82,768
|
|
|
132,328
|
|
||
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Properties and equipment
|
267,498
|
|
|
518,964
|
|
||
Convertible debt
|
7,262
|
|
|
14,231
|
|
||
Total gross deferred tax liabilities
|
274,760
|
|
|
533,195
|
|
||
Net deferred tax liability
|
$
|
191,992
|
|
|
$
|
400,867
|
|
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Beginning balance
|
$
|
92,387
|
|
|
$
|
89,492
|
|
Obligations incurred with development activities
|
3,638
|
|
|
4,894
|
|
||
Accretion expense
|
6,306
|
|
|
7,080
|
|
||
Revisions in estimated cash flows
|
(2,860
|
)
|
|
—
|
|
||
Obligations discharged with asset retirements
|
(12,165
|
)
|
|
(9,079
|
)
|
||
Balance at December 31
|
87,306
|
|
|
92,387
|
|
||
Less liabilities held-for-sale
|
(499
|
)
|
|
—
|
|
||
Less current portion
|
(15,801
|
)
|
|
(9,775
|
)
|
||
Long-term portion
|
$
|
71,006
|
|
|
$
|
82,612
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||
Area
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022 and
Through Expiration |
|
Total
|
|
Expiration
Date |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Wattenberg Field
|
|
3,541
|
|
|
23,934
|
|
|
31,110
|
|
|
31,025
|
|
|
121,922
|
|
|
211,532
|
|
|
April 30, 2026
|
||||||
Delaware Basin
|
|
14,600
|
|
|
14,600
|
|
|
14,640
|
|
|
—
|
|
|
—
|
|
|
43,840
|
|
|
December 31, 2020
|
||||||
Gas Marketing
|
|
7,117
|
|
|
7,117
|
|
|
7,136
|
|
|
7,056
|
|
|
4,495
|
|
|
32,921
|
|
|
August 31, 2022
|
||||||
Utica Shale (1)
|
|
2,738
|
|
|
2,738
|
|
|
2,745
|
|
|
2,738
|
|
|
4,326
|
|
|
15,285
|
|
|
July 31, 2023
|
||||||
Total
|
|
27,996
|
|
|
48,389
|
|
|
55,631
|
|
|
40,819
|
|
|
130,743
|
|
|
303,578
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Wattenberg Field
|
|
3,638
|
|
|
4,239
|
|
|
1,808
|
|
|
—
|
|
|
—
|
|
|
9,685
|
|
|
June 30, 2020
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dollar commitment (in thousands)
|
|
$
|
23,176
|
|
|
$
|
43,855
|
|
|
$
|
42,496
|
|
|
$
|
33,226
|
|
|
$
|
118,927
|
|
|
$
|
261,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||||
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Minimum Lease Payments
|
|
$
|
3,865
|
|
|
$
|
3,865
|
|
|
$
|
3,932
|
|
|
$
|
3,998
|
|
|
$
|
4,078
|
|
|
$
|
3,515
|
|
|
$
|
23,253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date
|
|
Shares Issued
|
|
Price per Share
|
|
Net Proceeds
|
|||||
|
|
|
|
|
|
(in millions)
|
|||||
September 2016
|
|
9,085,000
|
|
|
$
|
61.51
|
|
|
$
|
558.5
|
|
March 2016
|
|
5,922,500
|
|
|
50.11
|
|
|
296.6
|
|
||
March 2015
|
|
4,002,000
|
|
|
50.73
|
|
|
202.9
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Stock-based compensation expense
|
|
$
|
19,353
|
|
|
$
|
19,502
|
|
|
$
|
20,068
|
|
Income tax benefit
|
|
(7,372
|
)
|
|
(7,296
|
)
|
|
(7,636
|
)
|
|||
Net stock-based compensation expense
|
|
$
|
11,981
|
|
|
$
|
12,206
|
|
|
$
|
12,432
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
|
|
||||||
Expected term of award (in years)
|
6.0 years
|
|
|
6.0 years
|
|
|
5.2 years
|
|
|||
Risk-free interest rate
|
2.0
|
%
|
|
1.8
|
%
|
|
1.4
|
%
|
|||
Expected volatility
|
53.3
|
%
|
|
54.5
|
%
|
|
58.0
|
%
|
|||
Weighted-average grant date fair value per share
|
$
|
38.58
|
|
|
$
|
26.96
|
|
|
$
|
22.23
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||||||||||||||
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Average Remaining Contractual
Term (in years) |
|
Aggregate Intrinsic
Value |
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Aggregate Intrinsic
Value |
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Aggregate Intrinsic
Value |
||||||||||||||||
Outstanding at January 1,
|
244,078
|
|
|
$
|
41.36
|
|
|
6.9
|
|
|
$
|
7,620
|
|
|
326,453
|
|
|
$
|
38.99
|
|
|
$
|
4,697
|
|
|
279,011
|
|
|
$
|
38.77
|
|
|
$
|
1,472
|
|
Awarded
|
54,142
|
|
|
74.57
|
|
|
—
|
|
|
—
|
|
|
58,709
|
|
|
51.63
|
|
|
—
|
|
|
68,274
|
|
|
39.63
|
|
|
—
|
|
||||||
Exercised
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(141,084
|
)
|
|
40.16
|
|
|
2,770
|
|
|
(20,832
|
)
|
|
38.05
|
|
|
473
|
|
||||||
Outstanding at December 31
|
298,220
|
|
|
47.39
|
|
|
6.5
|
|
|
2,490
|
|
|
244,078
|
|
|
41.36
|
|
|
7,620
|
|
|
326,453
|
|
|
38.99
|
|
|
4,697
|
|
||||||
Exercisable at December 31
|
223,865
|
|
|
43.28
|
|
|
5.9
|
|
|
2,267
|
|
|
174,919
|
|
|
38.72
|
|
|
5,924
|
|
|
222,489
|
|
|
37.70
|
|
|
3,489
|
|
|
Shares
|
|
Weighted-Average
Grant Date Fair Value per Share |
|||
|
|
|
|
|||
Non-vested at December 31, 2016
|
479,642
|
|
|
$
|
56.09
|
|
Granted
|
273,941
|
|
|
65.14
|
|
|
Vested
|
(266,809
|
)
|
|
57.67
|
|
|
Forfeited
|
(14,642
|
)
|
|
62.92
|
|
|
Non-vested at December 31, 2017
|
472,132
|
|
|
60.23
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of time-based awards vested
|
$
|
16,303
|
|
|
$
|
18,973
|
|
|
$
|
17,077
|
|
Total intrinsic value of time-based awards non-vested
|
24,334
|
|
|
34,812
|
|
|
28,029
|
|
|||
Market price per common share as of December 31,
|
51.54
|
|
|
72.58
|
|
|
53.38
|
|
|||
Weighted-average grant date fair value per share
|
65.14
|
|
|
58.52
|
|
|
48.88
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
|
|
|
|
|
||||||
Expected term of award (in years)
|
|
3 years
|
|
|
3 years
|
|
|
3 years
|
|
|||
Risk-free interest rate
|
|
1.4
|
%
|
|
1.2
|
%
|
|
0.9
|
%
|
|||
Expected volatility
|
|
51.4
|
%
|
|
52.3
|
%
|
|
53.0
|
%
|
|||
Weighted-average grant date fair value per share
|
|
$
|
94.02
|
|
|
$
|
72.54
|
|
|
$
|
66.16
|
|
|
|
Shares
|
|
Weighted-Average
Grant Date Fair Value per Share |
|||
|
|
|
|
|
|||
Non-vested at December 31, 2016
|
|
48,420
|
|
|
$
|
64.97
|
|
Granted
|
|
28,069
|
|
|
94.02
|
|
|
Vested
|
|
(24,140
|
)
|
|
57.35
|
|
|
Non-vested at December 31, 2017
|
|
52,349
|
|
|
84.06
|
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of market-based awards vested
|
$
|
2,687
|
|
|
$
|
6,562
|
|
|
$
|
4,293
|
|
Total intrinsic value of market-based awards non-vested
|
2,698
|
|
|
3,514
|
|
|
3,819
|
|
|||
Market price per common share as of December 31,
|
51.54
|
|
|
72.58
|
|
|
53.38
|
|
|||
Weighted-average grant date fair value per share
|
94.02
|
|
|
72.54
|
|
|
66.16
|
|
|
Year Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common shares outstanding - basic
|
65,837
|
|
|
49,052
|
|
|
39,153
|
|
Weighted-average common shares and equivalents outstanding - diluted
|
65,837
|
|
|
49,052
|
|
|
39,153
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
|
|
|
|
|
|
|||
Restricted stock
|
590
|
|
|
689
|
|
|
831
|
|
Convertible notes
|
—
|
|
|
292
|
|
|
562
|
|
Other equity-based awards
|
75
|
|
|
109
|
|
|
101
|
|
Total anti-dilutive common share equivalents
|
665
|
|
|
1,090
|
|
|
1,494
|
|
|
|
|
|
|
|
(i)
|
PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
|
(ii)
|
PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes;
|
(iii)
|
Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and
|
(iv)
|
Parent and subsidiaries on a consolidated basis ("Consolidated").
