Nevada
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95-2636730
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(State of incorporation)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $0.01 per share
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NASDAQ Global Select Market
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
£
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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PART I
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Page
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PART II
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PART III
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PART IV
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•
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changes in worldwide production volumes and demand, including economic conditions that might impact demand;
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•
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volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices;
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•
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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;
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•
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potential declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;
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•
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changes in estimates of proved reserves;
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•
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inaccuracy of reserve estimates and expected production rates;
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•
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potential for production decline rates from our wells being greater than expected;
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•
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timing and extent of our success in discovering, acquiring, developing and producing reserves;
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•
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our ability to secure leases, drilling rigs, supplies and services at reasonable prices;
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•
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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;
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•
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timing and receipt of necessary regulatory permits;
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•
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risks incidental to the drilling and operation of crude oil and natural gas wells;
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•
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our future cash flows, liquidity and financial condition;
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•
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competition within the oil and gas industry;
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•
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availability and cost of capital;
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•
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reductions in the borrowing base under our revolving credit facility;
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•
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our success in marketing crude oil, natural gas and NGLs;
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•
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effect of crude oil and natural gas derivatives activities;
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•
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impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;
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•
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cost of pending or future litigation;
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•
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effect that acquisitions we may pursue have on our capital expenditures;
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•
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our ability to retain or attract senior management and key technical employees; and
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•
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success of strategic plans, expectations and objectives for our future operations.
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Proved Reserves at December 31, 2014
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||||||||
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Proved Reserves (MMBoe)
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% of Total Proved Reserves
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% Proved Developed
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% Liquids
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Proved Reserves to Production Ratio (in years)
|
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2014 Production (MBoe)
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||||
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||||
Wattenberg Field
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245
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|
98
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%
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|
29
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%
|
|
64
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%
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28.9
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8,484
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Utica Shale
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5
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2
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%
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|
77
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%
|
|
53
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%
|
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6.5
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|
805
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Total proved reserves
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250
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|
100
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%
|
|
30
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%
|
|
64
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%
|
|
26.9
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9,289
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•
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Excellent drilling opportunities with a strong liquidity position.
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◦
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Multi-year project inventory in premier crude oil, natural gas and NGLs plays.
We have a significant operational presence in two key U.S. onshore basins and have identified a substantial inventory of approximately
2,650
gross proved undeveloped and probable horizontal drilling projects. We believe that this inventory will allow us to continue to grow our reserves and production, and that, with respect to the Wattenberg Field in particular, the majority of our projects will generate attractive rates of return at current commodity prices and our expected cost structure.
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◦
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Access to liquidity.
As of
December 31, 2014
, we had a total liquidity position of
$398.4 million
, comprised of
$16.1 million
of cash and cash equivalents and
$382.3 million
available for borrowing under revolving credit facility. We have no near-term debt maturities and had
$56.0 million
outstanding on our revolving credit facility as of
December 31, 2014
. In September 2014, the semi-annual redetermination of our revolving credit facility's borrowing base was completed, resulting in an increase in the borrowing base from $450 million to $700 million. We elected to maintain the aggregate commitment at $450 million. Considering the additional $250 million borrowing base available under our revolving credit facility, subject to certain terms and conditions of the agreement, our liquidity position as of
December 31, 2014
would have been
$648.3 million
.
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◦
|
Derivative program.
We actively hedge our future exposure to commodity price fluctuations by entering into crude oil and natural gas collars, fixed-price swaps and basis protection swaps. As of
December 31, 2014
, we have hedged approximately
5,200
MBbls, or approximately
79%
to
85%
, of our expected crude oil production in
2015
at a weighted-average minimum price of
$88.61
per Bbl and a weighted-average maximum price of
$90.07
per Bbl. As of the same date, we have hedged approximately
22.5
Bcf, or approximately
74%
to
79%
, of our expected natural gas production in
2015
at a weighted-average minimum price of
$3.90
per Mcf and and a weighted-average maximum price of
$4.02
per Mcf. While our derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect our cash flows, borrowing base and liquidity during periods of depressed commodity prices.
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•
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Track record of reserve and production growth.
Our proved reserves have grown from
38
MMBoe at December 31,
2009
, after adjusting for subsequent divestitures, to approximately
250
MMBoe at
December 31, 2014
, representing a compound annual growth rate (“CAGR”) of
46%
. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of
55%
. Our annual production from continuing operations grew from
2.7
MMBoe in
2009
to
9.3
MMBoe in
2014
, representing a CAGR of
28%
.
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•
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Horizontal drilling and completion experience.
We have a proven track record of applying technical expertise toward developing unconventional resources through horizontal drilling and completion operations. We have transitioned to multi-well pad drilling, extended laterals, increased frac density and enhanced frac design to further optimize costs and enhance horizontal drilling efficiencies. These changes enable us to improve economics and increase well density in our horizontal plays.
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•
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Significant control in our core areas.
As a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately
89%
of the wells in which we have an interest. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas. Additionally, this strategy provides us flexibility in selecting drilling locations based upon differing criteria. Our operational control is also enhanced by the fact that a majority of our Wattenberg Field leasehold is held by production.
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•
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Reputation for strong environmental health and safety compliance program.
We believe that we have established a positive reputation for our environmental health and safety program. We believe that this is an important advantage for us in competing in today’s intensive regulatory climate and in working with local communities in which we operate.
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•
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Community participation and outreach.
We are dedicated to being an active and contributing member in the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. We also encourage our employees to take an active role through our charitable matching contribution fund and by participating in our “Energizing Our Community” day, during which our employees volunteer in the communities in which they work and live.
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•
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Management experience and operational expertise.
We have a management team with a proven track record of drilling performance and a technical and operational staff with expertise in the basins in which we operate, particularly in horizontal drilling, completion and production activities in the Wattenberg Field.
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•
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Crude oil
. We do not refine any of our crude oil production. In the Wattenberg Field, crude oil is sold at each individual well site and transported by the purchasers via truck, pipeline or rail to markets under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into a five-year agreement, beginning in the second quarter of 2015, which will allow crude oil sold to these purchasers to be transported via pipeline to Cushing, Oklahoma. In addition, we have signed a long term agreement for gathering of crude oil at the wellhead by pipeline from several of our wells and transportation to at least one central point in the Wattenberg Field, with a view toward reducing costs and minimizing truck traffic. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River.
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•
|
Natural gas
. We primarily sell our natural gas to midstream service providers, marketers and utilities. Our natural gas is transported through third-party gathering systems and pipelines and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. We generally sell the natural gas that we produce under contracts with indexed, NYMEX or CIG monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions whereby prices change monthly with changes in the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. In certain instances, we enter into firm transportation, processing and sales agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP Midstream, LP, which gathers and processes wet natural gas produced in the basin and sells our residue gas to various markets. In the fourth quarter of 2014, we entered into an agreement with AKA Energy Group ("AKA") whereby we have committed production from a specified number of new horizontal wells to be drilled and completed prior to mid-2016. Pursuant to the agreement, AKA is required to install and operate, or contract for use of, facilities necessary to receive and purchase production volume committed under the agreement. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm transportation agreement with MarkWest Utica EMG ("MarkWest") while wet natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"). We market our Utica residue gas to various purchasers based on a pipeline basis or NYMEX pricing. We are currently selling all of our residue gas from the MarkWest plant at a daily price based on the Chicago Citygate market, and plan to do so through October 2015.
|
•
|
NGLs
. In the Wattenberg Field, all of our NGLs are sold at the tailgate of the third-party midstream service provider processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. In the Utica Shale, our NGLs are fractionated and marketed by MarkWest and Blue Racer and sold based on month-to-month pricing in various markets. Our NGL production is sold under both short- and long-term contracts.
|
•
|
Wattenberg Field, DJ Basin, Colorado.
Currently, horizontal wells drilled in this area target the reservoirs in the Niobrara and Codell formations. These horizontal wells have a vertical depth ranging from approximately 6,500 to 7,500 feet, with lateral lengths of approximately 4,000 to 7,000 feet. Using pad drilling, we have increased well density in the horizontal Niobrara and Codell plays, which results in reduced per-well costs. We currently estimate that we have
2,600
gross proved undeveloped and probable horizontal projects in the Wattenberg Field drilling inventory. In addition to our horizontal drilling program, we currently operate approximately 2,450 vertical wells in the Wattenberg Field.
|
•
|
Utica Shale, southeastern Ohio.
Wells drilled in this area primarily target the Point Pleasant member of the Utica Shale formation. Our acreage targets the condensate and wet natural gas windows of the Utica Shale play throughout southeastern Ohio. The horizontal wells have a vertical depth ranging from approximately 7,000 to 8,000 feet, with lateral lengths of approximately 4,000 to 7,500 feet. We currently estimate that we have approximately
50
gross probable projects for horizontal drilling in the condensate and wet natural gas windows of the Utica Shale.
|
|
|
Productive Wells
|
||||||||||||||||
|
|
As of December 31, 2014
|
||||||||||||||||
|
|
Crude Oil
|
|
Natural Gas
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field
|
|
403
|
|
|
246.9
|
|
|
2,445
|
|
|
2,200.1
|
|
|
2,848
|
|
|
2,447.0
|
|
Utica Shale
|
|
16
|
|
|
12.7
|
|
|
3
|
|
|
3.0
|
|
|
19
|
|
|
15.7
|
|
Total productive wells
|
|
419
|
|
|
259.6
|
|
|
2,448
|
|
|
2,203.1
|
|
|
2,867
|
|
|
2,462.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2014
|
|
2013 (3)
|
|
2012 (3)(4)(5)
|
||||||
Proved reserves
|
|
|
|
|
|
||||||
Crude oil and condensate
(MMBbls)
|
101
|
|
|
94
|
|
|
59
|
|
|||
Natural gas
(Bcf)
|
537
|
|
|
740
|
|
|
604
|
|
|||
NGLs
(MMBbls)
|
60
|
|
|
49
|
|
|
33
|
|
|||
Total proved reserves
(MMBoe)
|
250
|
|
|
266
|
|
|
193
|
|
|||
Proved developed reserves
(MMBoe)
|
75
|
|
|
76
|
|
|
82
|
|
|||
Estimated future net cash flows
(in millions)
(1)
|
$
|
4,938
|
|
|
$
|
4,323
|
|
|
$
|
2,756
|
|
PV-10 (
in millions)
(2)
|
$
|
3,450
|
|
|
$
|
2,704
|
|
|
$
|
1,709
|
|
Standardized measure
(in millions)
|
$
|
2,306
|
|
|
$
|
1,782
|
|
|
$
|
1,168
|
|
(1)
|
Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately
$7.3 billion
,
$6.4 billion
and
$4.0 billion
as of December 31,
2014
,
2013
and
2012
, respectively, less an internally-estimated future income tax expense of approximately
$2.3 billion
,
$2.1 billion
and
$1.2 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 I, 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)
|
Includes estimated reserve data related to our Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of these assets.
|
|
As of December 31,
|
||||||
|
2013
|
|
2012
|
||||
Proved reserves
|
|
|
|
||||
Natural gas
(Bcf)
|
237
|
|
|
179
|
|
||
Total proved reserves
(MMBoe)
|
40
|
|
|
30
|
|
||
Proved developed reserves (MMBoe)
|
9
|
|
|
7
|
|
||
Estimated future net cash flows
(in millions)
|
$
|
394
|
|
|
$
|
135
|
|
(4)
|
Includes estimated reserve data related to our Piceance and northeast Colorado ("NECO") crude oil and natural gas properties which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance and NECO assets.
|
|
December 31, 2012
|
||
Proved reserves
|
|
||
Crude oil and condensate
(MMBbls)
|
0.1
|
|
|
Natural gas
(Bcf)
|
84
|
|
|
Total proved reserves
(MMBoe)
|
14
|
|
|
Proved developed reserves
(MMBoe)
|
14
|
|
|
Estimated future net cash flows
(in millions)
|
$
|
56
|
|
(5)
|
Includes estimated reserve data related to our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties, which were divested in December 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to these assets.
|
|
December 31, 2012
|
||
Proved reserves
|
|
||
Natural gas
(Bcf)
|
11
|
|
|
Total proved reserves
(MMBoe)
|
2
|
|
|
Proved developed reserves
(MMBoe)
|
2
|
|
|
Estimated future net cash flows
(in millions)
|
$
|
3
|
|
|
|
As of December 31, 2014
|
|||||||||||||
Operating Region/Area
|
|
Crude Oil and Condensate (MBbls)
|
|
Natural Gas
(MMcf) |
|
NGLs
(MBbls)
|
|
Crude Oil
Equivalent (MBoe) |
|
Percent
|
|||||
Proved developed
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
25,339
|
|
|
174,680
|
|
|
16,397
|
|
|
70,849
|
|
|
95
|
%
|
Utica Shale
|
|
1,459
|
|
|
11,953
|
|
|
605
|
|
|
4,056
|
|
|
5
|
%
|
Total proved developed
|
|
26,798
|
|
|
186,633
|
|
|
17,002
|
|
|
74,905
|
|
|
100
|
%
|
Proved undeveloped
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
73,185
|
|
|
347,525
|
|
|
42,913
|
|
|
174,019
|
|
|
99
|
%
|
Utica Shale
|
|
532
|
|
|
2,814
|
|
|
204
|
|
|
1,205
|
|
|
1
|
%
|
Total proved undeveloped
|
|
73,717
|
|
|
350,339
|
|
|
43,117
|
|
|
175,224
|
|
|
100
|
%
|
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
98,524
|
|
|
522,205
|
|
|
59,310
|
|
|
244,868
|
|
|
98
|
%
|
Utica Shale
|
|
1,991
|
|
|
14,767
|
|
|
809
|
|
|
5,261
|
|
|
2
|
%
|
Total proved reserves
|
|
100,515
|
|
|
536,972
|
|
|
60,119
|
|
|
250,129
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing Scenario - NYMEX
|
|
|
|
|
||||||||
|
Crude Oil (per Bbl)*
|
|
Natural Gas (per MMBtu)*
|
|
Proved Reserves (MMBoe)
|
|
% Change from December 31, 2014 Estimated Reserves
|
||||||
2014 Reserve Report
|
$
|
94.99
|
|
|
$
|
4.35
|
|
|
250.1
|
|
|
—
|
|
Scenario A
|
70.00
|
|
|
4.00
|
|
|
238.0
|
|
|
(5
|
)%
|
||
Scenario B
|
60.00
|
|
|
3.50
|
|
|
234.0
|
|
|
(7
|
)%
|
||
Scenario C
|
50.00
|
|
|
3.25
|
|
|
227.0
|
|
|
(9
|
)%
|
*
|
These prices are indices and do not include basin differentials for crude oil and natural gas. The above reserve stress-test scenarios were calculated using the indicated index prices, less the year-end 2014 differentials we experienced for the respective commodity by basin.
|
|
|
As of December 31, 2014
|
||||||||||||||||
|
|
Developed
|
|
Undeveloped (1)
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field
|
|
97,900
|
|
|
88,500
|
|
|
8,100
|
|
|
7,000
|
|
|
106,000
|
|
|
95,500
|
|
Utica Shale
|
|
3,600
|
|
|
3,000
|
|
|
68,200
|
|
|
63,800
|
|
|
71,800
|
|
|
66,800
|
|
Total acreage
|
|
101,500
|
|
|
91,500
|
|
|
76,300
|
|
|
70,800
|
|
|
177,800
|
|
|
162,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Approximately
2%
,
8%
and
20%
of our undeveloped leaseholds expire during 2015, 2016 and 2017, respectively, primarily in the Utica Shale. Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production.
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
Operating Region
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field
|
|
158
|
|
|
85.9
|
|
|
97
|
|
|
61.2
|
|
|
66
|
|
|
43.0
|
|
Utica Shale
|
|
9
|
|
|
8.0
|
|
|
11
|
|
|
8.7
|
|
|
1
|
|
|
1.0
|
|
Other (1)
|
|
4
|
|
|
2.0
|
|
|
10
|
|
|
5.0
|
|
|
16
|
|
|
12.5
|
|
Total wells drilled
|
|
171
|
|
|
95.9
|
|
|
118
|
|
|
74.9
|
|
|
83
|
|
|
56.5
|
|
(1)
|
Includes drilling activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.
|
|
|
Net Development Well Drilling Activity
|
||||||||||||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
||||||
Wattenberg Field
|
|
90.7
|
|
42.8
|
|
1.7
|
(1)
|
53.5
|
|
|
15.6
|
|
|
0.1
|
|
|
31.3
|
|
|
7.7
|
|
|
—
|
|
Utica Shale
|
|
7.0
|
|
3.0
|
|
1.0
|
(1)
|
3.0
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other (2)
|
|
2.0
|
|
—
|
|
—
|
|
3.5
|
|
|
2.0
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
—
|
|
Total net development wells
|
|
99.7
|
|
45.8
|
|
2.7
|
|
60.0
|
|
|
19.6
|
|
|
0.1
|
|
|
32.8
|
|
|
7.7
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents two mechanical failures in the Wattenberg Field and one mechanical failure in the Utica Shale that resulted in the plugging and abandonment of the respective wells.
|
(2)
|
Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.
|
|
|
Net Exploratory Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|||||||||
Utica Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|
1.7
|
|
Other (1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total net exploratory wells
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|
1.7
|
|
(1)
|
Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014.
|
•
|
bond requirements in order to drill or operate wells;
|
•
|
well locations;
|
•
|
drilling and casing methods;
|
•
|
surface use and restoration of well properties;
|
•
|
well plugging and abandoning;
|
•
|
fluid disposal; and
|
•
|
air emissions.
|
•
|
costs of providing service, including depreciation expense;
|
•
|
allowed rate of return, including the equity component of the capital structure and related income taxes; and
|
•
|
volume throughput assumptions.
|
•
|
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.
|
•
|
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 the area 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.
|
•
|
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.
|
•
|
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 utilize 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;
|
•
|
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.
|
•
|
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.
|
•
|
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 will be subject to significant new capital, margin and business conduct 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.
|
•
|
the organization of our board of directors as a classified board, which allows no more than one-third of our directors to be elected each year;
|
•
|
limitations on the ability of our shareholders to call special meetings; and
|
•
|
certain Nevada anti-takeover statutes.