|
|
|
Consolidating Balance Sheets
|
||||||||||||||
|
|
December 31, 2017
|
||||||||||||||
|
|
Parent
|
|
Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||
|
|
(in thousands)
|
||||||||||||||
Assets
|
|
|
|
|
|
|
|
|
||||||||
Current assets:
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
|
$
|
180,675
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
180,675
|
|
Accounts receivable, net
|
|
160,490
|
|
|
37,108
|
|
|
—
|
|
|
197,598
|
|
||||
Fair value of derivatives
|
|
14,338
|
|
|
—
|
|
|
—
|
|
|
14,338
|
|
||||
Prepaid expenses and other current assets
|
|
8,284
|
|
|
329
|
|
|
—
|
|
|
8,613
|
|
||||
Total current assets
|
|
363,787
|
|
|
37,437
|
|
|
—
|
|
|
401,224
|
|
||||
Properties and equipment, net
|
|
1,891,314
|
|
|
2,042,153
|
|
|
—
|
|
|
3,933,467
|
|
||||
Assets held-for-sale, net
|
|
40,084
|
|
|
—
|
|
|
—
|
|
|
40,084
|
|
||||
Intercompany receivable
|
|
250,279
|
|
|
—
|
|
|
(250,279
|
)
|
|
—
|
|
||||
Investment in subsidiaries
|
|
1,617,537
|
|
|
—
|
|
|
(1,617,537
|
)
|
|
—
|
|
||||
Other assets
|
|
42,547
|
|
|
2,569
|
|
|
—
|
|
|
45,116
|
|
||||
Total Assets
|
|
$
|
4,205,548
|
|
|
$
|
2,082,159
|
|
|
$
|
(1,867,816
|
)
|
|
$
|
4,419,891
|
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities and Stockholders' Equity
|
|
|
|
|
|
|
|
|
||||||||
Liabilities
|
|
|
|
|
|
|
|
|
||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Accounts payable
|
|
$
|
85,000
|
|
|
$
|
65,067
|
|
|
$
|
—
|
|
|
$
|
150,067
|
|
Production tax liability
|
|
35,902
|
|
|
1,752
|
|
|
—
|
|
|
37,654
|
|
||||
Fair value of derivatives
|
|
79,302
|
|
|
—
|
|
|
—
|
|
|
79,302
|
|
||||
Funds held for distribution
|
|
83,898
|
|
|
11,913
|
|
|
—
|
|
|
95,811
|
|
||||
Accrued interest payable
|
|
11,812
|
|
|
3
|
|
|
—
|
|
|
11,815
|
|
||||
Other accrued expenses
|
|
42,543
|
|
|
444
|
|
|
—
|
|
|
42,987
|
|
||||
Total current liabilities
|
|
338,457
|
|
|
79,179
|
|
|
—
|
|
|
417,636
|
|
||||
Intercompany payable
|
|
—
|
|
|
250,279
|
|
|
(250,279
|
)
|
|
—
|
|
||||
Long-term debt
|
|
1,151,932
|
|
|
—
|
|
|
—
|
|
|
1,151,932
|
|
||||
Deferred income taxes
|
|
62,857
|
|
|
129,135
|
|
|
—
|
|
|
191,992
|
|
||||
Asset retirement obligations
|
|
65,301
|
|
|
5,705
|
|
|
—
|
|
|
71,006
|
|
||||
Fair value of derivatives
|
|
22,343
|
|
|
—
|
|
|
—
|
|
|
22,343
|
|
||||
Other liabilities
|
|
57,009
|
|
|
324
|
|
|
—
|
|
|
57,333
|
|
||||
Total liabilities
|
|
1,697,899
|
|
|
464,622
|
|
|
(250,279
|
)
|
|
1,912,242
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Stockholders' equity
|
|
|
|
|
|
|
|
|
||||||||
Common shares
|
|
659
|
|
|
—
|
|
|
—
|
|
|
659
|
|
||||
Additional paid-in capital
|
|
2,503,294
|
|
|
1,766,775
|
|
|
(1,766,775
|
)
|
|
2,503,294
|
|
||||
Retained earnings
|
|
6,704
|
|
|
(149,238
|
)
|
|
149,238
|
|
|
6,704
|
|
||||
Treasury shares
|
|
(3,008
|
)
|
|
—
|
|
|
—
|
|
|
(3,008
|
)
|
||||
Total stockholders' equity
|
|
2,507,649
|
|
|
1,617,537
|
|
|
(1,617,537
|
)
|
|
2,507,649
|
|
||||
Total Liabilities and Stockholders' Equity
|
|
$
|
4,205,548
|
|
|
$
|
2,082,159
|
|
|
$
|
(1,867,816
|
)
|
|
$
|
4,419,891
|
|
|
|
Consolidating Balance Sheets
|
||||||||||||||
|
|
December 31, 2016
|
||||||||||||||
|
|
Parent
|
|
Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||
|
|
(in thousands)
|
||||||||||||||
Assets
|
|
|
|
|
|
|
|
|
||||||||
Current assets:
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
|
$
|
240,487
|
|
|
$
|
3,613
|
|
|
$
|
—
|
|
|
$
|
244,100
|
|
Accounts receivable, net
|
|
134,589
|
|
|
8,803
|
|
|
—
|
|
|
143,392
|
|
||||
Fair value of derivatives
|
|
8,791
|
|
|
—
|
|
|
—
|
|
|
8,791
|
|
||||
Prepaid expenses and other current assets
|
|
3,442
|
|
|
100
|
|
|
—
|
|
|
3,542
|
|
||||
Total current assets
|
|
387,309
|
|
|
12,516
|
|
|
—
|
|
|
399,825
|
|
||||
Properties and equipment, net
|
|
1,884,147
|
|
|
2,118,847
|
|
|
—
|
|
|
4,002,994
|
|
||||
Assets held-for-sale, net
|
|
5,272
|
|
|
—
|
|
|
—
|
|
|
5,272
|
|
||||
Intercompany receivable
|
|
9,415
|
|
|
—
|
|
|
(9,415
|
)
|
|
—
|
|
||||
Investment in subsidiaries
|
|
1,765,092
|
|
|
—
|
|
|
(1,765,092
|
)
|
|
—
|
|
||||
Fair value of derivatives
|
|
2,386
|
|
|
—
|
|
|
—
|
|
|
2,386
|
|
||||
Goodwill
|
|
—
|
|
|
62,041
|
|
|
—
|
|
|
62,041
|
|
||||
Other assets
|
|
13,153
|
|
|
171
|
|
|
—
|
|
|
13,324
|
|
||||
Total Assets
|
|
$
|
4,066,774
|
|
|
$
|
2,193,575
|
|
|
$
|
(1,774,507
|
)
|
|
$
|
4,485,842
|
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities and Stockholders' Equity
|
|
|
|
|
|
|
|
|
||||||||
Liabilities
|
|
|
|
|
|
|
|
|
||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Accounts payable
|
|
$
|
38,748
|
|
|
$
|
27,574
|
|
|
$
|
—
|
|
|
$
|
66,322
|
|
Production tax liability
|
|
24,401
|
|
|
366
|
|
|
—
|
|
|
24,767
|
|
||||
Fair value of derivatives
|
|
53,595
|
|
|
—
|
|
|
—
|
|
|
53,595
|
|
||||
Funds held for distribution
|
|
65,022
|
|
|
6,317
|
|
|
—
|
|
|
71,339
|
|
||||
Accrued interest payable
|
|
15,930
|
|
|
—
|
|
|
—
|
|
|
15,930
|
|
||||
Other accrued expenses
|
|
37,425
|
|
|
1,200
|
|
|
—
|
|
|
38,625
|
|
||||
Total current liabilities
|
|
235,121
|
|
|
35,457
|
|
|
—
|
|
|
270,578
|
|
||||
Intercompany payable
|
|
—
|
|
|
9,415
|
|
|
(9,415
|
)
|
|
—
|
|
||||
Long-term debt
|
|
1,043,954
|
|
|
—
|
|
|
—
|
|
|
1,043,954
|
|
||||
Deferred income taxes
|
|
20,971
|
|
|
379,896
|
|
|
—
|
|
|
400,867
|
|
||||
Asset retirement obligations
|
|
78,897
|
|
|
3,715
|
|
|
—
|
|
|
82,612
|
|
||||
Fair value of derivatives
|
|
27,595
|
|
|
—
|
|
|
—
|
|
|
27,595
|
|
||||
Other liabilities
|
|
37,482
|
|
|
—
|
|
|
—
|
|
|
37,482
|
|
||||
Total liabilities
|
|
1,444,020
|
|
|
428,483
|
|
|
(9,415
|
)
|
|
1,863,088
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Stockholders' equity
|
|
|
|
|
|
|
|
|
||||||||
Common shares
|
|
657
|
|
|
—
|
|
|
—
|
|
|
657
|
|
||||
Additional paid-in capital
|
|
2,489,557
|
|
|
1,766,775
|
|
|
(1,766,775
|
)
|
|
2,489,557
|
|
||||
Retained earnings
|
|
134,208
|
|
|
(1,683
|
)
|
|
1,683
|
|
|
134,208
|
|
||||
Treasury shares
|
|
(1,668
|
)
|
|
—
|
|
|
—
|
|
|
(1,668
|
)
|
||||
Total stockholders' equity
|
|
2,622,754
|
|
|
1,765,092
|
|
|
(1,765,092
|
)
|
|
2,622,754
|
|
||||
Total Liabilities and Stockholders' Equity
|
|
$
|
4,066,774
|
|
|
$
|
2,193,575
|
|
|
$
|
(1,774,507
|
)
|
|
$
|
4,485,842
|
|
|
|
Consolidating Statements of Operations
|
||||||||||||||
|
|
Year Ended December 31, 2017
|
||||||||||||||
|
|
Parent
|
|
Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
|
|
|
|
|
|
|
||||||||
Crude oil, natural gas, and NGLs sales
|
|
$
|
788,400
|
|
|
$
|
124,684
|
|
|
$
|
—
|
|
|
$
|
913,084
|
|
Commodity price risk management gain (loss), net
|
|
(3,936
|
)
|
|
—
|
|
|
—
|
|
|
(3,936
|
)
|
||||
Other income
|
|
11,901
|
|
|
567
|
|
|
—
|
|
|
12,468
|
|
||||
Total revenues
|
|
796,365
|
|
|
125,251
|
|
|
—
|
|
|
921,616
|
|
||||
Costs, expenses and other
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
|
68,031
|
|
|
21,610
|
|
|
—
|
|
|
89,641
|
|
||||
Production taxes
|
|
53,236
|
|
|
7,481
|
|
|
—
|
|
|
60,717
|
|
||||
Transportation, gathering, and processing expenses
|
|
23,301
|
|
|
9,919
|
|
|
—
|
|
|
33,220
|
|
||||
Exploration, geologic, and geophysical expense
|
|
1,092
|
|
|
46,242
|
|
|
—
|
|
|
47,334
|
|
||||
Impairment of properties and equipment
|
|
4,951
|
|
|
280,936
|
|
|
—
|
|
|
285,887
|
|
||||
Impairment of goodwill
|
|
—
|
|
|
75,121
|
|
|
—
|
|
|
75,121
|
|
||||
General and administrative expense
|
|
107,518
|
|
|
12,852
|
|
|
—
|
|
|
120,370
|
|
||||
Depreciation, depletion and amortization
|
|
403,984
|
|
|
65,100
|
|
|
—
|
|
|
469,084
|
|
||||
Provision for uncollectible notes receivable
|
|
(40,203
|
)
|
|
—
|
|
|
—
|
|
|
(40,203
|
)
|
||||
Accretion of asset retirement obligations
|
|
5,965
|
|
|
341
|
|
|
—
|
|
|
6,306
|
|
||||
Gain on sale of properties and equipment
|
|
(766
|
)
|
|
—
|
|
|
—
|
|
|
(766
|
)
|
||||
Other expenses
|
|
13,157
|
|
|
—
|
|
|
—
|
|
|
13,157
|
|
||||
Total costs, expenses and other
|
|
640,266
|
|
|
519,602
|
|
|
—
|
|
|
1,159,868
|
|
||||
Income (loss) from operations
|
|
156,099
|
|
|
(394,351
|
)
|
|
—
|
|
|
(238,252
|
)
|
||||
Loss on extinguishment of debt
|
|
(24,747
|
)
|
|
—
|
|
|
—
|
|
|
(24,747
|
)
|
||||
Interest expense
|
|
(79,919
|
)
|
|
1,225
|
|
|
—
|
|
|
(78,694
|
)
|
||||
Interest income
|
|
2,261
|
|
|
—
|
|
|
—
|
|
|
2,261
|
|
||||
Income (loss) before income taxes
|
|
53,694
|
|
|
(393,126
|
)
|
|
—
|
|
|
(339,432
|
)
|
||||
Income tax (expense) benefit
|
|
(33,643
|
)
|
|
245,571
|
|
|
—
|
|
|
211,928
|
|
||||
Equity in loss of subsidiary
|
|
(147,555
|
)
|
|
—
|
|
|
147,555
|
|
|
—
|
|
||||
Net loss
|
|
$
|
(127,504
|
)
|
|
$
|
(147,555
|
)
|
|
$
|
147,555
|
|
|
$
|
(127,504
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Consolidating Statements of Operations
|
||||||||||||||
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
|
Parent
|
|
Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
|
|
|
|
|
|
|
||||||||
Crude oil, natural gas, and NGLs sales
|
|
$
|
491,750
|
|
|
$
|
5,603
|
|
|
$
|
—
|
|
|
$
|
497,353
|
|
Commodity price risk management gain (loss), net
|
|
(125,681
|
)
|
|
—
|
|
|
—
|
|
|
(125,681
|
)
|
||||
Other income
|
|
11,241
|
|
|
2
|
|
|
—
|
|
|
11,243
|
|
||||
Total revenues
|
|
377,310
|
|
|
5,605
|
|
|
—
|
|
|
382,915
|
|
||||
Costs, expenses and other
|
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
|
58,401
|
|
|
1,549
|
|
|
—
|
|
|
59,950
|
|
||||
Production taxes
|
|
31,132
|
|
|
278
|
|
|
—
|
|
|
31,410
|
|
||||
Transportation, gathering, and processing expenses
|
|
18,263
|
|
|
152
|
|
|
—
|
|
|
18,415
|
|
||||
Exploration, geologic, and geophysical expense
|
|
1,197
|
|
|
3,472
|
|
|
—
|
|
|
4,669
|
|
||||
Impairment of properties and equipment
|
|
9,973
|
|
|
—
|
|
|
—
|
|
|
9,973
|
|
||||
General and administrative expense
|
|
112,166
|
|
|
304
|
|
|
—
|
|
|
112,470
|
|
||||
Depreciation, depletion and amortization
|
|
415,321
|
|
|
1,553
|
|
|
—
|
|
|
416,874
|
|
||||
Provision for uncollectible notes receivable
|
|
44,038
|
|
|
—
|
|
|
—
|
|
|
44,038
|
|
||||
Accretion of asset retirement obligations
|
|
7,070
|
|
|
10
|
|
|
—
|
|
|
7,080
|
|
||||
Gain on sale of properties and equipment
|
|
(43
|
)
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
||||
Other expenses
|
|
10,193
|
|
|
—
|
|
|
—
|
|
|
10,193
|
|
||||
Total costs, expenses and other
|
|
707,711
|
|
|
7,318
|
|
|
—
|
|
|
715,029
|
|
||||
Loss from operations
|
|
(330,401
|
)
|
|
(1,713
|
)
|
|
—
|
|
|
(332,114
|
)
|
||||
Interest expense
|
|
(62,002
|
)
|
|
30
|
|
|
—
|
|
|
(61,972
|
)
|
||||
Interest income
|
|
963
|
|
|
—
|
|
|
—
|
|
|
963
|
|
||||
Loss before income taxes
|
|
(391,440
|
)
|
|
(1,683
|
)
|
|
—
|
|
|
(393,123
|
)
|
||||
Income tax benefit
|
|
147,195
|
|
|
—
|
|
|
—
|
|
|
147,195
|
|
||||
Equity in loss of subsidiary
|
|