|
|
|
||||||
|
High
|
|
Low
|
||||
|
|
|
|
||||
January 1 - March 31, 2013
|
$
|
53.80
|
|
|
$
|
33.39
|
|
April 1 - June 30, 2013
|
55.56
|
|
|
38.02
|
|
||
July 1 - September 30, 2013
|
66.03
|
|
|
51.46
|
|
||
October 1 - December 31, 2013
|
73.93
|
|
|
51.32
|
|
||
January 1 - March 31, 2014
|
64.27
|
|
|
44.72
|
|
||
April 1 - June 30, 2014
|
70.44
|
|
|
56.88
|
|
||
July 1 - September 30, 2014
|
63.73
|
|
|
49.82
|
|
||
October 1 - December 31, 2014
|
50.95
|
|
|
27.91
|
|
Period
|
|
Total Number of Shares Purchased (1)
|
|
Average Price Paid per Share
|
|||
|
|
|
|
|
|||
October 1 - 31, 2014
|
|
5,632
|
|
|
$
|
45.94
|
|
November 1 - 30, 2014
|
|
2,083
|
|
|
34.33
|
|
|
December 1 - 31, 2014
|
|
15,304
|
|
|
41.27
|
|
|
Total fourth quarter purchases
|
|
23,019
|
|
|
41.79
|
|
(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,
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
|
(in millions, except per share data and as noted)
|
||||||||||||||||||
Statement of Operations (From Continuing Operations):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, natural gas and NGLs sales
|
|
$
|
471.4
|
|
|
$
|
340.8
|
|
|
$
|
228.0
|
|
|
$
|
216.1
|
|
|
$
|
144.8
|
|
Commodity price risk management gain (loss), net
|
|
310.3
|
|
|
$
|
(23.9
|
)
|
|
29.3
|
|
|
39.4
|
|
|
59.4
|
|
||||
Total revenues
|
|
856.2
|
|
|
392.7
|
|
|
307.1
|
|
|
323.3
|
|
|
274.8
|
|
|||||
Income (loss) from continuing operations
|
|
107.3
|
|
|
(21.1
|
)
|
|
(19.4
|
)
|
|
23.2
|
|
|
23.8
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
3.00
|
|
|
$
|
(0.65
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.98
|
|
|
$
|
1.23
|
|
Diluted
|
|
2.93
|
|
|
(0.65
|
)
|
|
(0.70
|
)
|
|
0.97
|
|
|
1.21
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash from:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
$
|
174.7
|
|
|
$
|
151.8
|
|
|
$
|
143.9
|
|
Investing activities
|
|
(474.1
|
)
|
|
(217.1
|
)
|
|
(451.9
|
)
|
|
(300.9
|
)
|
|
(142.3
|
)
|
|||||
Financing activities
|
|
60.3
|
|
|
248.7
|
|
|
271.4
|
|
|
171.5
|
|
|
(20.6
|
)
|
|||||
Capital expenditures
|
|
628.6
|
|
|
394.9
|
|
|
347.7
|
|
|
162.7
|
|
|
143.0
|
|
|||||
Acquisitions of crude oil and natural gas properties
|
|
—
|
|
|
9.7
|
|
|
312.2
|
|
|
158.1
|
|
|
—
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
2,340.6
|
|
|
$
|
2,025.2
|
|
|
$
|
1,698.0
|
|
|
$
|
1,389.0
|
|
|
$
|
1,250.3
|
|
Working capital
|
|
30.3
|
|
|
112.4
|
|
|
(22.0
|
)
|
|
16.2
|
|
|
32.9
|
|
|||||
Long-term debt
|
|
664.9
|
|
|
605.0
|
|
|
532.2
|
|
|
295.7
|
|
|
280.7
|
|
|||||
Total equity
|
|
1,137.4
|
|
|
967.6
|
|
|
664.1
|
|
|
642.2
|
|
|
538.6
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pricing and Lease Operating Expenses From to Continuing Operations (per Boe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Average sales price (excluding net settlements on derivatives)
|
|
$
|
50.72
|
|
|
$
|
52.23
|
|
|
$
|
46.85
|
|
|
$
|
49.97
|
|
|
$
|
43.38
|
|
Average lease operating expenses
|
|
4.36
|
|
|
4.78
|
|
|
4.57
|
|
|
4.56
|
|
|
3.97
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production (MBoe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production from continuing operations
|
|
9,294.4
|
|
|
6,524.7
|
|
|
4,866.5
|
|
|
4,324.4
|
|
|
3,336.6
|
|
|||||
Production from discontinued operations
|
|
1,093.0
|
|
|
2,032.6
|
|
|
3,458.7
|
|
|
3,596.3
|
|
|
3,102.8
|
|
|||||
Total production
|
|
10,387.4
|
|
|
8,557.3
|
|
|
8,325.2
|
|
|
7,920.7
|
|
|
6,439.4
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total proved reserves (MMBoe) (1)(2)(3)
|
|
250.1
|
|
|
265.8
|
|
|
192.8
|
|
|
169.3
|
|
|
143.4
|
|
(1)
|
Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe, 30 MMBoe, 22 MMBoe and 11MMBoe as of December 31, 2013, 2012, 2011 and 2010, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets.
|
(2)
|
Includes total proved reserves related to our Piceance Basin and NECO assets of
14
MMBoe,
59
MMBoe, and
76
MMBoe as of December 31, 2012, 2011 and 2010, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance Basin and NECO assets.
|
(3)
|
Includes total proved reserves related to our Permian Basin assets of
11
MMBoe and
5
MMBoe as of December 31, 2011 and 2010, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian Basin assets.
|
•
|
Positive net change in the fair value of unsettled derivatives in 2014 was
$311.1 million
compared to a negative net change in the fair value of unsettled derivative positions of $35.1 million in 2013, as the crude oil and natural gas forward curves shifted significantly lower during the later months of 2014;
|
•
|
Impairment of crude oil and natural gas properties increased to
$163.5 million
in 2014 compared to
$52.5 million
in 2013, primarily related to the
$158.3 million
write-down of our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value,
$112.6 million
of which was for proved producing properties and
$45.7 million
for unproved properties;
|
•
|
General and administrative expense increased to
$115.9 million
in 2014 compared to
$60.0 million
in 2013, primarily attributable to $40.3 million recorded in 2014 in connection with settlement of certain partnership-related class action litigation and litigation arising from bankruptcy proceedings of certain affiliated partnerships;
|
•
|
Depreciation, depletion and amortization expense increased to
$192.5 million
compared to
$115.6 million
in
2013
, mainly due to the increase in production; and
|
•
|
Gain on sale of properties and equipment classified as discontinued operations increased to
$76.5 million
compared to a loss on sale of properties and equipment classified as discontinued operations of
$1.7 million
in 2013.
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
|
|
Percent Change
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
|
2014-2013
|
|
2013-2012
|
||||||||
|
(dollars in millions, except per unit data)
|
|
|
|
|
||||||||||||
Production (1)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (MBbls)
|
4,321.9
|
|
|
2,909.7
|
|
|
1,987.8
|
|
|
48.5
|
%
|
|
46.4
|
%
|
|||
Natural gas (MMcf)
|
19,298.0
|
|
|
15,431.2
|
|
|
12,247.8
|
|
|
25.1
|
%
|
|
26.0
|
%
|
|||
NGLs (MBbls)
|
1,756.2
|
|
|
1,043.2
|
|
|
837.3
|
|
|
68.3
|
%
|
|
24.6
|
%
|
|||
Crude oil equivalent (MBoe) (2)
|
9,294.4
|
|
|
6,524.7
|
|
|
4,866.5
|
|
|
42.4
|
%
|
|
34.1
|
%
|
|||
Average MBoe per day
|
25.5
|
|
|
17.9
|
|
|
13.3
|
|
|
42.4
|
%
|
|
34.4
|
%
|
|||
Crude Oil, Natural Gas and NGLs Sales
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil
|
$
|
348.6
|
|
|
$
|
261.6
|
|
|
$
|
173.5
|
|
|
33.3
|
%
|
|
20.4
|
%
|
Natural gas
|
74.7
|
|
|
50.0
|
|
|
31.6
|
|
|
49.4
|
%
|
|
58.2
|
%
|
|||
NGLs
|
48.1
|
|
|
29.2
|
|
|
22.9
|
|
|
64.7
|
%
|
|
27.5
|
%
|
|||
Total crude oil, natural gas and NGLs sales
|
$
|
471.4
|
|
|
$
|
340.8
|
|
|
$
|
228.0
|
|
|
38.3
|
%
|
|
49.5
|
%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Settlements on Derivatives (3)
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
(3.1
|
)
|
|
$
|
14.3
|
|
|
$
|
44.1
|
|
|
*
|
|
|
(67.6
|
)%
|
Crude oil
|
2.3
|
|
|
(3.1
|
)
|
|
(0.5
|
)
|
|
*
|
|
|
*
|
|
|||
Total net settlements on derivatives
|
$
|
(0.8
|
)
|
|
$
|
11.2
|
|
|
$
|
43.6
|
|
|
*
|
|
|
(74.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price (excluding net settlements on derivatives)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (per Bbl)
|
$
|
80.67
|
|
|
$
|
89.92
|
|
|
$
|
87.27
|
|
|
(10.3
|
)%
|
|
3.0
|
%
|
Natural gas (per Mcf)
|
3.87
|
|
|
3.24
|
|
|
2.58
|
|
|
19.4
|
%
|
|
25.6
|
%
|
|||
NGLs (per Bbl)
|
27.39
|
|
|
27.97
|
|
|
27.33
|
|
|
(2.1
|
)%
|
|
2.3
|
%
|
|||
Crude oil equivalent (per Boe)
|
50.72
|
|
|
52.23
|
|
|
46.85
|
|
|
(2.9
|
)%
|
|
11.5
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Lease Operating Expenses (per Boe)
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
$
|
4.60
|
|
|
$
|
4.37
|
|
|
$
|
3.88
|
|
|
5.3
|
%
|
|
12.6
|
%
|
Utica Shale
|
1.82
|
|
|
1.50
|
|
|
5.86
|
|
|
21.3
|
%
|
|
*
|
|
|||
Other
|
2.04
|
|
|
13.53
|
|
|
12.11
|
|
|
(84.9
|
)%
|
|
11.7
|
%
|
|||
Weighted-average
|
4.36
|
|
|
4.78
|
|
|
4.57
|
|
|
(8.8
|
)%
|
|
4.6
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Natural Gas Marketing Contribution Margin (4)
|
$
|
(0.4
|
)
|
|
$
|
(0.3
|
)
|
|
$
|
0.4
|
|
|
(33.3
|
)%
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Other Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||||
Exploration expense
|
$
|
0.9
|
|
|
$
|
6.3
|
|
|
$
|
18.2
|
|
|
(85.0
|
)%
|
|
(65.2
|
)%
|
Impairment of crude oil and natural gas properties
|
163.5
|
|
|
52.5
|
|
|
5.0
|
|
|
*
|
|
|
*
|
|
|||
General and administrative expense
|
115.9
|
|
|
60.0
|
|
|
54.8
|
|
|
93.2
|
%
|
|
9.4
|
%
|
|||
Depreciation, depletion and amortization
|
192.5
|
|
|
115.6
|
|
|
91.1
|
|
|
66.5
|
%
|
|
26.9
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Loss on extinguishment of debt
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
23.3
|
|
|
*
|
|
|
*
|
|
Interest expense
|
$
|
47.8
|
|
|
$
|
50.1
|
|
|
$
|
47.5
|
|
|
(4.6
|
)%
|
|
5.6
|
%
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
(1)
|
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data.
|
(2)
|
One Bbl of crude oil or NGL equals six Mcf of natural gas.
|
(3)
|
Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing.
|
(4)
|
Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
|
|
|
|
|
|
Change
|
|||||||
Production by Operating Region
|
|
2014
|
|
2013
|
|
2012
|
|
2014-2013
|
|
2013-2012
|
|||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
4,026.7
|
|
|
2,783.1
|
|
|
1,979.1
|
|
|
44.7
|
%
|
|
40.6
|
%
|
Utica Shale
|
|
295.2
|
|
|
122.8
|
|
|
3.0
|
|
|
140.4
|
%
|
|
*
|
|
Other
|
|
—
|
|
|
3.8
|
|
|
5.7
|
|
|
*
|
|
|
(33.3
|
)%
|
Total
|
|
4,321.9
|
|
|
2,909.7
|
|
|
1,987.8
|
|
|
48.5
|
%
|
|
46.4
|
%
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
17,108.9
|
|
|
12,724.3
|
|
|
9,844.7
|
|
|
34.5
|
%
|
|
29.3
|
%
|
Utica Shale
|
|
2,152.9
|
|
|
561.1
|
|
|
2.1
|
|
|
283.7
|
%
|
|
*
|
|
Other
|
|
36.2
|
|
|
2,145.8
|
|
|
2,401.0
|
|
|
(98.3
|
)%
|
|
(10.6
|
)%
|
Total
|
|
19,298.0
|
|
|
15,431.2
|
|
|
12,247.8
|
|
|
25.1
|
%
|
|
26.0
|
%
|
NGLs (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
1,605.7
|
|
|
1,034.4
|
|
|
837.3
|
|
|
55.2
|
%
|
|
23.5
|
%
|
Utica Shale
|
|
150.5
|
|
|
8.8
|
|
|
—
|
|
|
*
|
|
|
*
|
|
Total
|
|
1,756.2
|
|
|
1,043.2
|
|
|
837.3
|
|
|
68.3
|
%
|
|
24.6
|
%
|
Crude oil equivalent (MBoe)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
8,483.8
|
|
|
5,938.2
|
|
|
4,457.3
|
|
|
42.9
|
%
|
|
33.2
|
%
|
Utica Shale
|
|
804.6
|
|
|
225.2
|
|
|
3.3
|
|
|
257.3
|
%
|
|
*
|
|
Other
|
|
6.0
|
|
|
361.3
|
|
|
405.9
|
|
|
(98.3
|
)%
|
|
(11.0
|
)%
|
Total
|
|
9,294.4
|
|
|
6,524.7
|
|
|
4,866.5
|
|
|
42.4
|
%
|
|
34.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
|
|
Year Ended December 31,
|
||||||||||||||||
Average Sales Price by Operating Region
|
|
|
|
|
|
|
|
Change
|
||||||||||
(excluding net settlements on derivatives)
|
|
2014
|
|
2013
|
|
2012
|
|
2014-2013
|
|
2013-2012
|
||||||||
Crude oil (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
$
|
80.61
|
|
|
$
|
89.83
|
|
|
$
|
87.27
|
|
|
(10.3
|
)%
|
|
2.9
|
%
|
Utica Shale
|
|
81.52
|
|
|
91.90
|
|
|
76.57
|
|
|
(11.3
|
)%
|
|
20.0
|
%
|
|||
Other
|
|
—
|
|
|
92.88
|
|
|
92.72
|
|
|
*
|
|
|
0.2
|
%
|
|||
Weighted-average price
|
|
80.67
|
|
|
89.92
|
|
|
87.27
|
|
|
(10.3
|
)%
|
|
3.0
|
%
|
|||
Natural gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
3.94
|
|
|
3.25
|
|
|
2.61
|
|
|
21.2
|
%
|
|
24.5
|
%
|
|||
Utica Shale
|
|
3.35
|
|
|
2.74
|
|
|
1.66
|
|
|
22.3
|
%
|
|
65.1
|
%
|
|||
Other
|
|
3.90
|
|
|
3.31
|
|
|
2.49
|
|
|
17.8
|
%
|
|
32.9
|
%
|
|||
Weighted-average price
|
|
3.87
|
|
|
3.24
|
|
|
2.58
|
|
|
19.4
|
%
|
|
25.6
|
%
|
|||
NGLs (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
25.95
|
|
|
27.83
|
|
|
27.33
|
|
|
(6.8
|
)%
|
|
1.8
|
%
|
|||
Utica Shale
|
|
42.76
|
|
|
43.70
|
|
|
—
|
|
|
(2.2
|
)%
|
|
*
|
|
|||
Weighted-average price
|
|
27.39
|
|
|
27.97
|
|
|
27.33
|
|
|
(2.1
|
)%
|
|
2.3
|
%
|
|||
Crude oil equivalent (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
51.10
|
|
|
53.91
|
|
|
49.64
|
|
|
(5.2
|
)%
|
|
8.6
|
%
|
|||
Utica Shale
|
|
46.87
|
|
|
58.68
|
|
|
69.55
|
|
|
(20.1
|
)%
|
|
(15.6
|
)%
|
|||
Other
|
|
23.42
|
|
|
20.59
|
|
|
16.02
|
|
|
13.7
|
%
|
|
28.5
|
%
|
|||
Weighted-average price
|
|
50.72
|
|
|
52.23
|
|
|
46.85
|
|
|
(2.9
|
)%
|
|
11.5
|
%
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in millions)
|
||||||
Increase in production
|
$
|
159.5
|
|
|
$
|
94.3
|
|
Increase (decrease) in average crude oil price
|
(40.0
|
)
|
|
7.7
|
|
||
Increase in average natural gas price
|
12.1
|
|
|
10.2
|
|
||
Increase (decrease) in average NGLs price
|
(1.0
|
)
|
|
0.6
|
|
||
Total increase in crude oil, natural gas and NGLs sales revenue
|
$
|
130.6
|
|
|
$
|
112.8
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions, except per unit data)
|
||||||||||
|
|
|
|
|
|
||||||
Lease operating expenses
|
$
|
40.5
|
|
|
$
|
31.2
|
|
|
$
|
22.2
|
|
Production taxes
|
25.6
|
|
|
21.8
|
|
|
13.9
|
|
|||
Transportation, gathering and processing expenses
|
4.6
|
|
|
5.2
|
|
|
2.8
|
|
|||
Overhead and other production expenses
|
12.9
|
|
|
6.7
|
|
|
10.5
|
|
|||
Total production costs
|
$
|
83.6
|
|
|
$
|
64.9
|
|
|
$
|
49.4
|
|
Total production costs per Boe
|
$
|
9.00
|
|
|
$
|
9.94
|
|
|
$
|
10.15
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Commodity price risk management gain (loss), net:
|
|
|
|
|
|
||||||
Net settlements:
|
|
|
|
|
|
||||||
Natural gas
|
$
|
(3.1
|
)
|
|
$
|
14.3
|
|
|
$
|
44.1
|
|
Crude oil
|
2.3
|
|
|
(3.1
|
)
|
|
(0.5
|
)
|
|||
Total net settlements
|
(0.8
|
)
|
|
11.2
|
|
|
43.6
|
|
|||
Change in fair value of unsettled derivatives:
|
|
|
|
|
|
||||||
Reclassification of settlements included in prior period changes in fair value of derivatives
|
13.3
|
|
|
(28.7
|
)
|
|
(25.1
|
)
|
|||
Natural gas fixed price swaps
|
30.6
|
|
|
4.3
|
|
|
(0.2
|
)
|
|||
Natural gas basis swaps
|
—
|
|
|
(4.3
|
)
|
|
(0.5
|
)
|
|||
Natural gas collars
|
11.1
|
|
|
3.8
|
|
|
2.1
|
|
|||
Crude oil fixed price swaps
|
206.5
|
|
|
(9.1
|
)
|
|
7.7
|
|
|||
Crude oil collars
|
49.6
|
|
|
(1.1
|
)
|
|
1.7
|
|
|||
Net change in fair value of unsettled derivatives
|
311.1
|
|
|
(35.1
|
)
|
|
(14.3
|
)
|
|||
Total commodity price risk management gain (loss), net
|
$
|
310.3
|
|
|
$
|
(23.9
|
)
|
|
$
|
29.3
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Natural gas sales revenue
|
$
|
71.4
|
|
|
$
|
68.9
|
|
|
$
|
44.9
|
|
Net settlements from derivatives
|
(0.2
|
)
|
|
0.5
|
|
|
2.2
|
|
|||
Net change in fair value of unsettled derivatives
|
0.4
|
|
|
0.4
|
|
|
(1.7
|
)
|
|||
Total sales from natural gas marketing
|
71.6
|
|
|
69.8
|
|
|
45.4
|
|
|||
|
|
|
|
|
|
||||||
Costs of natural gas purchases
|
70.1
|
|
|
68.1
|
|
|
43.3
|
|
|||
Net settlements from derivatives
|
(0.3
|
)
|
|
0.3
|
|
|
2.0
|
|
|||
Net change in fair value of unsettled derivatives
|
0.4
|
|
|
0.4
|
|
|
(1.6
|
)
|
|||
Other
|
1.8
|
|
|
1.3
|
|
|
1.3
|
|
|||
Total costs of natural gas marketing
|
72.0
|
|
|
70.1
|
|
|
45.0
|
|
|||
|
|
|
|
|
|
||||||
Natural gas marketing contribution margin
|
$
|
(0.4
|
)
|
|
$
|
(0.3
|
)
|
|
$
|
0.4
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Exploratory dry hole costs
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14.5
|
|
Geological and geophysical costs
|
|
—
|
|
|
0.7
|
|
|
0.7
|
|
|||
Operating, personnel and other
|
|
0.9
|
|
|
5.6
|
|
|
3.0
|
|
|||
Total exploration expense
|
|
$
|
0.9
|
|
|
$
|
6.3
|
|
|
$
|
18.2
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Continuing operations:
|
|
|
|
|
|
||||||
Impairment of proved properties
|
$
|
112.6
|
|
|
$
|
48.8
|
|
|
$
|
—
|
|
Impairment of unproved properties
|
45.7
|
|
|
0.5
|
|
|
1.0
|
|
|||
Amortization of individually insignificant unproved properties
|
4.4
|
|
|
3.2
|
|
|
4.0
|
|
|||
Other
|
0.8
|
|
|
—
|
|
|
—
|
|
|||
Total impairment of crude oil and natural gas properties
|
$
|
163.5
|
|
|
$
|
52.5
|
|
|
$
|
5.0
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
Operating Region/Area
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(per Boe)
|
||||||||||
Wattenberg Field
|
|
$
|
19.26
|
|
|
$
|
17.68
|
|
|
$
|
18.20
|
|
Utica Shale
|
|
31.19
|
|
|
24.87
|
|
|
—
|
|
|||
Other
|
|
—
|
|
|
2.66
|
|
|
12.50
|
|
|||
Total weighted-average
|
|
20.28
|
|
|
17.05
|
|
|
17.74
|
|
|
|
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)
|
|
$
|
671.0
|
|
|
$
|
—
|
|
|
$
|
115.0
|
|
|
$
|
56.0
|
|
|
$
|
500.0
|
|
Derivative contracts (3)
|
|
0.8
|
|
|
0.6
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|||||
Production tax liability
|
|
47.7
|
|
|
21.3
|
|
|
26.4
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
73.9
|
|
|
1.9
|
|
|
8.5
|
|
|
9.9
|
|
|
53.6
|
|
|||||
Other liabilities (4)
|
|
3.6
|
|
|
0.3
|
|
|
0.5
|
|
|
0.7
|
|
|
2.1
|
|
|||||
|
|
797.0
|
|
|
24.1
|
|
|
150.6
|
|
|
66.6
|
|
|
555.7
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commitments, contingencies and other arrangements (5)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest on long-term debt (6)
|
|
319.1
|
|
|
46.0
|
|
|
86.0
|
|
|
78.9
|
|
|
108.2
|
|
|||||
Operating leases
|
|
12.8
|
|
|
2.5
|
|
|
4.4
|
|
|
3.8
|
|
|
2.1
|
|
|||||
Firm transportation and processing agreements (7)
|
|
95.9
|
|
|
14.5
|
|
|
34.8
|
|
|
32.6
|
|
|
14.0
|
|
|||||
|
|
427.8
|
|
|
63.0
|
|
|
125.2
|
|
|
115.3
|
|
|
124.3
|
|
|||||
Total
|
|
$
|
1,224.8
|
|
|
$
|
87.1
|
|
|
$
|
275.8
|
|
|
$
|
181.9
|
|
|
$
|
680.0
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Table does not include deferred income tax liability to taxing authorities of
$125.7 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
$6.1 million
in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report.