(1,683
|
)
|
|
—
|
|
|
1,683
|
|
|
—
|
|
||||
Net loss
|
|
$
|
(245,928
|
)
|
|
$
|
(1,683
|
)
|
|
$
|
1,683
|
|
|
$
|
(245,928
|
)
|
|
|
Condensed Consolidating Statements of Cash Flows
|
||||||||||||||
|
|
Year Ended December 31, 2017
|
||||||||||||||
|
|
Parent
|
|
Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
Cash flows from operating activities
|
|
$
|
537,704
|
|
|
$
|
50,859
|
|
|
$
|
—
|
|
|
$
|
588,563
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures for development of crude oil and natural properties
|
|
(439,897
|
)
|
|
(297,311
|
)
|
|
—
|
|
|
(737,208
|
)
|
||||
Capital expenditures for other properties and equipment
|
|
(3,539
|
)
|
|
(1,555
|
)
|
|
—
|
|
|
(5,094
|
)
|
||||
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition
|
|
(21,000
|
)
|
|
5,372
|
|
|
—
|
|
|
(15,628
|
)
|
||||
Proceeds from sale of properties and equipment
|
|
10,084
|
|
|
(93
|
)
|
|
—
|
|
|
9,991
|
|
||||
Sale of promissory note
|
|
40,203
|
|
|
—
|
|
|
—
|
|
|
40,203
|
|
||||
Restricted cash
|
|
(9,250
|
)
|
|
—
|
|
|
—
|
|
|
(9,250
|
)
|
||||
Sale of short-term investments
|
|
49,890
|
|
|
—
|
|
|
—
|
|
|
49,890
|
|
||||
Purchase of short-term investments
|
|
(49,890
|
)
|
|
—
|
|
|
—
|
|
|
(49,890
|
)
|
||||
Intercompany transfers
|
|
(239,191
|
)
|
|
—
|
|
|
239,191
|
|
|
—
|
|
||||
Net cash from investing activities
|
|
(662,590
|
)
|
|
(293,587
|
)
|
|
239,191
|
|
|
(716,986
|
)
|
||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Proceeds from issuance of senior notes
|
|
592,366
|
|
|
—
|
|
|
—
|
|
|
592,366
|
|
||||
Redemption of senior notes
|
|
(519,375
|
)
|
|
—
|
|
|
—
|
|
|
(519,375
|
)
|
||||
Purchase of treasury stock
|
|
(6,672
|
)
|
|
—
|
|
|
—
|
|
|
(6,672
|
)
|
||||
Payment of debt issuance costs
|
|
(50
|
)
|
|
—
|
|
|
—
|
|
|
(50
|
)
|
||||
Other
|
|
(1,195
|
)
|
|
(76
|
)
|
|
—
|
|
|
(1,271
|
)
|
||||
Intercompany transfers
|
|
—
|
|
|
239,191
|
|
|
(239,191
|
)
|
|
—
|
|
||||
Net cash from financing activities
|
|
65,074
|
|
|
239,115
|
|
|
(239,191
|
)
|
|
64,998
|
|
||||
Net change in cash and cash equivalents
|
|
(59,812
|
)
|
|
(3,613
|
)
|
|
—
|
|
|
(63,425
|
)
|
||||
Cash and cash equivalents, beginning of period
|
|
240,487
|
|
|
3,613
|
|
|
—
|
|
|
244,100
|
|
||||
Cash and cash equivalents, end of period
|
|
$
|
180,675
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
180,675
|
|
|
|
Condensed Consolidating Statements of Cash Flows
|
||||||||||||||
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
|
Parent
|
|
Guarantor
|
|
Eliminations
|
|
Consolidated
|
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
Cash flows from operating activities
|
|
$
|
492,893
|
|
|
$
|
(6,630
|
)
|
|
$
|
—
|
|
|
$
|
486,263
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures for development of crude oil and natural properties
|
|
(436,361
|
)
|
|
(523
|
)
|
|
—
|
|
|
(436,884
|
)
|
||||
Capital expenditures for other properties and equipment
|
|
(2,282
|
)
|
|
(1,182
|
)
|
|
—
|
|
|
(3,464
|
)
|
||||
Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition
|
|
(1,076,256
|
)
|
|
2,533
|
|
|
—
|
|
|
(1,073,723
|
)
|
||||
Proceeds from sale of properties and equipment
|
|
4,945
|
|
|
—
|
|
|
—
|
|
|
4,945
|
|
||||
Intercompany transfers
|
|
(9,415
|
)
|
|
—
|
|
|
9,415
|
|
|
—
|
|
||||
Net cash from investing activities
|
|
(1,519,369
|
)
|
|
828
|
|
|
9,415
|
|
|
(1,509,126
|
)
|
||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Proceeds from issuance of equity, net of issuance costs
|
|
855,074
|
|
|
—
|
|
|
—
|
|
|
855,074
|
|
||||
Proceeds from issuance of senior notes
|
|
392,172
|
|
|
—
|
|
|
—
|
|
|
392,172
|
|
||||
Proceeds from issuance of convertible senior notes
|
|
193,935
|
|
|
—
|
|
|
—
|
|
|
193,935
|
|
||||
Proceeds from revolving credit facility
|
|
85,000
|
|
|
—
|
|
|
—
|
|
|
85,000
|
|
||||
Repayment of revolving credit facility
|
|
(122,000
|
)
|
|
—
|
|
|
—
|
|
|
(122,000
|
)
|
||||
Redemption of convertible notes
|
|
(115,000
|
)
|
|
—
|
|
|
—
|
|
|
(115,000
|
)
|
||||
Payment of debt issuance costs
|
|
(15,556
|
)
|
|
—
|
|
|
—
|
|
|
(15,556
|
)
|
||||
Purchase of treasury shares
|
|
(6,935
|
)
|
|
—
|
|
|
—
|
|
|
(6,935
|
)
|
||||
Other
|
|
(577
|
)
|
|
—
|
|
|
—
|
|
|
(577
|
)
|
||||
Intercompany transfers
|
|
—
|
|
|
9,415
|
|
|
(9,415
|
)
|
|
—
|
|
||||
Net cash from financing activities
|
|
1,266,113
|
|
|
9,415
|
|
|
(9,415
|
)
|
|
1,266,113
|
|
||||
Net change in cash and cash equivalents
|
|
239,637
|
|
|
3,613
|
|
|
—
|
|
|
243,250
|
|
||||
Cash and cash equivalents, beginning of period
|
|
850
|
|
|
—
|
|
|
—
|
|
|
850
|
|
||||
Cash and cash equivalents, end of period
|
|
$
|
240,487
|
|
|
$
|
3,613
|
|
|
$
|
—
|
|
|
$
|
244,100
|
|
|
|
Average Benchmark Prices (1)
|
||||||||||
As of December 31,
|
|
Crude Oil
(per Bbl)
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl) (2)
|
||||||
|
|
|
|
|
|
|
||||||
2017
|
|
$
|
51.34
|
|
|
$
|
2.98
|
|
|
$
|
51.34
|
|
2016
|
|
42.75
|
|
|
2.48
|
|
|
42.75
|
|
|||
2015
|
|
50.28
|
|
|
2.59
|
|
|
50.28
|
|
|
|
Price Used to Estimate Reserves (3)
|
||||||||||
As of December 31,
|
|
Crude Oil
(per Bbl)
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl) (2)
|
||||||
|
|
|
|
|
|
|
||||||
2017
|
|
$
|
48.68
|
|
|
$
|
2.31
|
|
|
$
|
20.21
|
|
2016
|
|
38.67
|
|
|
1.85
|
|
|
11.97
|
|
|||
2015
|
|
42.10
|
|
|
2.05
|
|
|
12.23
|
|
(1)
|
Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months.
|
(2)
|
For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.
|
(3)
|
These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.
|
|
Crude Oil, Condensate (MBbls)
|
|
Natural Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Total
(MBoe)
|
||||
Proved Reserves:
|
|
|
|
|
|
|
|
||||
Proved reserves, January 1, 2015
|
100,515
|
|
|
536,972
|
|
|
60,119
|
|
|
250,129
|
|
Revisions of previous estimates
|
(43,268
|
)
|
|
(154,775
|
)
|
|
(24,407
|
)
|
|
(93,471
|
)
|
Extensions, discoveries, and other additions
|
48,707
|
|
|
311,709
|
|
|
30,835
|
|
|
131,494
|
|
Acquisition of reserves
|
17
|
|
|
215
|
|
|
23
|
|
|
76
|
|
Dispositions
|
(12
|
)
|
|
(82
|
)
|
|
(8
|
)
|
|
(34
|
)
|
Production
|
(6,984
|
)
|
|
(33,302
|
)
|
|
(2,835
|
)
|
|
(15,369
|
)
|
Proved reserves, December 31, 2015
|
98,975
|
|
|
660,737
|
|
|
63,727
|
|
|
272,825
|
|
Revisions of previous estimates
|
(22,097
|
)
|
|
(80,426
|
)
|
|
(7,130
|
)
|
|
(42,631
|
)
|
Extensions, discoveries, and other additions
|
494
|
|
|
4,094
|
|
|
355
|
|
|
1,531
|
|
Acquisition of reserves
|
50,126
|
|
|
305,224
|
|
|
32,586
|
|
|
133,583
|
|
Dispositions
|
(601
|
)
|
|
(4,202
|
)
|
|
(424
|
)
|
|
(1,725
|
)
|
Production
|
(8,728
|
)
|
|
(51,730
|
)
|
|
(4,826
|
)
|
|
(22,176
|
)
|
Proved reserves, December 31, 2016
|
118,169
|
|
|
833,697
|
|
|
84,288
|
|
|
341,407
|
|
Revisions of previous estimates
|
28,334
|
|
|
96,119
|
|
|
8,104
|
|
|
52,457
|
|
Extensions, discoveries, and other additions
|
2,923
|
|
|
11,541
|
|
|
1,158
|
|
|
6,005
|
|
Acquisition of reserves
|
18,971
|
|
|
289,223
|
|
|
19,604
|
|
|
86,778
|
|
Dispositions
|
(653
|
)
|
|
(4,597
|
)
|
|
(481
|
)
|
|
(1,900
|
)
|
Production
|
(12,902
|
)
|
|
(71,689
|
)
|
|
(6,981
|
)
|
|
(31,830
|
)
|
Proved reserves, December 31, 2017
|
154,842
|
|
|
1,154,294
|
|
|
105,692
|
|
|
452,917
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves, as of:
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
26,257
|
|
|
175,367
|
|
|
15,011
|
|
|
70,496
|
|
December 31, 2016
|
30,013
|
|
|
264,452
|
|
|
24,196
|
|
|
98,284
|
|
December 31, 2017
|
46,862
|
|
|
365,332
|
|
|
35,220
|
|
|
142,971
|
|
Proved Undeveloped Reserves, as of:
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
72,718
|
|
|
485,370
|
|
|
48,716
|
|
|
202,329
|
|
December 31, 2016
|
88,156
|
|
|
569,245
|
|
|
60,092
|
|
|
243,122
|
|
December 31, 2017
|
107,980
|
|
|
788,962
|
|
|
70,472
|
|
|
309,946
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|||
|
(MBoe)
|
|||||||
|
|
|
|
|
|
|||
Proved reserves, January 1, 2015
|
74,905
|
|
|
175,224
|
|
|
250,129
|
|
Undeveloped reserves converted to developed
|
29,090
|
|
|
(29,090
|
)
|
|
—
|
|
Revisions of previous estimates
|
(26,875
|
)
|
|
(66,596
|
)
|
|
(93,471
|
)
|
Extensions, discoveries, and other additions
|
8,703
|
|
|
122,791
|
|
|
131,494
|
|
Acquisition of reserves
|
76
|
|
|
—
|
|
|
76
|
|
Dispositions
|
(34
|
)
|
|
—
|
|
|
(34
|
)
|
Production
|
(15,369
|
)
|
|
—
|
|
|
(15,369
|
)
|
Proved reserves, December 31, 2015
|
70,496
|
|
|
202,329
|
|
|
272,825
|
|
Undeveloped reserves converted to developed
|
32,192
|
|
|
(32,192
|
)
|
|
—
|
|
Revisions of previous estimates
|
6,112
|
|
|
(48,743
|
)
|
|
(42,631
|
)
|
Extensions, discoveries, and other additions
|
1,531
|
|
|
—
|
|
|
1,531
|
|
Acquisition of reserves
|
10,229
|
|
|
123,354
|
|
|
133,583
|
|
Dispositions
|
(99
|
)
|
|
(1,626
|
)
|
|
(1,725
|
)
|
Production
|
(22,176
|
)
|
|
—
|
|
|
(22,176
|
)
|
Proved reserves, December 31, 2016
|
98,285
|
|
|
243,122
|
|
|
341,407
|
|
Undeveloped reserves converted to developed
|
54,648
|
|
|
(54,648
|
)
|
|
—
|
|
Revisions of previous estimates
|
18,291
|
|
|
34,166
|
|
|
52,457
|
|
Extensions, discoveries, and other additions
|
2,292
|
|
|
3,713
|
|
|
6,005
|
|
Acquisition of reserves
|
1,305
|
|
|
85,473
|
|
|
86,778
|
|
Dispositions
|
(20
|
)
|
|
(1,880
|
)
|
|
(1,900
|
)
|
Production
|
(31,830
|
)
|
|
—
|
|
|
(31,830
|
)
|
Proved reserves, December 31, 2017
|
142,971
|
|
|
309,946
|
|
|
452,917
|
|
|
|
|
|
|
|
•
|
Negative revisions of
57.7
MMBoe were due to Wattenberg Field PUD locations being dropped from our proved five- year development plan and being replaced by PUD locations on newly-acquired properties.