|
(3)
|
Represents our gross liability related to the fair value of derivative positions.
|
(4)
|
Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.
|
(5)
|
Table does not include an undrawn
$11.7 million
irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or 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. See Note 11, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report.
|
(6)
|
Amounts presented include $301.9 million to the holders of our 7.75% senior notes due 2022 and $5.1 million payable to the holders of our 3.25% convertible senior notes due 2016. Amounts also include $12.1 million payable to the participating banks in our revolving credit facility, of which interest of $4.9 million is related to unutilized commitments at a rate of .38% per annum, $7.1 million related to the outstanding borrowings on our revolving credit facility of
$56.0 million
and $0.1 million related to our undrawn letters of credit.
|
(7)
|
Represents our gross commitment. See Note 11, Commitments and Contingencies - Firm Transportation, Processing and Sales Agreements, to our consolidated financial statements included elsewhere in this report.
|
•
|
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;
|
•
|
ability to generate sufficient cash to service our debt obligations; and
|
•
|
viability of acquisition opportunities and capital expenditure projects, including the related rate of return.
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Adjusted cash flows from operations:
|
|
|
|
|
|
||||||
Adjusted cash flows from operations
|
$
|
250.2
|
|
|
$
|
207.8
|
|
|
$
|
163.9
|
|
Changes in assets and liabilities
|
(13.5
|
)
|
|
(48.6
|
)
|
|
10.8
|
|
|||
Net cash from operating activities
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
$
|
174.7
|
|
|
|
|
|
|
|
||||||
Adjusted net income (loss):
|
|
|
|
|
|
||||||
Adjusted net income (loss)
|
$
|
(37.7
|
)
|
|
$
|
0.5
|
|
|
$
|
(120.1
|
)
|
Gain (loss) on commodity derivative instruments
|
309.3
|
|
|
(23.7
|
)
|
|
32.4
|
|
|||
Net settlements on commodity derivative instruments
|
2.0
|
|
|
(13.1
|
)
|
|
(49.5
|
)
|
|||
Tax effect of above adjustments
|
(118.2
|
)
|
|
14.0
|
|
|
6.5
|
|
|||
Net income (loss)
|
$
|
155.4
|
|
|
$
|
(22.3
|
)
|
|
$
|
(130.7
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA to net income (loss):
|
|
|
|
|
|
||||||
Adjusted EBITDA
|
$
|
361.0
|
|
|
$
|
241.0
|
|
|
$
|
196.9
|
|
Gain (loss) on commodity derivative instruments
|
309.3
|
|
|
(23.7
|
)
|
|
32.4
|
|
|||
Net settlements on commodity derivative instruments
|
2.0
|
|
|
(13.1
|
)
|
|
(49.5
|
)
|
|||
Interest expense, net
|
(48.6
|
)
|
|
(51.4
|
)
|
|
(48.3
|
)
|
|||
Income tax provision
|
(99.2
|
)
|
|
12.6
|
|
|
80.2
|
|
|||
Impairment of crude oil and natural gas properties
|
(164.0
|
)
|
|
(53.4
|
)
|
|
(168.2
|
)
|
|||
Depreciation, depletion and amortization
|
(201.7
|
)
|
|
(129.5
|
)
|
|
(146.9
|
)
|
|||
Accretion of asset retirement obligations
|
(3.4
|
)
|
|
(4.8
|
)
|
|
(4.0
|
)
|
|||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
(23.3
|
)
|
|||
Net income (loss)
|
$
|
155.4
|
|
|
$
|
(22.3
|
)
|
|
$
|
(130.7
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA to net cash from operating activities:
|
|
|
|
|
|
||||||
Adjusted EBITDA
|
$
|
361.0
|
|
|
$
|
241.0
|
|
|
$
|
196.9
|
|
Interest expense, net
|
(48.6
|
)
|
|
(51.4
|
)
|
|
(48.3
|
)
|
|||
Exploratory dry hole costs
|
—
|
|
|
—
|
|
|
15.3
|
|
|||
Stock-based compensation
|
17.5
|
|
|
12.9
|
|
|
8.5
|
|
|||
Amortization of debt discount and issuance costs
|
6.9
|
|
|
6.8
|
|
|
7.9
|
|
|||
(Gain) loss on sale of properties and equipment
|
(76.0
|
)
|
|
3.7
|
|
|
(24.3
|
)
|
|||
Other
|
(10.6
|
)
|
|
(5.2
|
)
|
|
7.9
|
|
|||
Changes in assets and liabilities
|
(13.5
|
)
|
|
(48.6
|
)
|
|
10.8
|
|
|||
Net cash from operating activities
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
$
|
174.7
|
|
|
|
|
|
|
|
||||||
PV-10:
|
|
|
|
|
|
||||||
PV-10
|
$
|
3,450.1
|
|
|
$
|
2,703.9
|
|
|
$
|
1,708.9
|
|
Present value of estimated future income tax discounted at 10%
|
(1,143.6
|
)
|
|
(921.7
|
)
|
|
(540.4
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
2,306.5
|
|
|
$
|
1,782.2
|
|
|
$
|
1,168.5
|
|
|
|
Collars
|
|
Fixed-Price Swaps
|
|
Basis Protection Swaps
|
|
|
|||||||||||||||||||||
Commodity/ Index/
Maturity Period
|
|
Quantity
(Gas -
BBtu
(1)
Oil - MBbls)
|
|
Weighted-Average
Contract Price
|
|
Quantity
(Gas -
BBtu
(1)
Oil - MBbls)
|
|
Weighted-
Average
Contract
Price
|
|
Quantity
(BBtu)
(1)
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value
December 31,
2014 (2)
(in millions)
|
|||||||||||||||
|
Floors
|
|
Ceilings
|
|
|
|
|
|
|||||||||||||||||||||
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
NYMEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
2015
|
|
7,340.0
|
|
|
$
|
3.93
|
|
|
$
|
4.31
|
|
|
12,415.0
|
|
|
$
|
4.04
|
|
|
9,600.0
|
|
|
$
|
(0.24
|
)
|
|
$
|
19.1
|
|
2016
|
|
7,820.0
|
|
|
3.88
|
|
|
4.24
|
|
|
19,680.0
|
|
|
3.98
|
|
|
—
|
|
|
—
|
|
|
14.0
|
|
|||||
2017
|
|
5,130.0
|
|
|
3.91
|
|
|
4.34
|
|
|
10,100.0
|
|
|
3.99
|
|
|
—
|
|
|
—
|
|
|
4.0
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
CIG
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,730.0
|
|
|
4.01
|
|
|
—
|
|
|
—
|
|
|
3.4
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total Natural Gas
|
|
20,290.0
|
|
|
|
|
|
|
44,925.0
|
|
|
|
|
9,600.0
|
|
|
|
|
$
|
40.5
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
NYMEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
2015
|
|
686.0
|
|
|
$
|
85.63
|
|
|
$
|
96.86
|
|
|
4,514.0
|
|
|
$
|
89.12
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
164.4
|
|
2016
|
|
1,740.0
|
|
|
77.59
|
|
|
97.55
|
|
|
2,400.0
|
|
|
90.37
|
|
|
—
|
|
|
—
|
|
|
94.6
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total Crude Oil
|
|
2,426.0
|
|
|
|
|
|
|
6,914.0
|
|
|
|
|
—
|
|
|
|
|
259.0
|
|
|||||||||
Total Natural Gas and Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
299.5
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
A standard unit of measurement for natural gas (one BBtu
equals one MMcf).
|
(2)
|
Approximately 20.8% of the fair value of our derivative assets and none of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report.
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
Average Index Closing Price:
|
|
|
|
||||
Crude oil (per Bbl)
|
|
|
|
||||
NYMEX
|
$
|
92.91
|
|
|
$
|
97.97
|
|
Natural gas (per MMBtu)
|
|
|
|
||||
NYMEX
|
$
|
4.42
|
|
|
$
|
3.65
|
|
CIG
|
4.17
|
|
|
3.45
|
|
||
TETCO M-2 (1)
|
3.35
|
|
|
3.50
|
|
||
|
|
|
|
||||
Average Sales Price Realized:
|
|
|
|
||||
Excluding net settlements on derivatives
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
80.67
|
|
|
$
|
89.92
|
|
Natural gas (per Mcf)
|
3.87
|
|
|
3.29
|
|
||
NGLs (per Bbl)
|
27.39
|
|
|
27.97
|
|
Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
|
||
|
|
|
Financial Statements:
|
|
|
|
||
|
||
Consolidated Statements of Operations - Years Ended December 31, 2
014, 2013 and 2012
|
|
|
Consolidated Statements of Cash Flows - Years Ended December 31, 201
4, 2013 and 2012
|
|
|
Consolidated Statements of Equity - Years Ended December 31, 201
4, 2013 and 2012
|
|
|
|
||
|
|
|
Supplemental Information - Unaudited:
|
|
|
|
||
|
||
|
|
|
Financial Statement Schedule:
|
|
|
|
||
|
|
|
As of December 31,
|
|
2014
|
|
2013
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
16,066
|
|
|
$
|
192,642
|
|
Restricted cash
|
|
—
|
|
|
2,211
|
|
||
Accounts receivable, net
|
|
131,204
|
|
|
88,111
|
|
||
Accounts receivable affiliates
|
|
512
|
|
|
6,614
|
|
||
Fair value of derivatives
|
|
187,495
|
|
|
1,521
|
|
||
Deferred income taxes
|
|
—
|
|
|
22,374
|
|
||
Assets held for sale
|
|
—
|
|
|
7,661
|
|
||
Prepaid expenses and other current assets
|
|
5,442
|
|
|
4,679
|
|
||
Total current assets
|
|
340,719
|
|
|
325,813
|
|
||
Properties and equipment, net
|
|
1,800,186
|
|
|
1,480,986
|
|
||
Assets held for sale
|
|
2,874
|
|
|
182,136
|
|
||
Fair value of derivatives
|
|
112,819
|
|
|
4,503
|
|
||
Other assets
|
|
83,990
|
|
|
31,765
|
|
||
Total Assets
|
|
$
|
2,340,588
|
|
|
$
|
2,025,203
|
|
|
|
|
|
|
||||
Liabilities and Shareholders' Equity
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
130,321
|
|
|
$
|
101,688
|
|
Accounts payable affiliates
|
|
—
|
|
|
41
|
|
||
Production tax liability
|
|
21,314
|
|
|
22,232
|
|
||
Fair value of derivatives
|
|
570
|
|
|
14,689
|
|
||
Funds held for distribution
|
|
27,186
|
|
|
31,040
|
|
||
Accrued interest payable
|
|
9,109
|
|
|
9,033
|
|
||
Deferred income taxes
|
|
59,174
|
|
|
—
|
|
||
Liabilities held for sale
|
|
—
|
|
|
12,069
|
|
||
Other accrued expenses
|
|
62,717
|
|
|
22,628
|
|
||
Total current liabilities
|
|
310,391
|
|
|
213,420
|
|
||
Long-term debt
|
|
664,923
|
|
|
604,990
|
|
||
Deferred income taxes
|
|
125,693
|
|
|
118,767
|
|
||
Asset retirement obligation
|
|
71,992
|
|
|
37,638
|
|
||
Fair value of derivatives
|
|
197
|
|
|
2,842
|
|
||
Liabilities held for sale
|
|
—
|
|
|
55,915
|
|
||
Other liabilities
|
|
30,033
|
|
|
24,037
|
|
||
Total liabilities
|
|
1,203,229
|
|
|
1,057,609
|
|
||
|
|
|
|
|
||||
Commitments and contingent liabilities
|
|
|
|
|
||||
|
|
|
|
|
||||
Shareholders' equity
|
|
|
|
|
||||
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued
|
|
—
|
|
|
—
|
|
||
Common shares - par value $0.01 per share, 150,000,000 authorized, 35,927,985 and 35,675,656 issued as of December 31, 2014 and 2013, respectively
|
|
359
|
|
|
357
|
|
||
Additional paid-in capital
|
|
689,209
|
|
|
674,211
|
|
||
Retained earnings
|
|
448,702
|
|
|
293,267
|
|
||
Treasury shares - at cost, 21,643 and 5,508 as of December 31, 2014 and 2013, respectively
|
|
(911
|
)
|
|
(241
|
)
|
||
Total shareholders' equity
|
|
1,137,359
|
|
|
967,594
|
|
||
Total Liabilities and Shareholders' Equity
|
|
$
|
2,340,588
|
|
|
$
|
2,025,203
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
|
$
|
471,413
|
|
|
$
|
340,795
|
|
|
$
|
227,990
|
|
Sales from natural gas marketing
|
|
71,571
|
|
|
69,787
|
|
|
45,371
|
|
|||
Commodity price risk management gain (loss), net
|
|
310,304
|
|
|
(23,919
|
)
|
|
29,279
|
|
|||
Well operations, pipeline income and other
|
|
2,919
|
|
|
6,002
|
|
|
4,496
|
|
|||
Total revenues
|
|
856,207
|
|
|
392,665
|
|
|
307,136
|
|
|||
Costs, expenses and other
|
|
|
|
|
|
|
||||||
Production costs
|
|
83,624
|
|
|
64,850
|
|
|
49,383
|
|
|||
Cost of natural gas marketing
|
|
72,015
|
|
|
70,084
|
|
|
45,023
|
|
|||
Exploration expense
|
|
947
|
|
|
6,334
|
|
|
18,202
|
|
|||
Impairment of crude oil and natural gas properties
|
|
163,532
|
|
|
52,509
|
|
|
5,020
|
|
|||
General and administrative expense
|
|
115,859
|
|
|
59,956
|
|
|
54,817
|
|
|||
Depreciation, depletion and amortization
|
|
192,528
|
|
|
115,624
|
|
|
91,111
|
|
|||
Accretion of asset retirement obligations
|
|
3,415
|
|
|
4,566
|
|
|
3,670
|
|
|||
(Gain) loss on sale of properties and equipment
|
|
507
|
|
|
2,022
|
|
|
(183
|
)
|
|||
Total cost, expenses and other
|
|
632,427
|
|
|
375,945
|
|
|
267,043
|
|
|||
Income from operations
|
|
223,780
|
|
|
16,720
|
|
|
40,093
|
|
|||
Interest expense
|
|
(47,842
|
)
|
|
(50,143
|
)
|
|
(47,505
|
)
|
|||
Interest income
|
|
1,290
|
|
|
460
|
|
|
7
|
|
|||
Loss on extinguishment of debt
|
|
—
|
|
|
—
|
|
|
(23,283
|
)
|
|||
Income (loss) from continuing operations before income taxes
|
|
177,228
|
|
|
(32,963
|
)
|
|
(30,688
|
)
|
|||
Provision for income taxes
|
|
(69,967
|
)
|
|
11,852
|
|
|
11,333
|
|
|||
Income (loss) from continuing operations
|
|
107,261
|
|
|
(21,111
|
)
|
|
(19,355
|
)
|
|||
Income (loss) from discontinued operations, net of tax
|
|
48,174
|
|
|
(1,190
|
)
|
|
(111,357
|
)
|
|||
Net income (loss)
|
|
$
|
155,435
|
|
|
$
|
(22,301
|
)
|
|
$
|
(130,712
|
)
|
|
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
3.00
|
|
|
$
|
(0.65
|
)
|
|
$
|
(0.70
|
)
|
Income (loss) from discontinued operations, net of tax
|
|
1.34
|
|
|
(0.04
|
)
|
|
(4.02
|
)
|
|||
Net income (loss)
|
|
$
|
4.34
|
|
|
$
|
(0.69
|
)
|
|
$
|
(4.72
|
)
|
|
|
|
|
|
|
|
||||||
Diluted
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
2.93
|
|
|
$
|
(0.65
|
)
|
|
$
|
(0.70
|
)
|
Income (loss) from discontinued operations, net of tax
|
|
1.31
|
|
|
(0.04
|
)
|
|
(4.02
|
)
|
|||
Net income (loss)
|
|
$
|
4.24
|
|
|
$
|
(0.69
|
)
|
|
$
|
(4.72
|
)
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
||||||
Basic
|
|
35,784
|
|
|
32,426
|
|
|
27,677
|
|
|||
Diluted
|
|
36,678
|
|
|
32,426
|
|
|
27,677
|
|
|||
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
155,435
|
|
|
$
|
(22,301
|
)
|
|
$
|
(130,712
|
)
|
Adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
|
|
|
|
|
||||||
Net change in fair value of unsettled derivatives
|
|
(311,281
|
)
|
|
36,801
|
|
|
17,134
|
|
|||
Depreciation, depletion and amortization
|
|
201,656
|
|
|
129,518
|
|
|
146,879
|
|
|||
Impairment of crude oil and natural gas properties
|
|
163,965
|
|
|
53,438
|
|
|
168,149
|
|
|||
Prepaid well costs write-offs
|
|
3,062
|
|
|
74
|
|
|
3,916
|
|
|||
Loss on extinguishment of debt
|
|
—
|
|
|
—
|
|
|
23,283
|
|
|||
Exploratory dry hole costs
|
|
—
|
|
|
—
|
|
|
15,347
|
|
|||
Accretion of asset retirement obligation
|
|
3,455
|
|
|
4,747
|
|
|
4,060
|
|
|||
Stock-based compensation
|
|
17,518
|
|
|
12,880
|
|
|
8,495
|
|
|||
Excess tax benefits from stock-based compensation
|
|
(1,999
|
)
|
|
(2,489
|
)