|
•
|
Positive revisions of
93.9
MMBoe for infill drilling within a proven area, with 37.3 MMBoe in our Wattenberg Field and 56.6 MMBoe in our Delaware Basin.
|
•
|
Net negative revisions of 2.2 MMBoe were due to an increase in operating costs, partially offset by an increase in prices for crude oil, natural gas, and NGLs.
|
•
|
Negative revisions of 0.7 MMBoe were due to locations being removed due to the SEC five-year development rule.
|
•
|
Net positive revisions of 19.2 MMBoe includes performance revisions and other items.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Revenue:
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
$
|
913,084
|
|
|
$
|
497,353
|
|
|
$
|
378,713
|
|
Commodity price risk management gain (loss), net
|
(3,936
|
)
|
|
(125,681
|
)
|
|
203,183
|
|
|||
|
909,148
|
|
|
371,672
|
|
|
581,896
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Lease operating expenses
|
89,641
|
|
|
59,950
|
|
|
56,992
|
|
|||
Production taxes
|
60,717
|
|
|
31,410
|
|
|
18,443
|
|
|||
Transportation, gathering and processing expenses
|
33,220
|
|
|
18,415
|
|
|
10,151
|
|
|||
Exploration expense
|
47,334
|
|
|
4,669
|
|
|
1,102
|
|
|||
Impairment of properties and equipment
|
285,887
|
|
|
9,973
|
|
|
161,620
|
|
|||
Depreciation, depletion, and amortization
|
462,482
|
|
|
413,105
|
|
|
298,760
|
|
|||
Accretion of asset retirement obligations
|
6,306
|
|
|
7,080
|
|
|
6,293
|
|
|||
Gain on sale of properties and equipment
|
(766
|
)
|
|
(43
|
)
|
|
(385
|
)
|
|||
|
984,821
|
|
|
544,559
|
|
|
552,976
|
|
|||
Results of operations for crude oil and natural gas producing
activities before provision for income taxes |
(75,673
|
)
|
|
(172,887
|
)
|
|
28,920
|
|
|||
Provision for income taxes
|
47,247
|
|
|
64,733
|
|
|
(10,394
|
)
|
|||
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs
|
$
|
(28,426
|
)
|
|
$
|
(108,154
|
)
|
|
$
|
18,526
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
Acquisition of properties: (1)
|
|
|
|
|
|
||||||
Proved properties
|
$
|
172
|
|
|
$
|
268,567
|
|
|
$
|
3,561
|
|
Unproved properties
|
18,914
|
|
|
1,843,985
|
|
|
15
|
|
|||
Development costs (2)
|
688,165
|
|
|
383,336
|
|
|
552,104
|
|
|||
Exploration costs: (3)
|
|
|
|
|
|
||||||
Exploratory drilling
|
80,103
|
|
|
—
|
|
|
—
|
|
|||
Geological and geophysical
|
3,881
|
|
|
4,669
|
|
|
—
|
|
|||
Total costs incurred (4)
|
$
|
791,235
|
|
|
$
|
2,500,557
|
|
|
$
|
555,680
|
|
|
|
|
|
|
|
(1)
|
Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties
|
(2)
|
Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended
December 31, 2017
,
2016
, and
2015
,
$463.4 million
,
$204.6 million
, and
$207.8 million
, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately
$32.8 million
of infrastructure and pipeline costs in 2017.
|
(3)
|
Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells.
|
(4)
|
During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017.
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Proved crude oil and natural gas properties
|
$
|
4,356,922
|
|
|
$
|
3,499,718
|
|
Unproved crude oil and natural gas properties
|
1,097,317
|
|
|
1,874,671
|
|
||
Uncompleted wells, equipment and facilities
|
265,526
|
|
|
150,424
|
|
||
Capitalized costs
|
5,719,765
|
|
|
5,524,813
|
|
||
Less accumulated DD&A
|
(1,803,847
|
)
|
|
(1,534,678
|
)
|
||
Capitalized costs, net
|
$
|
3,915,918
|
|
|
$
|
3,990,135
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Future estimated cash flows
|
$
|
12,340,407
|
|
|
$
|
7,122,525
|
|
|
$
|
6,297,298
|
|
Future estimated production costs*
|
(3,245,627
|
)
|
|
(1,624,167
|
)
|
|
(1,493,040
|
)
|
|||
Future estimated development costs
|
(2,893,335
|
)
|
|
(2,219,914
|
)
|
|
(2,036,685
|
)
|
|||
Future estimated income tax expense
|
(748,494
|
)
|
|
(597,476
|
)
|
|
(508,332
|
)
|
|||
Future net cash flows
|
5,452,951
|
|
|
2,680,968
|
|
|
2,259,241
|
|
|||
10% annual discount for estimated timing of cash flows
|
(2,572,846
|
)
|
|
(1,260,339
|
)
|
|
(1,162,377
|
)
|
|||
Standardized measure of discounted future estimated net cash flows
|
$
|
2,880,105
|
|
|
$
|
1,420,629
|
|
|
$
|
1,096,864
|
|
|
|
|
|
|
|
*
|
Represents future estimated lease operating expenses, production taxes, transportation, gathering, and processing expenses.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Beginning of period
|
$
|
1,420,629
|
|
|
$
|
1,096,864
|
|
|
$
|
2,306,465
|
|
Sales of crude oil, natural gas and NGLs production, net of production costs
|
(729,506
|
)
|
|
(387,576
|
)
|
|
(293,127
|
)
|
|||
Net changes in prices and production costs (1)
|
841,713
|
|
|
(205,760
|
)
|
|
(1,752,921
|
)
|
|||
Extensions, discoveries, and improved recovery, less related costs
|
47,240
|
|
|
15,128
|
|
|
489,178
|
|
|||
Sales of reserves
|
(2,613
|
)
|
|
(3,745
|
)
|
|
(463
|
)
|
|||
Purchases of reserves
|
224,483
|
|
|
487,636
|
|
|
374
|
|
|||
Development costs incurred during the period
|
419,047
|
|
|
268,672
|
|
|
368,840
|
|
|||
Revisions of previous quantity estimates
|
484,431
|
|
|
(320,286
|
)
|
|
(1,286,462
|
)
|
|||
Changes in estimated income taxes
|
(138,560
|
)
|
|
(13,630
|
)
|
|
902,994
|
|
|||
Net changes in future development costs
|
25,183
|
|
|
391,145
|
|
|
112,958
|
|
|||
Accretion of discount
|
167,487
|
|
|
133,747
|
|
|
345,007
|
|
|||
Timing and other
|
120,571
|
|
|
(41,566
|
)
|
|
(95,979
|
)
|
|||
End of period
|
$
|
2,880,105
|
|
|
$
|
1,420,629
|
|
|
$
|
1,096,864
|
|
|
|
|
|
|
|
(1)
|
Our weighted-average price, net of production costs per Boe, in our 2017 reserve report increased to
$20.08
as compared to
$15.73
for 2016 and
$17.30
for 2015.