|
|
—
|
|
|||
(Gain) loss from sale of properties and equipment
|
|
(75,972
|
)
|
|
3,722
|
|
|
(24,273
|
)
|
|||
Amortization of debt discount and issuance costs
|
|
6,938
|
|
|
6,783
|
|
|
7,864
|
|
|||
Deferred income taxes
|
|
88,474
|
|
|
(15,883
|
)
|
|
(80,379
|
)
|
|||
Other
|
|
(1,076
|
)
|
|
460
|
|
|
4,123
|
|
|||
Total adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
94,740
|
|
|
230,051
|
|
|
294,598
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
(34,598
|
)
|
|
(41,509
|
)
|
|
6,843
|
|
|||
Other assets
|
|
(3,296
|
)
|
|
3,461
|
|
|
(2,908
|
)
|
|||
Restricted cash
|
|
2,214
|
|
|
(8
|
)
|
|
8,859
|
|
|||
Production tax liability
|
|
3,358
|
|
|
4,121
|
|
|
2,499
|
|
|||
Accounts payable and accrued expenses
|
|
21,453
|
|
|
(11,485
|
)
|
|
(5,050
|
)
|
|||
Other liabilities
|
|
(2,617
|
)
|
|
(3,165
|
)
|
|
592
|
|
|||
Total changes in assets and liabilities
|
|
(13,486
|
)
|
|
(48,585
|
)
|
|
10,835
|
|
|||
Net cash from operating activities
|
|
236,689
|
|
|
159,165
|
|
|
174,721
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(628,592
|
)
|
|
(394,948
|
)
|
|
(347,729
|
)
|
|||
Acquisition of crude oil and natural gas properties, net of cash acquired
|
|
—
|
|
|
(9,658
|
)
|
|
(312,223
|
)
|
|||
Proceeds from acquisition adjustments
|
|
—
|
|
|
7,579
|
|
|
14,469
|
|
|||
Proceeds from sale of properties and equipment, net
|
|
154,457
|
|
|
179,919
|
|
|
193,544
|
|
|||
Net cash from investing activities
|
|
(474,135
|
)
|
|
(217,108
|
)
|
|
(451,939
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from revolving credit facility
|
|
263,750
|
|
|
260,250
|
|
|
682,000
|
|
|||
Repayment of revolving credit facility
|
|
(200,000
|
)
|
|
(283,500
|
)
|
|
(839,750
|
)
|
|||
Proceeds from senior notes offering
|
|
—
|
|
|
—
|
|
|
500,000
|
|
|||
Redemption of senior notes
|
|
—
|
|
|
—
|
|
|
(221,840
|
)
|
|||
Payment of debt issuance costs
|
|
(88
|
)
|
|
(2,352
|
)
|
|
(11,969
|
)
|
|||
Proceeds from sale of common stock, net of issuance costs
|
|
—
|
|
|
275,847
|
|
|
164,496
|
|
|||
Excess tax benefits from stock-based compensation
|
|
1,999
|
|
|
2,489
|
|
|
—
|
|
|||
Purchase of treasury shares
|
|
(5,392
|
)
|
|
(4,133
|
)
|
|
(1,500
|
)
|
|||
Proceeds from exercise of stock options
|
|
—
|
|
|
128
|
|
|
—
|
|
|||
Net cash from financing activities
|
|
60,269
|
|
|
248,729
|
|
|
271,437
|
|
|||
Net change in cash and cash equivalents
|
|
(177,177
|
)
|
|
190,786
|
|
|
(5,781
|
)
|
|||
Cash and cash equivalents, beginning of year
|
|
193,243
|
|
|
2,457
|
|
|
8,238
|
|
|||
Cash and cash equivalents, end of year
|
|
$
|
16,066
|
|
|
$
|
193,243
|
|
|
$
|
2,457
|
|
|
|
|
|
|
|
|
||||||
Supplemental cash flow information:
|
|
|
|
|
|
|
||||||
Cash payments for (receipts from):
|
|
|
|
|
|
|
||||||
Interest, net of capitalized interest
|
|
$
|
46,809
|
|
|
$
|
48,844
|
|
|
$
|
41,768
|
|
Income taxes
|
|
1,800
|
|
|
(3,014
|
)
|
|
1,845
|
|
|||
Non-cash investing activities:
|
|
|
|
|
|
|
||||||
Change in accounts payable related to capital expenditures
|
|
39,667
|
|
|
33,328
|
|
|
288
|
|
|||
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal
|
|
33,250
|
|
|
2,112
|
|
|
11,967
|
|
|||
Change in accounts receivable related to sale of properties and equipment
|
|
—
|
|
|
808
|
|
|
—
|
|
|||
Change in other assets related to sale of properties and equipment
|
|
39,048
|
|
|
3,350
|
|
|
—
|
|
|||
See Note 15,
Acquisitions
, for non-cash transactions related to our acquisitions
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2014
|
|
2013
|
|
2012
|
||||||
Common shares, issued:
|
|
|
|
|
|
|
||||||
Shares beginning of year
|
|
35,675,656
|
|
|
30,294,224
|
|
|
23,634,958
|
|
|||
Shares issued pursuant to sale of equity
|
|
—
|
|
|
5,175,000
|
|
|
6,500,000
|
|
|||
Exercise of stock options
|
|
—
|
|
|
10,763
|
|
|
—
|
|
|||
Issuance of stock awards, net of forfeitures
|
|
253,032
|
|
|
212,926
|
|
|
173,737
|
|
|||
Retirement of treasury shares
|
|
(703
|
)
|
|
(17,257
|
)
|
|
(14,471
|
)
|
|||
Shares end of year
|
|
35,927,985
|
|
|
35,675,656
|
|
|
30,294,224
|
|
|||
Treasury shares:
|
|
|
|
|
|
|
||||||
Shares beginning of year
|
|
5,508
|
|
|
5,059
|
|
|
2,938
|
|
|||
Purchase of treasury shares
|
|
97,646
|
|
|
84,642
|
|
|
44,576
|
|
|||
Issuance of treasury shares
|
|
(83,208
|
)
|
|
(67,334
|
)
|
|
(28,587
|
)
|
|||
Retirement of treasury shares
|
|
(703
|
)
|
|
(17,257
|
)
|
|
(14,471
|
)
|
|||
Non-employee directors' deferred compensation plan
|
|
2,400
|
|
|
398
|
|
|
603
|
|
|||
Shares end of year
|
|
21,643
|
|
|
5,508
|
|
|
5,059
|
|
|||
Common shares outstanding
|
|
35,906,342
|
|
|
35,670,148
|
|
|
30,289,165
|
|
|||
|
|
|
|
|
|
|
||||||
Equity:
|
|
|
|
|
|
|
||||||
Shareholders' equity
|
|
|
|
|
|
|
||||||
Preferred shares, par value $0.01 per share:
|
|
|
|
|
|
|
||||||
Balance beginning and end of year
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common shares, par value $0.01 per share:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
357
|
|
|
303
|
|
|
236
|
|
|||
Shares issued pursuant to sale of equity
|
|
—
|
|
|
52
|
|
|
65
|
|
|||
Issuance of stock awards, net of forfeitures
|
|
2
|
|
|
2
|
|
|
2
|
|
|||
Balance end of year
|
|
359
|
|
|
357
|
|
|
303
|
|
|||
Additional paid-in capital:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
674,211
|
|
|
387,494
|
|
|
217,707
|
|
|||
Proceeds from sale of equity, net of issuance costs
|
|
—
|
|
|
275,795
|
|
|
164,431
|
|
|||
Exercise of stock options
|
|
—
|
|
|
125
|
|
|
—
|
|
|||
Stock-based compensation expense
|
|
17,851
|
|
|
12,402
|
|
|
8,495
|
|
|||
Issuance of treasury shares
|
|
(4,817
|
)
|
|
(3,270
|
)
|
|
(955
|
)
|
|||
Retirement of treasury shares
|
|
(35
|
)
|
|
(824
|
)
|
|
(491
|
)
|
|||
Tax impact of stock-based compensation
|
|
1,999
|
|
|
2,489
|
|
|
(1,693
|
)
|
|||
Balance end of year
|
|
689,209
|
|
|
674,211
|
|
|
387,494
|
|
|||
Retained earnings:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
293,267
|
|
|
315,568
|
|
|
446,280
|
|
|||
Net income (loss) attributable to shareholders
|
|
155,435
|
|
|
(22,301
|
)
|
|
(130,712
|
)
|
|||
Balance end of year
|
|
448,702
|
|
|
293,267
|
|
|
315,568
|
|
|||
Treasury shares, at cost:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
(241
|
)
|
|
(184
|
)
|
|
(111
|
)
|
|||
Purchase of treasury shares
|
|
(5,392
|
)
|
|
(4,133
|
)
|
|
(1,500
|
)
|
|||
Issuance of treasury shares
|
|
4,817
|
|
|
3,271
|
|
|
955
|
|
|||
Retirement of treasury shares
|
|
35
|
|
|
824
|
|
|
491
|
|
|||
Non-employee directors' deferred compensation plan
|
|
(130
|
)
|
|
(19
|
)
|
|
(19
|
)
|
|||
Balance end of year
|
|
(911
|
)
|
|
(241
|
)
|
|
(184
|
)
|
|||
Total shareholders' equity
|
|
1,137,359
|
|
|
967,594
|
|
|
703,181
|
|
|||
|
|
|
|
|
|
|
Pipelines and related facilities
|
10 - 17 years
|
Transportation and other equipment
|
3 - 20 years
|
Buildings
|
20 - 30 years
|
|
As of December 31,
|
||||||||||||||||||||||
|
2014
|
|
2013
|
||||||||||||||||||||
|
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)
|
||||||||||||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity-based derivative contracts
|
$
|
237,939
|
|
|
$
|
62,356
|
|
|
$
|
300,295
|
|
|
$
|
3,852
|
|
|
$
|
2,098
|
|
|
$
|
5,950
|
|
Basis protection derivative contracts
|
19
|
|
|
—
|
|
|
19
|
|
|
74
|
|
|
—
|
|
|
74
|
|
||||||
Total assets
|
237,958
|
|
|
62,356
|
|
|
300,314
|
|
|
3,926
|
|
|
2,098
|
|
|
6,024
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity-based derivative contracts
|
742
|
|
|
—
|
|
|
742
|
|
|
16,539
|
|
|
987
|
|
|
17,526
|
|
||||||
Basis protection derivative contracts
|
25
|
|
|
—
|
|
|
25
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||||
Total liabilities
|
767
|
|
|
—
|
|
|
767
|
|
|
16,544
|
|
|
987
|
|
|
17,531
|
|
||||||
Net asset (liability)
|
$
|
237,191
|
|
|
$
|
62,356
|
|
|
$
|
299,547
|
|
|
$
|
(12,618
|
)
|
|
$
|
1,111
|
|
|
$
|
(11,507
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Fair value, net asset, beginning of period
|
|
$
|
1,111
|
|
|
$
|
13,610
|
|
|
$
|
22,107
|
|
Changes in fair value included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
62,003
|
|
|
(1,748
|
)
|
|
7,517
|
|
|||
Sales from natural gas marketing
|
|
(22
|
)
|
|
13
|
|
|
63
|
|
|||
Changes in fair value included in balance sheet line item (1):
|
|
|
|
|
|
|
||||||
Accounts payable affiliates
|
|
—
|
|
|
—
|
|
|
(319
|
)
|
|||
Settlements included in statement of operations line items:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
(737
|
)
|
|
(6,361
|
)
|
|
(15,644
|
)
|
|||
Sales from natural gas marketing
|
|
1
|
|
|
(37
|
)
|
|
(114
|
)
|
|||
Loss from discontinued operations, net of tax
|
|
—
|
|
|
(4,366
|
)
|
|
—
|
|
|||
Fair value, net asset end of period
|
|
$
|
62,356
|
|
|
$
|
1,111
|
|
|
$
|
13,610
|
|
|
|
|
|
|
|
|
||||||
Net change in fair value of unsettled derivatives included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
$
|
15,632
|
|
|
$
|
(2,731
|
)
|
|
$
|
3,665
|
|
Sales from natural gas marketing
|
|
3
|
|
|
4
|
|
|
1
|
|
|||
Total
|
|
$
|
15,635
|
|
|
$
|
(2,727
|
)
|
|
$
|
3,666
|
|
|
|
|
|
|
|
|
(1)
|
Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.
|
•
|
For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and
|
•
|
For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.
|
•
|
Collars contain a fixed floor price 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;
|
•
|
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 CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2014, 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; and
|
•
|
Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale.
|
Derivative instruments:
|
|
Balance sheet line item
|
|
2014
|
|
2013
|
|||||
|
|
|
|
|
(in thousands)
|
||||||
Derivative assets:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
$
|
186,886
|
|
|
$
|
1,086
|
|
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
590
|
|
|
361
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
19
|
|
|
74
|
|
||
|
|
|
|
|
187,495
|
|
|
1,521
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
112,599
|
|
|
4,225
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
220
|
|
|
278
|
|
||
|
|
|
|
|
112,819
|
|
|
4,503
|
|
||
Total derivative assets
|
|
|
|
|
$
|
300,314
|
|
|
$
|
6,024
|
|
|
|
|
|
|
|
|
|
||||
Derivative liabilities:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
$
|
—
|
|
|
$
|
14,437
|
|
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
545
|
|
|
247
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
25
|
|
|
—
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
—
|
|
|
5
|
|
||
|
|
|
|
|
570
|
|
|
14,689
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
—
|
|
|
2,609
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
197
|
|
|
233
|
|
||
|
|
|
|
|
197
|
|
|
2,842
|
|
||
Total derivative liabilities
|
|
|
|
|
$
|
767
|
|
|
$
|
17,531
|
|
|
|
Year Ended December 31,
|
||||||||||
Consolidated statement of operations line item
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
|
||||||||||
Commodity price risk management gain (loss), net
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
(837
|
)
|
|
$
|
11,177
|
|
|
$
|
43,591
|
|
Net change in fair value of unsettled derivatives
|
|
311,141
|
|
|
(35,096
|
)
|
|
(14,312
|
)
|
|||
Total commodity price risk management gain (loss), net
|
|
$
|
310,304
|
|
|
$
|
(23,919
|
)
|
|
$
|
29,279
|
|
Sales from natural gas marketing
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
(208
|
)
|
|
$
|
446
|
|
|
$
|
2,170
|
|
Net change in fair value of unsettled derivatives
|
|
364
|
|
|
429
|
|
|
(1,658
|
)
|
|||
Total sales from natural gas marketing
|
|
$
|
156
|
|
|
$
|
875
|
|
|
$
|
512
|
|
Cost of natural gas marketing
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
346
|
|
|
$
|
(257
|
)
|
|
$
|
(2,029
|
)
|
Net change in fair value of unsettled derivatives
|
|
(451
|
)
|
|
(412
|
)
|
|
1,601
|
|
|||
Total cost of natural gas marketing
|
|
$
|
(105
|
)
|
|
$
|
(669
|
)
|
|
$
|
(428
|
)
|
|
|
|
|
|
|
|
As of December 31, 2014
|
|
Derivative instruments, recorded in consolidated balance sheet, gross
|
|
Effect of master netting agreements
|
|
Derivative instruments, net
|
||||||
|
|
(in thousands)
|
||||||||||
Asset derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
300,314
|
|
|
$
|
(29
|
)
|
|
$
|
300,285
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
767
|
|
|
$
|
(29
|
)
|
|
$
|
738
|
|
|
|
|
|
|
|
|
As of December 31, 2013
|
|
Derivative instruments, recorded in consolidated balance sheet, gross
|
|
Effect of master netting agreements
|
|
Derivative instruments, net
|
||||||
|
|
(in thousands)
|
||||||||||
Asset derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
6,024
|
|
|
$
|
(4,637
|
)
|
|
$
|
1,387
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
17,531
|
|
|
$
|
(4,637
|
)
|
|
$
|
12,894
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Crude oil, natural gas and NGLs sales
|
$
|
49,531
|
|
|
$
|
61,197
|
|
Joint interest billings
|
52,841
|
|
|
20,085
|
|
||
Derivative counterparties
|
12,582
|
|
|
1,025
|
|
||
Insurance reimbursement
|
11,212
|
|
|
—
|
|
||
Other
|
5,524
|
|
|
6,700
|
|
||
Allowance for doubtful accounts
|
(486
|
)
|
|
(896
|
)
|
||
Accounts receivable, net
|
$
|
131,204
|
|
|
$
|
88,111
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
Customer
|
|
2014
|
|
2013
|
|
2012
|
|||
|
|
|
|
|
|
|
|||
Suncor Energy Marketing, Inc.