|
|
2017
|
||||||||||||||
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Total revenues
|
$
|
273,707
|
|
|
$
|
275,158
|
|
|
$
|
183,235
|
|
|
$
|
189,516
|
|
Total costs, expenses and other
|
182,004
|
|
|
190,522
|
|
|
579,326
|
|
|
208,016
|
|
||||
Income (loss) from operations
|
91,703
|
|
|
84,636
|
|
|
(396,091
|
)
|
|
(18,500
|
)
|
||||
Income (loss) before income taxes
|
72,476
|
|
|
65,787
|
|
|
(414,887
|
)
|
|
(62,808
|
)
|
||||
Net income (loss) (1)
|
$
|
46,146
|
|
|
$
|
41,250
|
|
|
$
|
(292,537
|
)
|
|
$
|
77,637
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings per share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.70
|
|
|
$
|
0.63
|
|
|
$
|
(4.44
|
)
|
|
$
|
1.18
|
|
Diluted
|
0.70
|
|
|
0.62
|
|
|
(4.44
|
)
|
|
1.17
|
|
|
2016
|
||||||||||||||
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Total revenues
|
$
|
90,831
|
|
|
$
|
20,097
|
|
|
$
|
163,890
|
|
|
$
|
108,097
|
|
Total costs, expenses and other
|
193,864
|
|
|
163,379
|
|
|
179,178
|
|
|
178,608
|
|
||||
Loss from operations
|
(103,033
|
)
|
|
(143,282
|
)
|
|
(15,288
|
)
|
|
(70,511
|
)
|
||||
Loss before income taxes
|
(113,369
|
)
|
|
(153,777
|
)
|
|
(35,341
|
)
|
|
(90,636
|
)
|
||||
Net loss
|
$
|
(71,530
|
)
|
|
$
|
(95,450
|
)
|
|
$
|
(23,309
|
)
|
|
$
|
(55,639
|
)
|
|
|
|
|
|
|
|
|
||||||||
Earnings per share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(1.72
|
)
|
|
$
|
(2.04
|
)
|
|
$
|
(0.48
|
)
|
|
$
|
(0.94
|
)
|
Diluted
|
(1.72
|
)
|
|
(2.04
|
)
|
|
(0.48
|
)
|
|
(0.94
|
)
|
Description
|
|
Beginning
Balance January 1, |
|
Charged to
Costs and Expenses |
|
Deductions (1)
|
|
Ending
Balance December 31, |
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
2017:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for uncollectible notes
|
|
$
|
44,038
|
|
|
$
|
—
|
|
|
$
|
44,038
|
|
|
$
|
—
|
|
Allowance for doubtful accounts
|
|
2,190
|
|
|
1,108
|
|
|
170
|
|
|
3,128
|
|
||||
Allowance for expirations of unproved crude oil and natural gas properties
|
|
359
|
|
|
263,817
|
|
|
13,017
|
|
|
251,159
|
|
||||
2016:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for uncollectible notes
|
|
—
|
|
|
44,038
|
|
|
—
|
|
|
44,038
|
|
||||
Allowance for doubtful accounts
|
|
2,009
|
|
|
1,309
|
|
|
1,128
|
|
|
2,190
|
|
||||
Allowance for expirations of unproved crude oil and natural gas properties
|
|
144
|
|
|
215
|
|
|
—
|
|
|
359
|
|
||||
2015:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
486
|
|
|
1,700
|
|
|
177
|
|
|
2,009
|
|
||||
Allowance for expirations of unproved crude oil and natural gas properties
|
|
9,293
|
|
|
7,012
|
|
|
16,161
|
|
|
144
|
|
(1)
|
For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent either actual expired or abandoned unproved crude oil and natural gas properties or an accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.
|
(a)
|
(1)
|
Exhibits:
|
|
|
See Exhibits Index on the following page.
|
|
|
|
|
Incorporated by Reference
|
|
|
||||||
Exhibit Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File Number
|
|
Exhibit
|
|
Filing Date
|
|
Filed Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.1
|
|
|
8-K12B
|
|
001-37419
|
|
2.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.2
|
|
|
8-K
|
|
001-37419
|
|
2.1
|
|
8/24/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3
|
|
|
8-K
|
|
001-37419
|
|
2.2
|
|
8/24/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.1
|
|
|
8-K12B
|
|
001-37419
|
|
3.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
8-K12B
|
|
001-37419
|
|
3.2
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.1
|
|
|
10-K
|
|
001-37419
|
|
4.1
|
|
2/28/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.2
|
|
|
8-K
|
|
001-37419
|
|
4.1
|
|
11/29/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
|
8-K
|
|
001-37419
|
|
4.1
|
|
9/14/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.4
|
|
|
8-K
|
|
001-37419
|
|
4.2
|
|
9/14/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.5
|
|
|
8-K
|
|
001-37419
|
|
4.1
|
|
9/15/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1
|
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.2
|
|
|
10-K
|
|
001-37419
|
|
10.2
|
|
2/28/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.3
|
|
|
10-K
|
|
|
|
10.3
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4
|
|
|
10-K
|
|
000-07246
|
|
10.26
|
|
2/27/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4.1
|
|
|
8-K
|
|
000-07246
|
|
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5
|
|
|
10-K
|
|
001-37419
|
|
10.5
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.6
|
|
|
10-K
|
|
001-37419
|
|
10.6
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7
|
|
|
10-K
|
|
000-07246
|
|
10.5.2
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.1
|
|
|
10-K
|
|
000-07246
|
|
10.9
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.2
|
|
|
10-K
|
|
000-07246
|
|
10.10
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.3
|
|
|
10-K
|
|
000-07246
|
|
10.5.4
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.4
|
|
|
10-K
|
|
000-07246
|
|
10.5.5
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
|
|
||||||
Exhibit Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File Number
|
|
Exhibit
|
|
Filing Date
|
|
Filed Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.5
|
|
|
10-K
|
|
000-07246
|
|
10.5.6
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.6
|
|
|
10-K
|
|
000-07246
|
|
10.5.7
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.7
|
|
|
10-K
|
|
000-07246
|
|
10.5.8
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.8
|
|
|
10-K
|
|
001-37419
|
|
10.7.8
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.9
|
|
|
8-K
|
|
000-07246
|
|
10.3
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.10
|
|
|
8-K
|
|
000-07246
|
|
10.4
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11
|
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
5/28/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.1
|
|
|
10-K
|
|
001-37419
|
|
10.11.1
|
|
2/22/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.2
|
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
9/8/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.3
|
|
|
10-Q
|
|
001-37419
|
|
99.1
|
|
11/3/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.4
|
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
5/16/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11.5
|
|
|
10-Q
|
|
001-37419
|
|
10.1
|
|
11/7/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.12*
|
|
|
10-K
|
|
001-37419
|
|
10.14
|
|
2/28/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.12.1*
|
|
|
10-K
|
|
001-37419
|
|
10.14.1
|
|
2/28/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.13
|
|
|
8-K
|
|
001-37419
|
|
10.2
|
|
9/15/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.14
|
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
12/7/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.15
|
|
|
8-K
|
|
001-37419
|
|
10.2
|
|
12/7/2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.16
|
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
11/17/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.17
|
|
|
8-K
|
|
001-37419
|
|
10.1
|
|
11/29/2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incorporated by Reference
|
|
|
||||||
Exhibit Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File Number
|
|
Exhibit
|
|
Filing Date
|
|
Filed Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.1
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21.1
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.1
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.2
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.3
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31.1
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31.2
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32.1
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99.1
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99.2
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101.INS
|
|
XBRL Instance Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
PDC ENERGY, INC.