|
|
19.7
|
%
|
|
35.9
|
%
|
|
39.1
|
%
|
Concord Energy
|
|
18.3
|
%
|
|
—
|
%
|
|
—
|
%
|
DCP Midstream, LP
|
|
15.1
|
%
|
|
13.9
|
%
|
|
16.0
|
%
|
Teppco Crude Oil, LLC
|
|
12.9
|
%
|
|
8
|
%
|
|
2.4
|
%
|
|
|
Fair Value of
Derivative Assets |
||
Counterparty Name
|
|
As of December 31, 2014
|
||
|
|
(in thousands)
|
||
|
|
|
||
JP Morgan Chase Bank, N.A (1)
|
|
$
|
95,294
|
|
Canadian Imperial Bank of Commerce (1)
|
|
61,570
|
|
|
NATIXIS (1)
|
|
45,214
|
|
|
Wells Fargo Bank, N.A. (1)
|
|
41,844
|
|
|
Key Bank N.A. (1)
|
|
24,899
|
|
|
Bank of Nova Scotia (1)
|
|
23,760
|
|
|
Other lenders in our revolving credit facility
|
|
7,726
|
|
|
Various (2)
|
|
7
|
|
|
Total
|
|
$
|
300,314
|
|
|
|
|
|
Amount
|
||
|
(in thousands)
|
||
Note Receivable:
|
|
||
Principal outstanding, October 14, 2014
|
$
|
39,048
|
|
Paid-In-Kind interest
|
659
|
|
|
Principal outstanding, December 31, 2014
|
$
|
39,707
|
|
|
As of December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Properties and equipment, net:
|
|
|
|
||||
Crude oil and natural gas properties
|
|
|
|
||||
Proved
|
$
|
2,267,165
|
|
|
$
|
1,677,271
|
|
Unproved
|
188,206
|
|
|
253,464
|
|
||
Total crude oil and natural gas properties
|
2,455,371
|
|
|
1,930,735
|
|
||
Equipment and other
|
29,562
|
|
|
28,832
|
|
||
Land and buildings
|
9,015
|
|
|
9,782
|
|
||
Construction in progress
|
137,937
|
|
|
41,180
|
|
||
Properties and equipment, at cost
|
2,631,885
|
|
|
2,010,529
|
|
||
Accumulated DD&A
|
(831,699
|
)
|
|
(529,543
|
)
|
||
Properties and equipment, net
|
$
|
1,800,186
|
|
|
$
|
1,480,986
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
Continuing operations:
|
|
|
|
|
|
||||||
Impairment of proved properties
|
$
|
112,557
|
|
|
$
|
48,750
|
|
|
$
|
—
|
|
Impairment of unproved properties
|
45,732
|
|
|
517
|
|
|
1,011
|
|
|||
Amortization of individually insignificant unproved properties
|
4,465
|
|
|
3,242
|
|
|
4,009
|
|
|||
Other
|
778
|
|
|
—
|
|
|
—
|
|
|||
Total continuing operations
|
163,532
|
|
|
52,509
|
|
|
5,020
|
|
|||
Discontinued operations:
|
|
|
|
|
|
||||||
Impairment of proved properties
|
—
|
|
|
—
|
|
|
161,185
|
|
|||
Impairment of unproved properties
|
433
|
|
|
566
|
|
|
931
|
|
|||
Amortization of individually insignificant unproved properties
|
—
|
|
|
363
|
|
|
1,013
|
|
|||
Total discontinued operations
|
433
|
|
|
929
|
|
|
163,129
|
|
|||
Total impairment of crude oil and natural gas properties
|
$
|
163,965
|
|
|
$
|
53,438
|
|
|
$
|
168,149
|
|
|
|
|
|
|
|
|
2013
|
||
|
(in thousands)
|
||
|
|
||
Balance beginning of year, January 1,
|
$
|
19,567
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
2,105
|
|
|
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
|
(21,672
|
)
|
|
Capitalized exploratory well costs charged to expense
|
—
|
|
|
Balance end of year, December 31,
|
$
|
—
|
|
|
|
||
Number of wells pending determination at December 31,
|
—
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
(1,514
|
)
|
|
$
|
1,355
|
|
|
$
|
—
|
|
State
|
966
|
|
|
199
|
|
|
(199
|
)
|
|||
Total current income taxes
|
(548
|
)
|
|
1,554
|
|
|
(199
|
)
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
(60,698
|
)
|
|
8,238
|
|
|
10,896
|
|
|||
State
|
(8,721
|
)
|
|
2,060
|
|
|
636
|
|
|||
Total deferred income taxes
|
(69,419
|
)
|
|
10,298
|
|
|
11,532
|
|
|||
Income tax benefit (expense) from continuing operations
|
$
|
(69,967
|
)
|
|
$
|
11,852
|
|
|
$
|
11,333
|
|
|
|
|
|
|
|
|
Year Ended December, 31,
|
|||||||
|
2014
|
|
2013
|
|
2012
|
|||
|
|
|
|
|
|
|||
Statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State income tax, net
|
2.8
|
|
|
4.0
|
|
|
0.9
|
|
Percentage depletion
|
(0.3
|
)
|
|
2.2
|
|
|
2.0
|
|
Non-deductible compensation
|
0.7
|
|
|
(4.2
|
)
|
|
(0.5
|
)
|
Other
|
1.3
|
|
|
(1.0
|
)
|
|
(0.5
|
)
|
Effective tax rate
|
39.5
|
%
|
|
36.0
|
%
|
|
36.9
|
%
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Net change in fair value of unsettled derivatives
|
$
|
—
|
|
|
$
|
6,205
|
|
Deferred compensation
|
10,459
|
|
|
8,507
|
|
||
Asset retirement obligations
|
28,051
|
|
|
11,630
|
|
||
State NOL and tax credit carryforwards, net
|
3,761
|
|
|
5,182
|
|
||
Percentage depletion - carryforward
|
—
|
|
|
4,570
|
|
||
Alternative minimum tax - credit carryforward
|
2,906
|
|
|
3,165
|
|
||
Federal NOL carryforward
|
—
|
|
|
4,601
|
|
||
Settlement of class action litigation
|
12,259
|
|
|
—
|
|
||
Other
|
3,144
|
|
|
6,229
|
|
||
Deferred tax assets
|
60,580
|
|
|
50,089
|
|
||
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Properties and equipment
|
130,155
|
|
|
120,746
|
|
||
Investment in PDCM
|
—
|
|
|
21,962
|
|
||
Net change in fair value of unsettled derivatives
|
113,007
|
|
|
—
|
|
||
Convertible debt
|
2,285
|
|
|
3,774
|
|
||
Total gross deferred tax liabilities
|
245,447
|
|
|
146,482
|
|
||
Net deferred tax liability
|
$
|
184,867
|
|
|
$
|
96,393
|
|
|
|
|
|
||||
Classification in the consolidated balance sheets:
|
|
|
|
||||
Deferred income tax assets
|
$
|
—
|
|
|
$
|
22,374
|
|
Deferred income tax liability - current
|
59,174
|
|
|
—
|
|
||
Deferred income tax liability - non-current
|
125,693
|
|
|
118,767
|
|
||
Net deferred tax liability
|
$
|
184,867
|
|
|
$
|
96,393
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Senior notes:
|
|
|
|
||||
3.25% Convertible senior notes due 2016:
|
|
|
|
||||
Principal amount
|
$
|
115,000
|
|
|
$
|
115,000
|
|
Unamortized discount
|
(6,077
|
)
|
|
(10,010
|
)
|
||
3.25% Convertible senior notes due 2016, net of discount
|
108,923
|
|
|
104,990
|
|
||
7.75% Senior notes due 2022
|
500,000
|
|
|
500,000
|
|
||
Total senior notes
|
608,923
|
|
|
604,990
|
|
||
Revolving credit facility
|
56,000
|
|
|
—
|
|
||
Long-term debt
|
664,923
|
|
|
604,990
|
|
||
|
|
|
|
||||
PDCM credit facility
|
—
|
|
|
37,000
|
|
||
PDCM second lien term loan
|
—
|
|
|
15,000
|
|
||
PDCM long-term debt (included in liabilities held for sale - non-current)
|
—
|
|
|
52,000
|
|
||
|
|
|
|
||||
Total debt
|
$
|
664,923
|
|
|
$
|
656,990
|
|
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Balance at beginning of period, January 1, 2014
|
$
|
41,030
|
|
|
$
|
62,563
|
|
Revisions in estimated cash flows
|
31,945
|
|
|
612
|
|
||
Obligations incurred with development activities
|
1,170
|
|
|
2,389
|
|
||
Accretion expense
|
3,455
|
|
|
4,747
|
|
||
Obligations discharged with divestitures of properties and asset retirements
|
(3,745
|
)
|
|
(29,281
|
)
|
||
Balance end of period, December 31, 2014
|
73,855
|
|
|
41,030
|
|
||
Less: Liabilities held for sale (1)
|
—
|
|
|
(2,234
|
)
|
||
Less: Current portion
|
(1,863
|
)
|
|
(1,158
|
)
|
||
Long-term portion
|
$
|
71,992
|
|
|
$
|
37,638
|
|
|
|
|
|
(1)
|
Represents asset retirement obligations related to assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information.
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||
Area
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019 and
Through Expiration |
|
Total
|
|
Expiration
Date |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Appalachian Basin
|
|
7,117
|
|
|
7,136
|
|
|
7,117
|
|
|
7,117
|
|
|
25,803
|
|
|
54,290
|
|
|
August 31, 2022
|
||||||
Utica Shale
|
|
2,737
|
|
|
2,745
|
|
|
2,737
|
|
|
2,737
|
|
|
12,549
|
|
|
23,505
|
|
|
July 22, 2023
|
||||||
Total
|
|
9,854
|
|
|
9,881
|
|
|
9,854
|
|
|
9,854
|
|
|
38,352
|
|
|
77,795
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Wattenberg Field
|
|
1,818
|
|
|
2,420
|
|
|
2,413
|
|
|
2,413
|
|
|
3,010
|
|
|
12,074
|
|
|
April 30, 2020
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dollar commitment (in thousands)
|
|
$
|
14,481
|
|
|
$
|
17,624
|
|
|
$
|
17,158
|
|
|
$
|
16,327
|
|
|
$
|
30,361
|
|
|
$
|
95,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||||
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Minimum Lease Payments
|
|
$
|
2,517
|
|
|
$
|
2,285
|
|
|
$
|
2,099
|
|
|
$
|
1,908
|
|
|
$
|
1,937
|
|
|
$
|
2,091
|
|
|
$
|
12,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Stock-based compensation expense
|
|
$
|
17,518
|
|
|
$
|
12,880
|
|
|
$
|
8,495
|
|
Income tax benefit
|
|
(5,955
|
)
|
|
(4,697
|
)
|
|
(3,245
|
)
|
|||
Net stock-based compensation expense
|
|
$
|
11,563
|
|
|
$
|
8,183
|
|
|
$
|
5,250
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
|
|
|
|
||||||
Expected term of award
|
6 years
|
|
|
6 years
|
|
|
6 years
|
|
|||
Risk-free interest rate
|
2.1
|
%
|
|
1.0
|
%
|
|
1.1
|
%
|
|||
Expected volatility
|
65.6
|
%
|
|
65.5
|
%
|
|
64.3
|
%
|
|||
Weighted-average grant date fair value per share
|
$
|
29.96
|
|
|
$
|
21.96
|
|
|
$
|
17.61
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||||||||||||||||||||||||||
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Average Remaining Contractual
Term (in years) |
|
Aggregate Intrinsic
Value (in thousands) |
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Aggregate Intrinsic
Value (in thousands) |
|
Number of
SARs |
|
Weighted-Average
Exercise Price |
|
Aggregate Intrinsic
Value (in thousands) |
||||||||||||||||
Outstanding beginning of year, January 1,
|
190,763
|
|
|
$
|
33.77
|
|
|
8.2
|
|
|
$
|
3,711
|
|
|
118,832
|
|
|
$
|
30.80
|
|
|
$
|
486
|
|
|
50,471
|
|
|
$
|
31.61
|
|
|
$
|
341
|
|
Awarded
|
88,248
|
|
|
49.57
|
|
|
—
|
|
|
—
|
|
|
87,078
|
|
|
37.18
|
|
|
—
|
|
|
68,361
|
|
|
30.19
|
|
|
—
|
|
||||||
Exercised
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,147
|
)
|
|
30.06
|
|
|
425
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Outstanding at December 31,
|
279,011
|
|
|
38.77
|
|
|
7.8
|
|
|
1,472
|
|
|
190,763
|
|
|
33.77
|
|
|
3,711
|
|
|
118,832
|
|
|
30.80
|
|
|
486
|
|
||||||
Exercisable at December 31,
|
139,334
|
|
|
36.27
|
|
|
7.3
|
|
|
982
|
|
|
51,922
|
|
|
29.97
|
|
|
1,207
|
|
|
27,458
|
|
|
28.84
|
|
|
187
|
|
|
Shares
|
|
Weighted-Average
Grant-Date Fair Value |
|||
|
|
|
|
|||
Non-vested at December 31, 2013
|
651,781
|
|
|
$
|
36.36
|
|
Granted
|
291,370
|
|
|
56.45
|
|
|
Vested
|
(328,071
|
)
|
|
36.26
|
|
|
Forfeited
|
(50,748
|
)
|
|
45.04
|
|
|
Non-vested at December 31, 2014
|
564,332
|
|
|
46.02
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of time-based awards vested
|
$
|
18,278
|
|
|
$
|
13,640
|
|
|
$
|
5,950
|
|
Total intrinsic value of time-based awards non-vested
|
23,290
|
|
|
34,688
|
|
|
21,470
|
|
|||
Market price per common share as of December 31,
|
41.27
|
|
|
53.22
|
|
|
33.21
|
|
|||
Weighted-average grant date fair value per share
|
56.45
|
|
|
45.53
|
|
|
26.59
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
|
|
|
||||
Expected term of award
|
|
3 years
|
|
|
3 years
|
|
||
Risk-free interest rate
|
|
0.8
|
%
|
|
0.4
|
%
|
||
Expected volatility
|
|
55.2
|
%
|
|
56.6
|
%
|
||
Weighted-average grant date fair value per share
|
|
$
|
56.87
|
|
|
$
|
49.04
|
|
|
|
Shares
|
|
Weighted-Average
Grant-Date Fair Value per Share |
|||
|
|
|
|
|
|||
Non-vested at December 31, 2013
|
|
72,111
|
|
|
$
|
43.75
|
|
Granted
|
|
42,151
|
|
|
56.87
|
|
|
Vested
|
|
(30,541
|
)
|
|
36.54
|
|
|
Non-vested at December 31, 2014
|
|
83,721
|
|
|
52.98
|
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of market-based awards vested
|
$
|
1,260
|
|
|
$
|
724
|
|
|
$
|
—
|
|
Total intrinsic value of market-based awards non-vested
|
3,455
|
|
|
3,838
|
|
|
1,352
|
|
|||
Market price per common share as of December 31,
|
41.27
|
|
|
53.22
|
|
|
33.21
|
|
|||
Weighted-average grant date fair value per share
|
56.87
|
|
|
49.04
|
|
|
36.54
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||||||||||||||||||
|
Number of
Shares Underlying Options |
|
Weighted-Average
Exercise Price Per Share |
|
Weighted- Average
Remaining Contractual Term (in years) |
|
Aggregate Intrinsic
Value (in thousands) |
|
Number of
Shares Underlying Options |
|
Weighted-Average
Exercise Price Per Share |
|
Number of
Shares Underlying Options |
|
Weighted-Average
Exercise Price Per Share |
||||||||||||
Outstanding beginning of year, January 1,
|
3,523
|
|
|
$
|
44.95
|
|
|
2.2
|
|
|
$
|
—
|
|
|
6,973
|
|
|
$
|
41.09
|
|
|
6,973
|
|
|
$
|
41.09
|
|
Exercised
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,450
|
)
|
|
37.15
|
|
|
—
|
|
|
—
|
|
||||
Outstanding end of year, December 31,
|
3,523
|
|
|
44.95
|
|
|
1.2
|
|
|
—
|
|
|
3,523
|
|
|
44.95
|
|
|
6,973
|
|
|
41.09
|
|
||||
Exercisable at December 31,
|
3,523
|
|
|
44.95
|
|
|
1.2
|
|
|
—
|
|
|
3,523
|
|
|
44.95
|
|
|
6,973
|
|
|
41.09
|
|
|
Year Ended December 31,
|
|||||||
|
2014
|
|
2013
|
|
2012
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common shares outstanding - basic
|
35,784
|
|
|
32,426
|
|
|
27,677
|
|
Dilutive effect of:
|
|
|
|
|
|
|||
Restricted stock
|
279
|
|
|
—
|
|
|
—
|
|
Stock options
|
1
|
|
|
—
|
|
|
—
|
|
SARs
|
45
|
|
|
—
|
|
|
—
|
|
Non-employee director deferred compensation
|
5
|
|
|
—
|
|
|
—
|
|
Convertible notes
|
564
|
|
|
—
|
|
|
—
|
|
Weighted-average common shares and equivalents outstanding - diluted
|
36,678
|
|
|
32,426
|
|
|
27,677
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
|
2014
|
|
2013
|
|
2012
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common share equivalents excluded from diluted earnings
|
|
|
|
|
|
|||
per share due to their anti-dilutive effect:
|
|
|
|
|
|
|||
Restricted stock
|
8
|
|
|
823
|
|
|
694
|
|
SARs
|
26
|
|
|
72
|
|
|
116
|
|
Stock options
|
—
|
|
|
7
|
|
|
7
|
|
Non-employee director deferred compensation
|
—
|
|
|
4
|
|
|
3
|
|
Convertible notes
|
—
|
|
|
518
|
|
|
—
|
|
Total anti-dilutive common share equivalents
|
34
|
|
|
1,424
|
|
|
820
|
|
|
|
|
|
|
|
Consolidated balance sheet
|
|
As of December 31, 2014
|
|
As of December 31, 2013
|
||||
|
|
|
|
|||||
Assets
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
—
|
|
|
$
|
601
|
|
Other current assets
|
|
—
|
|
|
7,060
|
|
||
Assets held for sale - current
|
|
—
|
|
|
7,661
|
|
||
|
|
|
|
|
||||
Non-current assets
|
|
|
|
|
||||
Properties and equipment, net
|
|
2,874
|
|
|
175,244
|
|
||
Other assets
|
|
—
|
|
|
6,892
|
|
||
Assets held for sale - non-current
|
|
2,874
|
|
|
182,136
|
|
||
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Liabilities held for sale - current
|
|
—
|
|
|
12,069
|
|
||
|
|
|
|
|
||||
Non-current liabilities
|
|
|
|
|
||||
Long-term debt
|
|
—
|
|
|
52,000
|
|
||
Asset retirement obligation
|
|
—
|
|
|
2,234
|
|
||
Other liabilities
|
|
—
|
|
|
1,681
|
|
||
Liabilities held for sale - non-current
|
|
—
|
|
|
55,915
|
|
||
|
|
|
|
|
||||
Net Assets
|
|
$
|
2,874
|
|
|
$
|
121,813
|
|
|
|
Year Ended December 31,
|
||||||||||
Consolidated statements of operations - discontinued operations
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in thousands)
|
||||||||||
Revenues
|
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
|
$
|
24,149
|
|
|
$
|
39,001
|
|
|
$
|
46,793
|
|
Sales from natural gas marketing
|
|
—
|
|
|
2,825
|
|
|
1,708
|
|
|||
Commodity price risk management gain (loss), net
|
|
(1,085
|
)
|
|
14
|
|
|
3,060
|
|
|||
Well operations, pipeline income and other
|
|
48
|
|
|
922
|
|
|
1,926
|
|
|||
Total revenues
|
|
23,112
|
|
|
42,762
|
|
|
53,487
|
|
|||
|
|
|
|
|
|
|
||||||
Costs, expenses and other
|
|
|
|
|
|
|
||||||
Production costs
|
|
7,120
|
|
|
16,515
|
|
|
27,770
|
|
|||
Cost of natural gas marketing
|
|
—
|
|
|
2,673
|
|
|
1,529
|
|
|||
Impairment of crude oil and natural gas properties
|
|
433
|
|
|
929
|
|