|
|
|
|
By: /s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief Executive Officer
|
|
|
|
February 26, 2018
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Barton R. Brookman
|
|
President, Chief Executive Officer and Director
|
|
February 26, 2018
|
Barton R. Brookman
|
|
(principal executive officer)
|
|
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
Senior Vice President and Chief Financial Officer
|
|
February 26, 2018
|
R. Scott Meyers
|
|
(principal financial officer and principal accounting officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey C. Swoveland
|
|
Chairman and Director
|
|
February 26, 2018
|
Jeffrey C. Swoveland
|
|
|
|
|
|
|
|
|
|
/s/ Anthony J. Crisafio
|
|
Director
|
|
February 26, 2018
|
Anthony J. Crisafio
|
|
|
|
|
|
|
|
|
|
/s/ Larry F. Mazza
|
|
Director
|
|
February 26, 2018
|
Larry F. Mazza
|
|
|
|
|
|
|
|
|
|
/s/ David C. Parke
|
|
Director
|
|
February 26, 2018
|
David C. Parke
|
|
|
|
|
|
|
|
|
|
/s/ Randy S. Nickerson
|
|
Director
|
|
February 26, 2018
|
Randy S. Nickerson
|
|
|
|
|
|
|
|
|
|
/s/ Mark E. Ellis
|
|
Director
|
|
February 26, 2018
|
Mark E. Ellis
|
|
|
|
|
|
|
|
|
|
/s/ Christina M. Ibrahim
|
|
Director
|
|
February 26, 2018
|
Christina M. Ibrahim
|
|
|
|
|
PDC ENERGY, INC.
|
|||||||||||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges
|
|||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
||||||||||
|
|
(dollars in thousands)
|
|
||||||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
(339,432
|
)
|
|
$
|
(393,123
|
)
|
|
$
|
(106,588
|
)
|
|
$
|
177,228
|
|
|
$
|
(32,963
|
)
|
|
Fixed charges (see below)
|
|
89,434
|
|
|
69,840
|
|
|
55,844
|
|
|
53,512
|
|
|
54,002
|
|
|
|||||
Amortization of capitalized interest
|
|
3,190
|
|
|
3,463
|
|
|
2,486
|
|
|
1,379
|
|
|
1,096
|
|
|
|||||
Interest capitalized
|
|
(5,049
|
)
|
|
(4,489
|
)
|
|
(5,060
|
)
|
|
(3,468
|
)
|
|
(1,709
|
)
|
|
|||||
Total adjusted earnings (loss) available for fixed charges
|
|
$
|
(251,857
|
)
|
|
$
|
(324,309
|
)
|
|
$
|
(53,318
|
)
|
|
$
|
228,651
|
|
|
$
|
20,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and debt expense (a)
|
|
$
|
78,694
|
|
|
$
|
61,972
|
|
|
$
|
47,571
|
|
|
$
|
47,842
|
|
|
$
|
50,143
|
|
|
Interest capitalized
|
|
5,049
|
|
|
4,489
|
|
|
5,060
|
|
|
3,468
|
|
|
1,709
|
|
|
|||||
Interest component of rental expense (b)
|
|
5,691
|
|
|
3,379
|
|
|
3,213
|
|
|
2,202
|
|
|
2,150
|
|
|
|||||
Total fixed charges
|
|
$
|
89,434
|
|
|
$
|
69,840
|
|
|
$
|
55,844
|
|
|
$
|
53,512
|
|
|
$
|
54,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
(c)
|
—
|
|
(c)
|
—
|
|
(c)
|
4.3
|
x
|
|
—
|
|
(c)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Represents interest expense on long-term debt and amortization of debt discount and issuance costs.
|
(b)
|
Represents the portion of rental expense which we believe represents an interest component.
|
(c)
|
For the years ended December 31, 2016, 2015, 2013, and 2012, earnings were insufficient to cover total fixed charges by
$341.3 million
,
$394.1 million
,
$175.1 million
,
and
$33.6 million
, respectively.
|
|
/s/ Ryder Scott Company, L.P.
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
TBPE Firm Registration No. F-1580
|
|
|
Denver, CO
|
|
February 26, 2018
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
By:
|
|
s/ J. Carter Henson, Jr.
|
|
|
J. Carter Henson, Jr., P.E.
|
|
|
Senior Vice President
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
1.
|
I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 26, 2018
|
|
/s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief Executive Officer
|
|
(principal executive officer)
|
1.
|
I have reviewed this Annual Report on Form 10-K of PDC Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 26, 2018
|
|
/s/ R. Scott Meyers
|
|
R. Scott Meyers
|
|
Senior Vice President and Chief Financial Officer
|
|
(principal financial officer)
|
1.
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Barton R. Brookman
|
|
February 26, 2018
|
Barton R. Brookman
|
|
|
President and Chief Executive Officer
|
|
|
(principal executive officer)
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
February 26, 2018
|
R. Scott Meyers
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
(principal financial officer)
|
|
|
As of December 31, 2017
|
|||||||||||||||||
|
|
Proved
|
|||||||||||||||
|
|
Developed
|
|
|
|
Total
|
|||||||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
|||||||||
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
|||||||||
Oil/Condensate - MBBL
|
|
36,618.6
|
|
|
736.7
|
|
|
69,707.5
|
|
|
107,062.8
|
|
|||||
Plant Products - MBBL
|
|
29,849.2
|
|
|
484.7
|
|
|
57,782.9
|
|
|
88,116.8
|
|
|||||
Gas - MMCF
|
|
309,261
|
|
|
5,482
|
|
|
644,458
|
|
|
959,201
|
|
|||||
|
|
|
|
|
|
|
|
|
|||||||||
Income Data (M$)
|
|
|
|
|
|
|
|
|
|||||||||
Future Gross Revenue
|
|
$
|
2,924,606
|
|
|
$
|
56,172
|
|
|
$
|
5,772,357
|
|
|
8,753,135
|
|
||
Deductions
|
|
878,158
|
|
|
64,018
|
|
|
3,188,610
|
|
|
4,130,786
|
|
|||||
Future Net Income (FNI)
|
|
$
|
2,046,448
|
|
|
$
|
(7,846
|
)
|
(1
|
)
|
$
|
2,583,747
|
|
|
$
|
4,622,349
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discounted FNI @ 10%
|
|
$
|
1,447,838
|
|
|
$
|
22,871
|
|
|
$
|
1,097,968
|
|
|
$
|
2,568,677
|
|
|
|
Discounted Future Net Income - (M$)
|
||||
|
|
As of December 31, 2017
|
||||
Discount Rate Percent
|
|
|
Total Proved
|
|
||
|
|
|
|
|
||
5
|
|
|
$
|
3,362,950
|
|
|
15
|
|
|
$
|
2,038,003
|
|
|
20
|
|
|
$
|
1,666,489
|
|
|
25
|
|
|
$
|
1,396,332
|
|
|
Geographic
Area
|
Product
|
Price
Reference
|
Average Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$51.34/Bbl
|
$48.62/Bbl
|
NGLs
|
WTI Cushing
|
$51.34/Bbl
|
$18.33/Bbl
|
|
Gas
|
Henry Hub
|
$2.98/MMBTU
|
$2.24/MCF
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
|||||||||||
Category
|
|
Oil (MMBL)
|
|
NGL (MMBL)
|
|
Gas (MMCF)
|
|
Total
|
|
Present Worth at 10%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved Developed Producing
|
|
9,507.1
|
|
|
4,886.0
|
|
|
50,589.8
|
|
|
377,983.5
|
|
|
267,642.3
|
|
Proved Undeveloped
|
|
38,273.4
|
|
|
12,689.5
|
|
|
144,503.6
|
|
|
837,108.9
|
|
|
375,641.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Proved
|
|
47,780.5
|
|
|
17,575.5
|
|
|
195,093.4
|
|
|
1,215,092.4
|
|
|
643,284.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Totals may not add because of rounding.
|
|
|
|
|
|
|
|
|
|
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir,
|