|
163,129
|
|
|||
Depreciation, depletion and amortization
|
|
9,128
|
|
|
13,894
|
|
|
55,768
|
|
|||
Other
|
|
3,445
|
|
|
7,266
|
|
|
8,791
|
|
|||
(Gain) loss on sale of properties and equipment
|
|
(76,479
|
)
|
|
1,700
|
|
|
(24,090
|
)
|
|||
Total costs, expenses and other
|
|
(56,353
|
)
|
|
42,977
|
|
|
232,897
|
|
|||
|
|
|
|
|
|
|
||||||
Interest expense
|
|
(2,222
|
)
|
|
(1,755
|
)
|
|
(782
|
)
|
|||
Interest income
|
|
194
|
|
|
10
|
|
|
1
|
|
|||
Income (loss) from discontinued operations
|
|
77,437
|
|
|
(1,960
|
)
|
|
(180,191
|
)
|
|||
Provision for income taxes
|
|
(29,263
|
)
|
|
770
|
|
|
68,834
|
|
|||
Income (loss) from discontinued operations, net of tax
|
|
$
|
48,174
|
|
|
$
|
(1,190
|
)
|
|
$
|
(111,357
|
)
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
Supplemental cash flows information - discontinued operations
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in thousands)
|
||||||||||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
$
|
(17,253
|
)
|
|
$
|
(45,277
|
)
|
|
$
|
(25,530
|
)
|
|
|
|
|
|
|
|
||||||
Significant non-cash investing items:
|
|
|
|
|
|
|
||||||
Change in accounts payable related to purchases of properties and equipment
|
|
(5,727
|
)
|
|
(4,738
|
)
|
|
(3,592
|
)
|
|||
|
|
|
|
|
|
|
|
Year Ended December 31, 2012
|
||
|
(in thousands)
|
||
|
|
||
Total acquisition cost
|
$
|
304,643
|
|
|
|
||
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
||
Assets acquired:
|
|
||
Crude oil and natural gas properties - proved
|
$
|
180,696
|
|
Crude oil and natural gas properties - unproved
|
151,428
|
|
|
Other assets
|
3,631
|
|
|
Total assets acquired
|
335,755
|
|
|
Liabilities assumed:
|
|
||
Asset retirement obligation
|
14,833
|
|
|
Other accrued expenses
|
9,574
|
|
|
Other liabilities
|
6,705
|
|
|
Total liabilities assumed
|
31,112
|
|
|
Total identifiable net assets acquired
|
$
|
304,643
|
|
|
|
|
Year Ended December 31, 2012
|
||
|
(in thousands, except per share amounts)
|
||
|
|
||
Total revenues
|
$
|
370,488
|
|
Total costs, expenses and other
|
521,178
|
|
|
Net income (loss)
|
$
|
(119,343
|
)
|
|
|
||
Earnings per share:
|
|
||
Basic
|
$
|
(4.31
|
)
|
Diluted
|
$
|
(4.31
|
)
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
Year Ended December 31,
|
|
|
|
|
|
||||||
Segment revenues:
|
|
|
|
|
|
||||||
Oil and gas exploration and production
|
$
|
784,636
|
|
|
$
|
322,878
|
|
|
$
|
261,765
|
|
Gas marketing
|
71,571
|
|
|
69,787
|
|
|
45,371
|
|
|||
Total revenues
|
$
|
856,207
|
|
|
$
|
392,665
|
|
|
$
|
307,136
|
|
|
|
|
|
|
|
||||||
Segment income (loss) before income taxes:
|
|
|
|
|
|
||||||
Oil and gas exploration and production
|
$
|
344,149
|
|
|
$
|
81,913
|
|
|
$
|
101,324
|
|
Gas marketing
|
(445
|
)
|
|
(297
|
)
|
|
348
|
|
|||
Unallocated
|
(166,476
|
)
|
|
(114,579
|
)
|
|
(132,360
|
)
|
|||
Income (loss) before income taxes
|
$
|
177,228
|
|
|
$
|
(32,963
|
)
|
|
$
|
(30,688
|
)
|
|
|
|
|
|
|
||||||
Expenditures for segment long-lived assets:
|
|
|
|
|
|
||||||
Oil and gas exploration and production
|
$
|
623,912
|
|
|
$
|
403,227
|
|
|
$
|
656,443
|
|
Unallocated
|
4,680
|
|
|
1,379
|
|
|
3,509
|
|
|||
Total
|
$
|
628,592
|
|
|
$
|
404,606
|
|
|
$
|
659,952
|
|
|
|
|
|
|
|
||||||
As of December 31,
|
|
|
|
|
|
||||||
Segment assets:
|
|
|
|
|
|
||||||
Oil and gas exploration and production
|
$
|
2,254,751
|
|
|
$
|
1,751,106
|
|
|
|
||
Gas marketing
|
6,979
|
|
|
20,342
|
|
|
|
||||
Unallocated
|
75,984
|
|
|
63,958
|
|
|
|
||||
Assets held for sale
|
2,874
|
|
|
189,797
|
|
|
|
||||
Total assets
|
$
|
2,340,588
|
|
|
$
|
2,025,203
|
|
|
|
||
|
|
|
|
|
|
|
|
Price Used to Estimate Reserves
|
||||||||||
As of December 31,
|
|
Crude Oil
(per Bbl)
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl)
|
||||||
|
|
|
|
|
|
|
||||||
2014
|
|
$
|
84.65
|
|
|
$
|
3.92
|
|
|
$
|
32.27
|
|
2013
|
|
82.18
|
|
|
3.22
|
|
|
29.92
|
|
|||
2012
|
|
87.51
|
|
|
2.35
|
|
|
28.02
|
|
|
Crude Oil, Condensate (MBbls)
|
|
Natural Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Total
(MBoe)
|
||||
Proved Reserves:
|
|
|
|
|
|
|
|
||||
Proved reserves, January 1, 2012 (1)
|
37,636
|
|
|
672,145
|
|
|
19,588
|
|
|
169,248
|
|
Revisions of previous estimates
|
(6,729
|
)
|
|
(289,436
|
)
|
|
(3,671
|
)
|
|
(58,639
|
)
|
Extensions, discoveries and other additions
|
27,482
|
|
|
172,933
|
|
|
11,637
|
|
|
67,941
|
|
Purchases of reserves
|
10,801
|
|
|
87,212
|
|
|
8,084
|
|
|
33,420
|
|
Dispositions
|
(7,854
|
)
|
|
(6,406
|
)
|
|
(1,970
|
)
|
|
(10,891
|
)
|
Production
|
(2,026
|
)
|
|
(32,410
|
)
|
|
(841
|
)
|
|
(8,269
|
)
|
Proved reserves, December 31, 2012 (2)
|
59,310
|
|
|
604,038
|
|
|
32,827
|
|
|
192,810
|
|
Revisions of previous estimates
|
(18,420
|
)
|
|
(117,068
|
)
|
|
(8,549
|
)
|
|
(46,480
|
)
|
Extensions, discoveries and other additions
|
55,759
|
|
|
365,563
|
|
|
25,249
|
|
|
141,935
|
|
Purchases of reserves
|
343
|
|
|
2,894
|
|
|
217
|
|
|
1,043
|
|
Dispositions
|
(252
|
)
|
|
(94,927
|
)
|
|
(30
|
)
|
|
(16,104
|
)
|
Production
|
(2,910
|
)
|
|
(20,860
|
)
|
|
(1,043
|
)
|
|
(7,430
|
)
|
Proved reserves, December 31, 2013 (3)
|
93,830
|
|
|
739,640
|
|
|
48,671
|
|
|
265,774
|
|
Revisions of previous estimates
|
(29,777
|
)
|
|
(149,064
|
)
|
|
(10,204
|
)
|
|
(64,825
|
)
|
Extensions, discoveries and other additions
|
40,792
|
|
|
202,957
|
|
|
23,411
|
|
|
98,029
|
|
Purchases of reserves
|
5
|
|
|
43
|
|
|
5
|
|
|
17
|
|
Dispositions
|
(13
|
)
|
|
(237,306
|
)
|
|
(8
|
)
|
|
(39,572
|
)
|
Production
|
(4,322
|
)
|
|
(19,298
|
)
|
|
(1,756
|
)
|
|
(9,294
|
)
|
Proved reserves, December 31, 2014
|
100,515
|
|
|
536,972
|
|
|
60,119
|
|
|
250,129
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves, as of:
|
|
|
|
|
|
|
|
||||
January 1, 2012 (1)
|
16,910
|
|
|
299,369
|
|
|
11,753
|
|
|
78,558
|
|
December 31, 2012 (2)
|
20,412
|
|
|
281,925
|
|
|
14,353
|
|
|
81,753
|
|
December 31, 2013 (3)
|
23,997
|
|
|
220,387
|
|
|
14,825
|
|
|
75,553
|
|
December 31, 2014
|
26,798
|
|
|
186,633
|
|
|
17,002
|
|
|
74,905
|
|
Proved Undeveloped Reserves, as of:
|
|
|
|
|
|
|
|
||||
January 1, 2012 (1)
|
20,726
|
|
|
372,776
|
|
|
7,835
|
|
|
90,690
|
|
December 31, 2012 (2)
|
38,898
|
|
|
322,113
|
|
|
18,474
|
|
|
111,058
|
|
December 31, 2013 (3)
|
69,833
|
|
|
519,253
|
|
|
33,846
|
|
|
190,221
|
|
December 31, 2014
|
73,717
|
|
|
350,339
|
|
|
43,117
|
|
|
175,224
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included
7,825
MBbls of crude oil,
6,242
MMcf of natural gas and
1,970
MBbls of NGLs, for an aggregate of
10,835
Mboe of crude oil equivalent, related to our Permian assets. Total proved developed reserves related to those assets included
1,815
MBbls,
1,750
MMcf,
550
MBbls and
2,657
MBoe, respectively, and proved undeveloped reserves included
6,010
MBbls,
4,492
MMcf,
1,420
MBbls and
8,179
MBoe, respectively.
|
(2)
|
Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include
148
MBbls of crude oil and
83,656
MMcf of natural gas, for an aggregate of
14,091
MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012.
|
(3)
|
Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Marcellus Shale assets. Total proved reserves included
235,950
MMcf of natural gas, for an aggregate of
39,325
Mboe of crude oil equivalent, related to our Marcellus Shale assets. Total proved developed reserves related to those assets included
53,904
MMcf and
8,984
MBoe, respectively, and proved undeveloped reserves included
182,046
MMcf and
30,341
MBoe, respectively.
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|||
|
(MBoe)
|
|||||||
|
|
|
|
|
|
|||
Beginning proved reserves, January 1, 2012
|
78,558
|
|
|
90,690
|
|
|
169,248
|
|
Undeveloped reserves converted to developed
|
7,655
|
|
|
(7,655
|
)
|
|
—
|
|
Revisions of previous estimates
|
(18,318
|
)
|
|
(40,321
|
)
|
|
(58,639
|
)
|
Extensions, discoveries and other additions
|
11,298
|
|
|
56,643
|
|
|
67,941
|
|
Purchases of reserves
|
13,542
|
|
|
19,878
|
|
|
33,420
|
|
Dispositions
|
(2,713
|
)
|
|
(8,178
|
)
|
|
(10,891
|
)
|
Production
|
(8,269
|
)
|
|
—
|
|
|
(8,269
|
)
|
Ending proved reserves, December 31, 2012
|
81,753
|
|
|
111,057
|
|
|
192,810
|
|
Undeveloped reserves converted to developed
|
3,212
|
|
|
(3,212
|
)
|
|
—
|
|
Revisions of previous estimates
|
(6,751
|
)
|
|
(39,729
|
)
|
|
(46,480
|
)
|
Extensions, discoveries and other additions
|
19,830
|
|
|
122,105
|
|
|
141,935
|
|
Purchases of reserves
|
1,043
|
|
|
—
|
|
|
1,043
|
|
Dispositions
|
(16,104
|
)
|
|
—
|
|
|
(16,104
|
)
|
Production
|
(7,430
|
)
|
|
—
|
|
|
(7,430
|
)
|
Ending proved reserves, December 31, 2013
|
75,553
|
|
|
190,221
|
|
|
265,774
|
|
Undeveloped reserves converted to developed
|
12,730
|
|
|
(12,730
|
)
|
|
—
|
|
Revisions of previous estimates
|
(22,827
|
)
|
|
(41,998
|
)
|
|
(64,825
|
)
|
Extensions, discoveries and other additions
|
27,957
|
|
|
70,072
|
|
|
98,029
|
|
Purchases of reserves
|
17
|
|
|
—
|
|
|
17
|
|
Dispositions
|
(9,231
|
)
|
|
(30,341
|
)
|
|
(39,572
|
)
|
Production
|
(9,294
|
)
|
|
—
|
|
|
(9,294
|
)
|
Ending proved reserves, December 31, 2014
|
74,905
|
|
|
175,224
|
|
|
250,129
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
Revenue:
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
$
|
495,562
|
|
|
$
|
379,796
|
|
|
$
|
274,783
|
|
Commodity price risk management gain, net
|
309,219
|
|
|
(23,905
|
)
|
|
32,339
|
|
|||
|
804,781
|
|
|
355,891
|
|
|
307,122
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Production costs
|
90,744
|
|
|
81,365
|
|
|
77,537
|
|
|||
Exploration expense
|
948
|
|
|
7,071
|
|
|
22,605
|
|
|||
Impairment of proved crude oil and natural gas properties
|
163,965
|
|
|
53,438
|
|
|
162,287
|
|
|||
Depreciation, depletion, and amortization
|
201,656
|
|
|
124,202
|
|
|
146,879
|
|
|||
Accretion of asset retirement obligations
|
3,455
|
|
|
4,747
|
|
|
4,060
|
|
|||
(Gain) loss on sale of properties and equipment
|
(75,972
|
)
|
|
3,722
|
|
|
(24,273
|
)
|
|||
|
384,796
|
|
|
274,545
|
|
|
389,095
|
|
|||
Results of operations for crude oil and natural gas producing
activities before provision for income taxes |
419,985
|
|
|
81,346
|
|
|
(81,973
|
)
|
|||
|
|
|
|
|
|
||||||
Provision for income taxes
|
(163,647
|
)
|
|
(29,400
|
)
|
|
31,163
|
|
|||
|
|
|
|
|
|
||||||
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs
|
$
|
256,338
|
|
|
$
|
51,946
|
|
|
$
|
(50,810
|
)
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
Acquisition of properties: (1)
|
|
|
|
|
|
||||||
Proved properties
|
$
|
11,973
|
|
|
$
|
28,698
|
|
|
$
|
105,303
|
|
Unproved properties
|
45,999
|
|
|
3,390
|
|
|
276,225
|
|
|||
Development costs (2)
|
590,855
|
|
|
332,250
|
|
|
233,144
|
|
|||
Exploration costs: (3)
|
|
|
|
|
|
||||||
Exploratory drilling
|
—
|
|
|
58,988
|
|
|
18,803
|
|
|||
Geological and geophysical
|
1
|
|
|
752
|
|
|
1,925
|
|
|||
Total costs incurred
|
$
|
648,828
|
|
|
$
|
424,078
|
|
|
$
|
635,400
|
|
|
|
|
|
|
|
(1)
|
Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.
|
(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, 2014
,
2013
and
2012
,
$125.2 million
,
$40.1 million
and
$62.0 million
, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.
|
(3)
|
Exploration costs - represents 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.
|
|
As of December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Proved crude oil and natural gas properties
|
$
|
2,267,165
|
|
|
$
|
1,677,271
|
|
Unproved crude oil and natural gas properties
|
188,206
|
|
|
253,463
|
|
||
Uncompleted wells, equipment and facilities
|
137,134
|
|
|
40,745
|
|
||
Capitalized costs
|
2,592,505
|
|
|
1,971,479
|
|
||
Less accumulated DD&A
|
(808,431
|
)
|
|
(507,510
|
)
|
||
Capitalized costs, net
|
$
|
1,784,074
|
|
|
$
|
1,463,969
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Future estimated cash flows
|
$
|
12,550,515
|
|
|
$
|
11,550,917
|
|
|
$
|
7,529,292
|
|
Future estimated production costs
|
(2,816,776
|
)
|
|
(2,329,836
|
)
|
|
(1,690,453
|
)
|
|||
Future estimated development costs
|
(2,458,790
|
)
|
|
(2,778,148
|
)
|
|
(1,852,177
|
)
|
|||
Future estimated income tax expense
|
(2,336,510
|
)
|
|
(2,119,615
|
)
|
|
(1,230,294
|
)
|
|||
Future net cash flows
|
4,938,439
|
|
|
4,323,318
|
|
|
2,756,368
|
|
|||
10% annual discount for estimated timing of cash flows
|
(2,631,974
|
)
|
|
(2,541,155
|
)
|
|
(1,587,871
|
)
|
|||
Standardized measure of discounted future estimated net cash flows
|
$
|
2,306,465
|
|
|
$
|
1,782,163
|
|
|
$
|
1,168,497
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Sales of crude oil, natural gas and NGLs production, net of production costs
|
$
|
(387,789
|
)
|
|
$
|
(286,021
|
)
|
|
$
|
(194,346
|
)
|
Net changes in prices and production costs (1)
|
129,213
|
|
|
89,527
|
|
|
95,501
|
|
|||
Extensions, discoveries, and improved recovery, less related costs (2)
|
1,444,581
|
|
|
1,529,006
|
|
|
632,781
|
|
|||
Sales of reserves (3)
|
(402,595
|
)
|
|
(142,724
|
)
|
|
(86,902
|
)
|
|||
Purchases of reserves (4)
|
238
|
|
|
10,610
|
|
|
296,208
|
|
|||
Development costs incurred during the period
|
161,404
|
|
|
46,366
|
|
|
69,198
|
|
|||
Revisions of previous quantity estimates (5)
|
(654,318
|
)
|
|
(397,738
|
)
|
|
(452,775
|
)
|
|||
Changes in estimated income taxes (6)
|
(221,874
|
)
|
|
(381,369
|
)
|
|
(131,256
|
)
|
|||
Net changes in future development costs
|
46,499
|
|
|
(40,707
|
)
|
|
(3,979
|
)
|
|||
Accretion of discount
|
270,389
|
|
|
142,040
|
|
|
124,105
|
|
|||
Timing and other
|
138,554
|
|
|
44,676
|
|
|
(121,247
|
)
|
|||
Total
|
$
|
524,302
|
|
|
$
|
613,666
|
|
|
$
|
227,288
|
|
|
|
|
|
|
|
(1)
|
Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to
$37.78
as compared to
$30.82
in our 2013 reserve report. This is due to the divestiture of our Marcellus Shale reserves during 2014 which further increased our liquids as a percentage of proved reserves. Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to
$30.82
from
$30.28
in our 2012 report due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which increased our liquids as a percentage of proved reserves.
|
(2)
|
The
6%
decrease in 2014 as compared to 2013 is primarily due to a scheduled maximum rig count of six rigs by 2016 as compared to a scheduled maximum rig count of seven in the 2013 year-end reserve report, partially offset by our increased PUD count in the Wattenberg Field resulting from successful downspacing tests in 2014. The
142%
increase in 2013 as compared to 2012 is primarily due to the addition of PUDs in the Utica Shale and our continued focus on our Wattenberg Field drilling program. Our increased PUD count in the Wattenberg Field is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report.
|
(3)
|
The increase in sales of reserves in 2014 as compared to 2013 was due to the divestiture of our Marcellus shale assets in October 2014. The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013.
|
(4)
|
The decrease in purchases of reserves in 2014 and 2013 as compared to the respective prior years was due to no material acquisitions having occurred.
|
(5)
|
The change in revisions of our previous quantity estimates in 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule.
|
(6)
|
The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately
38%
,
38%
and
38.2%
for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital.
|
|
2014
|
||||||||||||||||||
|
Quarter Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Year Ended
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, natural gas and NGLs sales
|
$
|
120,013
|
|
|
$
|
131,017
|
|
|
$
|
120,526
|
|
|
$
|
99,857
|
|
|
$
|
471,413
|
|
Sales from natural gas marketing
|
26,937
|
|
|
22,415
|
|
|
13,297
|
|
|
8,922
|
|
|
71,571
|
|
|||||
Commodity price risk management gain (loss), net
|
(24,909
|
)
|
|
(52,643
|
)
|
|
90,213
|
|
|
297,643
|
|
|
310,304
|
|
|||||
Well operations, pipeline income and other
|
616
|
|
|
514
|
|
|
520
|
|
|
1,269
|
|
|
2,919
|
|
|||||
Total revenues
|
122,657
|
|
|
101,303
|
|
|
224,556
|
|
|
407,691
|
|
|
856,207
|
|
|||||
Costs, expenses and other:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production costs
|
18,083
|
|
|
23,774
|
|
|
22,754
|
|
|
19,013
|
|
|
83,624
|
|
|||||
Cost of natural gas marketing
|
26,870
|
|
|
22,428
|
|
|
13,347
|
|
|
9,370
|
|
|
72,015
|
|
|||||
Exploration expense
|
307
|
|
|
276
|
|
|
190
|
|
|
174
|
|
|
947
|
|
|||||
Impairment of crude oil and natural gas properties
|
910
|
|
|
848
|
|
|
1,863
|
|
|
159,911
|
|
|
163,532
|
|
|||||
General and administrative expense
|
22,484
|
|
|
39,440
|
|
|
34,625
|
|
|
19,310
|
|
|
115,859
|
|
|||||
Depreciation, depletion and amortization
|
42,889
|
|
|
49,636
|
|
|
49,640
|
|
|
50,363
|
|
|
192,528
|
|
|||||
Accretion of asset retirement obligations
|
841
|
|
|
840
|
|
|
861
|
|
|
873
|
|
|
3,415
|
|
|||||
(Gain) loss on sale of properties and equipment
|
579
|
|
|
(23
|
)
|
|
21
|
|
|
(70
|
)
|
|
507
|
|
|||||
Total costs, expenses and other
|
112,963
|
|
|
137,219
|
|
|
123,301
|
|
|
258,944
|
|
|
632,427
|
|
|||||
Income (loss) from operations
|
9,694
|
|
|
(35,916
|
)
|
|
101,255
|
|
|
148,747
|
|
|
223,780
|
|
|||||
Interest expense
|
(12,183
|
)
|
|
(12,195
|
)
|
|
(11,821
|
)
|
|
(11,643
|
)
|
|
(47,842
|
)
|
|||||
Interest income
|
187
|
|
|
83
|
|
|
39
|
|
|
981
|
|
|
1,290
|
|
|||||
Income (loss) from continuing operations before income taxes
|
(2,302
|
)
|
|
(48,028
|
)
|
|
89,473
|
|
|
138,085
|
|
|
177,228
|
|
|||||
Provision for income taxes
|
894
|
|
|
18,650
|
|
|
(35,396
|
)
|
|
(54,115
|
)
|
|
(69,967
|
)
|
|||||
Income (loss) from continuing operations
|
(1,408
|
)
|
|
(29,378
|
)
|
|
54,077
|
|
|
83,970
|
|
|
107,261
|
|
|||||
Income (loss) from discontinued operations, net of tax
|
(719
|
)
|
|
1,191
|
|
|
(80
|
)
|
|
47,782
|
|
|
48,174
|
|
|||||
Net income (loss)
|
$
|
(2,127
|
)
|
|
$
|
(28,187
|
)
|
|
$
|
53,997
|
|
|
$
|
131,752
|
|
|
$
|
155,435
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(0.04
|
)
|
|
$
|
(0.82
|
)
|
|
$
|
1.51
|
|
|
$
|
2.34
|
|
|
$
|
3.00
|
|
Income (loss) from discontinued operations
|
(0.02
|
)
|
|
0.03
|
|
|
—
|
|
|
1.33
|
|
|
1.34
|
|
|||||
Net income (loss)
|
$
|
(0.06
|
)
|
|
$
|
(0.79
|
)
|
|
$
|
1.51
|
|
|
$
|
3.67
|
|
|
$
|
4.34
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(0.04
|
)
|
|
$
|
(0.82
|
)
|
|
$
|
1.47
|
|
|
$
|
2.32
|
|
|
$
|
2.93
|
|
Income (loss) from discontinued operations
|
(0.02
|
)
|
|
0.03
|
|
|
—
|
|
|
1.32
|
|
|
1.31
|
|
|||||
Net income (loss)
|
$
|
(0.06
|
)
|
|
$
|
(0.79
|
)
|
|
$
|
1.47
|
|
|
$
|
3.64
|
|
|
$
|
4.24
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
35,690
|
|
|
35,762
|
|
|
35,834
|
|
|
35,847
|
|
|
35,784
|
|
|||||
Diluted
|
35,690
|
|
|
35,762
|
|
|
36,828
|
|
|
36,146
|
|
|
36,678
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
2013
|
||||||||||||||||||
|
Quarter Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Year Ended
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, natural gas and NGLs sales
|
$
|
75,950
|
|
|
$
|
73,695
|
|
|
$
|
77,340
|
|
|
$
|
113,810
|
|
|
$
|
340,795
|
|
Sales from natural gas marketing
|
13,670
|
|
|
18,079
|
|
|
16,946
|
|
|
21,092
|
|
|
69,787
|
|
|||||
Commodity price risk management gain (loss), net
|
(19,765
|
)
|
|
21,828
|
|
|
(24,138
|
)
|
|
(1,844
|
)
|
|
(23,919
|
)
|
|||||
Well operations, pipeline income and other
|
1,060
|
|
|
954
|
|
|
1,667
|
|
|
2,321
|
|
|
6,002
|
|
|||||
Total revenues
|
70,915
|
|
|
114,556
|
|
|
71,815
|
|
|
135,379
|
|
|
392,665
|
|
|||||
Costs, expenses and other:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production costs
|
14,381
|
|
|
14,274
|
|
|
17,036
|
|
|
19,159
|
|
|
64,850
|
|
|||||
Cost of natural gas marketing
|
13,736
|
|
|
18,065
|
|
|
17,127
|
|
|
21,156
|
|
|
70,084
|
|
|||||
Exploration expense
|
1,540
|
|
|
1,266
|
|
|
1,841
|
|
|
1,687
|
|
|
6,334
|
|
|||||
Impairment of crude oil and natural gas properties
|
46,260
|
|
|
1,298
|
|
|
4,236
|
|
|
715
|
|
|
52,509
|
|
|||||
General and administrative expense
|
14,037
|
|
|
14,849
|
|
|
15,052
|
|
|
16,018
|
|
|
59,956
|
|
|||||
Depreciation, depletion and amortization
|
25,431
|
|
|
25,488
|
|
|
26,957
|
|
|
37,748
|
|
|
115,624
|
|
|||||
Accretion of asset retirement obligations
|
1,143
|
|
|
1,167
|
|
|
1,181
|
|
|
1,075
|
|
|
4,566
|
|
|||||
(Gain) loss on sale of properties and equipment
|
(30
|
)
|
|
(1
|
)
|
|
(100
|
)
|
|
2,153
|
|
|
2,022
|
|
|||||
Total costs, expenses and other
|
116,498
|
|
|
76,406
|
|
|
83,330
|
|
|
99,711
|
|
|
375,945
|
|
|||||
Income (loss) from operations
|
(45,583
|
)
|
|
38,150
|
|
|
(11,515
|
)
|
|
35,668
|
|
|
16,720
|
|
|||||
Interest expense
|
(13,088
|
)
|
|
(12,838
|
)
|
|
(11,957
|
)
|
|
(12,260
|
)
|
|
(50,143
|
)
|
|||||
Interest income
|
—
|
|
|
3
|
|
|
130
|
|
|
327
|
|
|
460
|
|
|||||
Income (loss) from continuing operations before income taxes
|
(58,671
|
)
|
|
25,315
|
|
|
(23,342
|
)
|
|
23,735
|
|
|
(32,963
|
)
|
|||||
Provision for income taxes
|
20,798
|
|
|
(9,444
|
)
|
|
9,435
|
|
|
(8,937
|
)
|
|
11,852
|
|
|||||
Income (loss) from continuing operations
|
(37,873
|
)
|
|
15,871
|
|
|
(13,907
|
)
|
|
14,798
|
|
|
(21,111
|
)
|
|||||
Income (loss) from discontinued operations, net of tax
|
(1,545
|
)
|
|
4,047
|
|
|
(2,093
|
)
|
|
(1,599
|
)
|
|
(1,190
|
)
|
|||||
Net income (loss)
|
$
|
(39,418
|
)
|
|
$
|
19,918
|
|
|
$
|
(16,000
|
)
|
|
$
|
13,199
|
|
|
$
|
(22,301
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(1.25
|
)
|
|
$
|
0.53
|
|
|
$
|
(0.42
|
)
|
|
$
|
0.42
|
|
|
$
|
(0.65
|
)
|
Income (loss) from discontinued operations
|
(0.05
|
)
|
|
0.13
|
|
|
(0.06
|
)
|
|
(0.04
|
)
|
|
(0.04
|
)
|
|||||
Net income (loss) attributable to shareholders
|
$
|
(1.30
|
)
|
|
$
|
0.66
|
|
|
$
|
(0.48
|
)
|
|
$
|
0.38
|
|
|
$
|
(0.69
|
)
|
Diluted
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(1.25
|
)
|
|
$
|
0.51
|
|
|
$
|
(0.42
|
)
|
|
$
|
0.40
|
|
|
$
|
(0.65
|
)
|
Income (loss) from discontinued operations
|
(0.05
|
)
|
|
0.13
|
|
|
(0.06
|
)
|
|
(0.04
|
)
|
|
(0.04
|
)
|
|||||
Net income (loss) attributable to shareholders
|
$
|
(1.30
|
)
|
|
$
|
0.64
|
|
|
$
|
(0.48
|
)
|
|
$
|
0.36
|
|
|
$
|
(0.69
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
30,270
|
|
|
30,332
|
|
|
33,413
|
|
|
35,620
|
|
|
32,426
|
|
|||||
Diluted
|
30,270
|
|
|
31,014
|
|
|
33,413
|
|
|
36,836
|
|
|
32,426
|
|
|||||
|
|
|
|
|
|
|
|
|
|
Description
|
|
Beginning
Balance January 1 |
|
Charged to
Costs and Expenses |
|
Deductions (1)
|
|
Ending
Balance December 31 |
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
2014:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
$
|
896
|
|
|
$
|
78
|
|
|
$
|
488
|
|
|
$
|
486
|
|
Valuation allowance for unproved crude oil and natural gas properties
|
|
5,142
|
|
|
4,465
|
|
|
314
|
|
|
9,293
|
|
||||
2013:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
718
|
|
|
322
|
|
|
144
|
|
|
896
|
|
||||
Valuation allowance for unproved crude oil and natural gas properties
|
|
5,690
|
|
|
3,038
|
|
|
3,586
|
|
|
5,142
|
|
||||
2012:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
644
|
|
|
222
|
|
|
148
|
|
|
718
|
|
||||
Valuation allowance for unproved crude oil and natural gas properties
|
|
10,711
|
|
|
3,332
|
|
|
8,353
|
|
|
5,690
|
|
(1)
|
For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.1
|
|
Fourth Amended and Restated Articles of Incorporation of PDC Energy, Inc. (the "Company")
|
|
8-K
|
|
000-07246
|
|
3.1
|
|
6/10/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
By-laws of the Company.
|
|
10-Q
|
|
000-07246
|
|
3.2
|
|
8/2/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.1
|
|
Rights Agreement by and between the Company and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
9/17/2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.2
|
|
Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon, including the form of 3.25% Convertible Senior Note due 2016.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
11/24/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
10/3/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1*
|
|
Form of Indemnification Agreement with Non-Employee Directors.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
6/13/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.2*
|
|
The Company 401(k) and Profit Sharing Plan, as amended on January 1, 2015.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.3*
|
|
Amended and Restated Non-Employee Director Deferred Compensation Plan.
|
|
10-K
|
|
000-07246
|
|
10.3
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4*
|
|
2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan").
|
|
10-K
|
|
000-07246
|
|
10.26
|
|
2/27/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4.1*
|
|
Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan.
|
|
8-K
|
|
000-07246
|
|
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5*
|
|
Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.2
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.1*
|
|
Form of 2012 Performance Share Agreement.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
1/20/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.2*
|
|
Form of 2013 Performance Share Agreement.
|
|
10-K
|
|
000-07246
|
|
10.9
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.3*
|
|
Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.10
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.4*
|
|
Form of 2014 Performance Share Agreement
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.5*
|
|
Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.6*
|
|
Form of 2015 Performance Share Agreement
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.7*
|
|
Form of 2015 Restricted Stock Unit Agreement
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.8*
|
|
Form of 2015 Stock Appreciation Rights Agreement
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.6*
|
|
Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.2
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7*
|
|
Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.3
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.8*
|
|
Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.4
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.9*
|
|
Employment Agreement with Barton R. Brookman, Jr., dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.5
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.10
|
|
Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009.
|
|
8-K
|
|
000-07246
|
|
2.1
|
|
11/4/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11
|
|
Second Amended and Restated Limited Liability Company Agreement of PDC Mountaineer, LLC, dated December 23, 2013.
|
|
10-K
|
|
000-07246
|
|
10.12
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PDC ENERGY, INC.
|
|
|
|
By: /s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief Executive Officer
|
|
|
|
February 19, 2015
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Barton R. Brookman
|
|
President, Chief Executive Officer and Director
|
|
February 19, 2015
|
Barton R. Brookman
|
|
(principal executive officer)
|
|
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
Chief Financial Officer
|
|
February 19, 2015
|
Gysle R. Shellum
|
|
(principal financial officer)
|
|
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
Chief Accounting Officer
|
|
February 19, 2015
|
R. Scott Meyers
|
|
(principal accounting officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey C. Swoveland
|
|
Chairman and Director
|
|
February 19, 2015
|
Jeffrey C. Swoveland
|
|
|
|
|
|
|
|
|
|
/s/ Joseph E. Casabona
|
|
Director
|
|
February 19, 2015
|
Joseph E. Casabona
|
|
|
|
|
|
|
|
|
|
/s/ Anthony J. Crisafio
|
|
Director
|
|
February 19, 2015
|
Anthony J. Crisafio
|
|
|
|
|
|
|
|
|
|
/s/ Larry F. Mazza
|
|
Director
|
|
February 19, 2015
|
Larry F. Mazza
|
|
|
|
|
|
|
|
|
|
/s/ David C. Parke
|
|
Director
|
|
February 19, 2015
|
David C. Parke
|
|
|
|
|
|
|
|
|
|
/s/ James M. Trimble
|
|
Director
|
|
February 19, 2015
|
James M. Trimble
|
|
|
|
|
|
|
|
|
|
/s/ Kimberly Luff Wakim
|
|
Director
|
|
February 19, 2015
|
Kimberly Luff Wakim
|
|
|
|
|
I.
|
Basic Plan Information...................................................................................................................................
2
|
A.
|
Account...................................................................................................................................................... 2
|
B.
|
Beneficiary................................................................................................................................................. 2
|
C.
|
Deferral Contribution................................................................................................................................. 2
|
D.
|
Employee................................................................................................................................................... 2
|
E.
|
Employer.................................................................................................................................................... 2
|
F.
|
ERISA........................................................................................................................................................ 2
|
G.
|
Highly Compensated Employee................................................................................................................. 2
|
H.
|
Non-Highly Compensated Employee......................................................................................................... 3
|
I.
|
Participant................................................................................................................................................... 3
|
J.
|
Plan Type.................................................................................................................................................... 3
|
K.
|
Plan Administrator...................................................................................................................................... 3
|
L.
|
Plan Number............................................................................................................................................... 3
|
M.
|
Plan Sponsor............................................................................................................................................... 3
|
N.
|
Plan Year..................................................................................................................................................... 3
|
O.
|
Service of Process...................................................................................................................................... 3
|
P.
|
Trustee........................................................................................................................................................ 3
|
Q.
|
Qualified Military Service.......................................................................................................................... 3
|
II.
|
Participation.....................................................................................................................................................
4
|
A.
|
Eligibility Requirements............................................................................................................................. 4
|
III.
|
Contributions...................................................................................................................................................
4
|
A.
|
Compensation............................................................................................................................................. 4
|
B.
|
Employee Deferral Contributions.............................................................................................................. 5
|
1.
|
Regular Deferral Contributions..........................................................................................................
5
|
2.
|
Additional Deferrals............................................................................................................................
5
|
3.
|
Age 50 and Over Catch-Up Contributions..........................................................................................
6
|
C.
|
Employer Matching Contributions............................................................................................................. 6
|
1.
|
Discretionary Matching Contributions...............................................................................................
6
|
D.
|
Nonelective Contributions.......................................................................................................................... 6
|
1.
|
Discretionary Nonelective Contributions............................................................................................
6
|
E.
|
Qualified Nonelective Contributions.......................................................................................................... 6
|
F.
|
Limit on Contributions............................................................................................................................... 6
|
G.
|
Rollover Contributions............................................................................................................................... 6
|
IV.
|
Investments......................................................................................................................................................
7
|
A.
|
Investments................................................................................................................................................ 7
|
B.
|
Fidelity
®
Portfolio Advisory Service at Work............................................................................................ 8
|
C.
|
Statement of Account................................................................................................................................. 8
|
D.
|
Election....................................................................................................................................................... 8
|
V.
|
Vesting...............................................................................................................................................................
8
|
A.
|
Forfeiture and Re-employment................................................................................................................... 10
|
VI.
|
Participant Loans............................................................................................................................................
11
|
A.
|
General Loan Rules.................................................................................................................................... 11
|
B.
|
Specific Loan Procedures........................................................................................................................... 11
|
1.
|
Loan Application.................................................................................................................................
11
|
2.
|
Loan Amount.......................................................................................................................................
11
|
3.
|
Number of Loans.................................................................................................................................
11
|
4.
|
Interest Rate........................................................................................................................................
11
|
5.
|
Loan Repayments and Loan Maturity.................................................................................................
11
|
6.
|
Default or Termination of Employment...............................................................................................
11
|
VII.
|
In Service Withdrawals...................................................................................................................................
12
|
A.
|
Hardship Withdrawals................................................................................................................................ 12
|
B.
|
Withdrawals After Age 59½...................................................................................................................... 12
|
C.
|
Withdrawals After Age 70½...................................................................................................................... 12
|
D.
|
Withdrawals After Normal Retirement Age.............................................................................................. 12
|
E.
|
Withdrawals of Rollover Contributions.................................................................................................... 12
|
F.
|
Roth In-Plan Conversion........................................................................................................................... 13
|
G.
|
Withdrawal for Participants Performing Qualified Military Service........................................................ 13
|
VIII.
|
Distribution of Benefits..................................................................................................................................
13
|
A.
|
Eligibility For Benefits.............................................................................................................................. 13
|
B.
|
Distributable Events.................................................................................................................................. 13
|
1.
|
Death..................................................................................................................................................
14
|
2.
|
Disability............................................................................................................................................
14
|
3.
|
Retirement..........................................................................................................................................
14
|
4.
|
Minimum Required Distributions.......................................................................................................
14
|
5.
|
Termination of Employment...............................................................................................................
14
|
C.
|
Form of Payments..................................................................................................................................... 14
|
1.
|
Lump Sum Distributions....................................................................................................................
14
|
a)
|
Non-rollover Distribution...........................................................................................................................
14
|
b)
|
Direct Rollover Distribution.......................................................................................................................
15
|
c)
|
Combination Non-rollover Distribution and Direct Rollover Distribution................................................
15
|
2.
|
Installment Distributions...................................................................................................................
16
|
3.
|
Other Non-Annuity.............................................................................................................................
16
|
IX.
|
Miscellaneous Information............................................................................................................................
16
|
A.
|
Benefits Not Insured................................................................................................................................. 16
|
B.
|
Attachment of Your Account.................................................................................................
...
................. 16
|
C.
|
Plan-to-Plan Transfer Of Assets................................................................................................................ 16
|
D.
|
Plan Amendment....................................................................................................................................... 16
|
E.
|
Plan Termination....................................................................................................................................... 17
|
F.
|
Interpretation of Plan................................................................................................................................. 17
|
G.
|
Electronic Delivery.................................................................................................................................... 17
|
X.
|
Internal Revenue Code Tests.........................................................................................................................
17
|
A.
|
Non-Discrimination Tests.......................................................................................................................... 17
|
B.
|
Top Heavy Test.......................................................................................................................................... 17
|
XI.
|
Participant Rights...........................................................................................................................................
18
|
A.
|
Claims........................................................................................................................................................ 18
|
1.
|
Claims Procedures..............................................................................................................................
18
|
2.
|
Review Procedures (For Appeal of an Adverse Benefit Determination)............................................
18
|
B.
|
Statement of ERISA Rights........................................................................................................................ 19
|
XII.
|
Services and Fees.............................................................................................................................................
20
|
Appendix A.
|
Investment Options.........................................................................................................................................
21
|
Summary Plan Description
The PDC Energy, Inc. 401(k) & Profit Sharing Plan
|
The PDC Energy, Inc. 401(k) & Profit Sharing Plan
|
I. Basic Plan Information
|
A.
|
Account
|
B.
|
Beneficiary
|
C.
|
Deferral Contribution
|
D.
|
Employee
|
E.
|
Employer
|
Federal Tax
Identification Number
|
Participating Employer Name
|
Designation
|
27-1195623
|
PDC Mountaineer LLC
|
Unrelated
|
F.
|
ERISA
|
G.
|
Highly Compensated Employee
|
H.
|
Non-Highly Compensated Employee
|
I.
|
Participant
|
J.
|
Plan Type
|
K.
|
Plan Administrator
|
L.
|
Plan Number
|
M.
|
Plan Sponsor
|
N.
|
Plan Year
|
O.
|
Service of Process
|
P.
|
Trustee
|
Q.
|
Qualified Military Service
|
II. Participation
|
A.
|
Eligibility Requirements
|
•
|
a resident of Puerto Rico
|
•
|
covered by a collective bargaining agreement for which retirement benefits have been the subject of good faith negotiations
|
•
|
a Leased Employee.
|
Contribution type
|
Age Requirement
|
Service Requirement
|
Entry Date
|
All Sources
|
18
|
1 month(s)
|
First day of each month
|
•
|
Employees that were a part of the acquisition of Seneca-Upshur Petroleum LLC on 10/04/2011
|
•
|
Employees that were a part of the acquisition of Merit Energy Company on 06/30/2012
|
III. Contributions
|
A.
|
Compensation
|
B.
|
Employee Deferral Contributions
|
D.
|
Nonelective Contributions
|
E.
|
Qualified Nonelective Contributions
|
F.
|
Limit on Contributions
|
G.
|
Rollover Contributions
|
IV. Investments
|
A.
|
Investments
|
•
|
A description of the annual operating expenses of each investment fund (e.g., investment management fees, administrative fees, transaction costs) which reduce the rate of return to you, and the aggregate amount of such expenses expressed as a percentage of average net assets of the designated investment alternative;
|
•
|
Prospectuses, financial statements and reports, plus any other material provided to the Plan which relates to the available investment alternatives;
|
•
|
A list of the assets comprising the portfolio of each investment fund that constitute plan assets within the meaning of 29 CFR 2510.3-101, the value of each such asset (or the proportion of the investment fund which it comprises), and with respect to each such asset which is a fixed rate investment contract issued by a bank, savings and loan association or insurance company, the name of the issuer of the contract, the term of the contract and the rate of return on the contract;
|
•
|
Information concerning the value of shares or units of the investment funds available to you under the Plan, as well as the past investment performance of such funds, determined net of expenses, on a reasonable and consistent basis; and
|
•
|
Information concerning the value of shares or units in the investment funds held in your Plan account.
|
B.
|
Fidelity
®
Portfolio Advisory Service at Work
|
C.
|
Statement of Account
|
D.
|
Election
|
V. Vesting
|
•
|
Employees that were a part of the acquisition of Seneca-Upshur Petroleum LLC on 10/04/2011
|
•
|
Employees that were a part of the acquisition of Merit Energy Company on 06/30/2012
|
Years of Service
|
Vesting Percentage
|
less than 1
|
100
|
1
|
100
|
Applicable Year(s)
|
Method
|
Measurement Period
|
Plan Year(s) before 2006
|
General
|
Jan. 1 to Dec. 31
|
2,006
|
General or Elapsed Time*
|
Jan. 1 to Dec. 31
|
Plan Year(s) after 2006
|
Elapsed Time
|
Jan. 1 to Dec. 31
|
*
|
You will receive vesting credit for this period if you would get such credit under either the general method (hours of service) or the elapsed time method.
|
A.
|
Forfeiture and Re-employment
|
Source
|
Amount
|
Vested Percentage
|
Vested Amount
|
Employee
|
$2,000
|
100%†
|
$2,000
|
Employer
|
$1,000
|
80%
|
800
|
Total
|
$3,000
|
|
$2,800
|
(1)
|
You are re-employed by your Employer before you incur five consecutive one-year breaks in service, and
|
(2)
|
If you received distribution of your vested Account and you repay the full amount of the distribution before the end of the five-year period that begins on the date you are re-employed.
|
VI. Participant Loans
|
A.
|
General Loan Rules
|
B.
|
Specific Loan Procedures
|
VII. In Service Withdrawals
|
A.
|
Hardship Withdrawals
|
•
|
Employee Deferral Contributions (including both pretax and Roth deferral contributions if available in the Participant’s Account)
|
•
|
Match
|
B.
|
Withdrawals After Age 59½
|
C.
|
Withdrawals After Age 70½
|
D.
|
Withdrawals After Normal Retirement Age
|
E.
|
Withdrawals of Rollover Contributions
|
F.
|
Roth In-Plan Conversion
|
G.
|
Withdrawal for Participants Performing Qualified Military Service
|
VIII. Distribution of Benefits
|
A.
|
Eligibility For Benefits
|
B.
|
Distributable Events
|
C.
|
Form of Payments
|
1.
|
Rollover to Fidelity IRA
- You will be asked whether you have received a Fidelity Service for Exiting Employees (‘SEE’) Rollover IRA Kit. If you haven’t received a SEE Kit, the Fidelity representative will send out one. Then, your rollover request will be entered on the system and will pend (for up to 90 days) until the Rollover IRA account is set up. You
must
return the signed Rollover IRA application to Fidelity’s Retail Customer Service Department (in Dallas, TX) in order to set up the Rollover IRA account. Once the Rollover IRA account has been set up, your vested Account balance will be transferred to the Fidelity Rollover IRA.
|
2.
|
Rollover to Non-Fidelity IRA
- A check will be issued by the Trustee payable to the IRA custodian or trustee for your benefit. The check will contain the notation ‘Direct Rollover’ and it will be mailed directly to you. You will be responsible for forwarding it on to the custodian or trustee. You must provide the Plan Administrator with complete information to facilitate your direct rollover distribution.
|
3.
|
Rollover to your New Employer’s Qualified Plan
- You should check with your new employer to determine if its plan will accept rollover contributions. If allowed, then a check will be issued by the Trustee payable to the trustee of your new employer’s qualified plan. The check will contain the notation ‘Direct Rollover’ and it will be mailed directly to you. You will be responsible for forwarding it on to the new trustee. You must provide the plan Administrator with complete information to facilitate your direct rollover distribution.
|
IX. Miscellaneous Information
|
A.
|
Benefits Not Insured
|
B.
|
Attachment of Your Account
|
C.
|
Plan-to-Plan Transfer Of Assets
|
D.
|
Plan Amendment
|
E.
|
Plan Termination
|
F.
|
Interpretation of Plan
|
G.
|
Electronic Delivery
|
X. Internal Revenue Code Tests
|
A.
|
Non-Discrimination Tests
|
B.
|
Top Heavy Test
|
XI. Participant Rights
|
A.
|
Claims
|
B.
|
Statement of ERISA Rights
|
•
|
Examine, without charge, at the Plan Administrator's office and at other specified locations, such as worksites and union halls, all documents governing the Plan, including insurance contracts and collective bargaining agreements, and a copy of the latest annual report (Form 5500 Series) filed by the Plan with the U.S. Department of Labor and available at the Public Disclosure Room of the Employee Benefits Security Administration.
|
•
|
Obtain, upon written request to the Plan Administrator, copies of documents governing the operation of the plan, including insurance contracts and collective bargaining agreements, and copies of the latest annual report (Form 5500 Series) and updated Summary Plan Description. The Plan Administrator may make a reasonable charge for the copies.
|
•
|
Receive a summary of the Plan's annual financial report. The Plan Administrator is required by law to furnish each Participant with a copy of this Summary Annual Report each year.
|
•
|
Obtain a statement telling you the fair market value of your vested, accrued benefit, as of the date for which the benefits are reported, if you stop working under the Plan now. If you do not have a right to a benefit under the plan, the statement will tell you how many more years you have to work to get a right to a benefit. This statement must be requested in writing and is not required to be given more than once every twelve (12) months. The Plan must provide the statement free of charge.
|
XII. Services and Fees
|
Appendix A.Investment Options
|
Name
|
Ticker Symbol
|
Fund Code
|
Fund Objective
|
Fidelity
®
Money Market Trust Retirement Money Market Portfolio
|
FRTXX
|
630
|
Seeks to obtain as high a level of current income as is consistent with the preservation of capital and liquidity.
Investing in U.S. dollar-denominated money market securities of domestic and foreign issuers and repurchase agreements. Investing more than 25% of total assets in the financial services industries. Potentially entering into reverse repurchase agreements.
|
Managed Income Portfolio Class 1
|
|
632
|
The fund seeks to preserve your principal investment while earning a level of interest income that is consistent with principal preservation. The fund seeks to maintain a stable net asset value (NAV) of $1 per share, but it cannot guarantee that it will be able to do so. The yield of the fund will fluctuate.
The fund invests in benefit-responsive investment contracts issued by insurance companies and other financial institutions ("Contracts"), fixed income securities, and money market funds. Under the terms of the Contracts, the assets of the fund are invested in fixed income securities (which may include, but are not limited to, U.S. Treasury and agency bonds, corporate bonds, mortgage-backed securities, commercial mortgage-backed securities, asset-backed securities, and collective investment vehicles and shares of investment companies that invest primarily in fixed income securities) and shares of money market funds. The fund may also invest in futures contracts, option contracts, and swap agreements. Fidelity Management Trust Company, as investment manager and trustee of the Fidelity Group Trust for Employee Benefit Plans, has claimed an exemption from registration under the Commodity Exchange Act and is not subject to registration or regulation under the Act. At the time of purchase, all Contracts and securities purchased for the fund must satisfy the credit quality standards specified in the Declaration of Separate Fund
|
Spartan
®
U.S. Bond Index Fund - Fidelity Advantage Class
|
FSITX
|
2,324
|
Seeks to provide investment results that correspond to the aggregate price and interest performance of the debt securities in the Barclays U.S. Aggregate Bond Index.
Normally investing at least 80% of the fund's assets in bonds included in the Barclays U.S. Aggregate Bond Index. Using statistical sampling techniques based on duration, maturity, interest rate sensitivity, security structure, and credit quality to attempt to replicate the returns of the Index using a smaller number of securities. Engaging in transactions that have a leveraging effect on the fund, including investments in derivatives - such as swaps (interest rate, total return, and credit default) and futures contracts - and forward-settling securities, to adjust the fund's risk exposure. Investing in Fidelity's central funds (specialized investment vehicles used by Fidelity funds to invest in particular security types or investment disciplines).
|
Fidelity
®
Balanced Fund - Class K
|
FBAKX
|
2,077
|
Seeks income and capital growth consistent with reasonable risk.
Investing approximately 60% of assets in stocks and other equity securities and the remainder in bonds and other debt securities, including lower-quality debt securities, when its outlook is neutral. Investing at least 25% of total assets in fixed-income senior securities (including debt securities and preferred stock.) Engaging in transactions that have a leveraging effect on the fund.
|
American Beacon Large Cap Value Fund Investor Class
|
AAGPX
|
OFA2
|
The investment seeks long-term capital appreciation and current income.
Under normal circumstances, at least 80% of the fund's net assets (plus the amount of any borrowings for investment purposes) are invested in equity securities of large market capitalization U.S. companies. These companies have market capitalizations within the market capitalization range of the companies in the Russell 1000
®
Index at the time of investment.
|
Fidelity
®
Value Fund - Class K
|
FVLKX
|
2,102
|
Seeks capital appreciation.
Investing in securities of companies that possess valuable fixed assets or that FMR believes are undervalued in the marketplace in relation to factors such as assets, earnings, or growth potential (stocks of these companies are often called "value" stocks). Normally investing primarily in common stocks.
|
Royce Opportunity Fund Institutional Class
|
ROFIX
|
OKTH
|
The investment seeks long-term growth of capital.
The fund invests its assets primarily in the equity securities of small-cap companies with stock market capitalizations up to $2.5 billion in an attempt to take advantage of what it believes are opportunistic situations for undervalued securities. Normally, the fund invests at least 65% of its net assets in equity securities.
|
Spartan
®
Total Market Index Fund - Fidelity Advantage Class
|
FSTVX
|
1,520
|
Seeks to provide investment results that correspond to the total return of a broad range of United States stocks.
Normally investing at least 80% of assets in common stocks included in the Dow Jones U.S. Total Stock Market Index, which represents the performance of a broad range of U.S. stocks.
|
Fidelity
®
Contrafund
®
- Class K
|
FCNKX
|
2,080
|
Seeks capital appreciation.
Investing in securities of companies whose value FMR believes is not fully recognized by the public. Investing in either 'growth' stocks or 'value' stocks or both. Normally investing primarily in common stocks.
|
Rainier Small/Mid Cap Equity Fund Original Shares
|
RIMSX
|
OF2W
|
The investment seeks to maximize long-term capital appreciation.
In pursuing its goal, the fund invests at least 80% of its net assets, plus any borrowings for investment purposes, in the common stock of small- and mid-capitalization companies traded in the United States. It will invest in approximately 100 to 150 companies.
|
Fidelity
®
International Discovery Fund - Class K
|
FIDKX
|
2,093
|
Seeks long-term growth of capital.
Normally investing primarily in non-U.S. securities. Normally investing primarily in common stocks.
|
Spartan
®
International Index Fund - Fidelity Advantage Class
|
FSIVX
|
1,522
|
Seeks to provide investment results that correspond to the total return of foreign stock markets.
Normally investing at least 80% of assets in common stocks included in the Morgan Stanley Capital International Europe, Australasia, Far East Index, which represents the performance of foreign stock markets.
|
Petroleum Development Corporation Company Stock Fund
|
|
RTHZ
|
Invests in the stock of Petroleum Development Corporation. Performance is directly tied to the performance of the company, as well as to that of the stock market as a whole. When you exchange into or out of this stock, your transaction is generally processed on a real-time basis. Other purchase and sale requests such as contributions, distributions or other transactions, are aggregated and stock orders are typically sent to market on the following business day. These transactions, which may take multiple days to complete in some circumstances, are based on the volume-weighted average trade price. The amount of an investment option that may be sold to exchange into stock is subject to reserve requirements. Industry-standard settlement periods apply to sales of stock. Commissionsand other transaction fees will apply to transactions involving this investment.
|
Fidelity Freedom K
®
Income Fund
|
FFKAX
|
2,171
|
Seeks high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to a stable target asset allocation of approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds.
|
Fidelity Freedom K
®
2005 Fund
|
FFKVX
|
2,173
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2010 Fund
|
FFKCX
|
2,174
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2015 Fund
|
FKVFX
|
2,175
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2020 Fund
|
FFKDX
|
2,176
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2025 Fund
|
FKTWX
|
2,177
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2030 Fund
|
FFKEX
|
2,178
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2035 Fund
|
FKTHX
|
2,179
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2040 Fund
|
FFKFX
|
2,180
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2045 Fund
|
FFKGX
|
2,181
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2050 Fund
|
FFKHX
|
2,182
|
Seeks high total return until its target retirement date. Thereafter, the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
Fidelity Freedom K
®
2055 Fund
|
FDENX
|
2,332
|
Seeks high total return until its target retirement date. Thereafter the fund's objective will be to seek high current income and, as a secondary objective, capital appreciation.
Investing in a combination of underlying Fidelity domestic equity funds, international equity funds, bond funds, and short-term funds. Allocating assets among underlying Fidelity funds according to an asset allocation strategy that becomes increasingly conservative until it reaches approximately 17% in domestic equity funds, 7% in international equity funds, 46% in bond funds, and 30% in short-term funds (approximately 10 to 19 years after the target year). Ultimately, the fund will merge with Fidelity Freedom K Income Fund. Strategic Advisers may continue to seek high total return for several years beyond the fund's target retirement date in an effort to achieve the fund's overall investment objective.
|
•
|
If the Company is ranked number 1, 200% of the Target Award
|
•
|
If the Company is ranked at the 75
th
percentile of the Peer Companies, including the Company, 150% of the Target Award
|
•
|
If the Company is ranked at the 50
th
percentile or median of the Peer Companies, including the Company, 100% of the Target Award
|
•
|
If the Company is ranked at the 25
th
percentile of the Peer Companies, including the Company, 50% of the Target Award
|
•
|
If the Company is ranked below the 25
th
percentile of the Peer Companies, including the Company, no award will be paid
|
•
|
Bill Barrett Corporation
|
•
|
Carrizo Oil & Gas, Inc.
|
•
|
Comstock Resources, Inc.
|
•
|
EXCO Resources, Inc.
|
•
|
Forest Oil Corporation
|
•
|
Goodrich Petroleum Corporation
|
•
|
Gulport Energy
|
•
|
Laredo Petroleum Holdings, Inc.
|
•
|
Magnum Hunter Resources Corp.
|
•
|
Penn Virginia Corp.
|
•
|
PetroQuest Energy, Inc.
|
•
|
Quicksilver Resources, Inc.
|
•
|
Resolute Energy Corporation
|
•
|
Rosetta Resources Inc.
|
•
|
Stone Energy Corporation
|
•
|
Swift Energy Company
|
Special Vesting Events
|
Termination of Continuous Service
|
|
|
||
In the event of the termination of your Continuous Service due to death or Disability, as defined in the Plan, or due to a termination without Cause or your voluntary resignation for Good Reason (as the terms “Cause” and “Good Reason” are defined in your employment agreement, if any, or if none, in any Company severance plan in which you are a participant), any non-vested shares of Restricted Stock will vest as of your date of termination.
|
||
|
|
|
Change in Control
|
|
|
|
|
|
In the event of a “Change in Control” (as defined in the Plan) while you are in the Continuous Service of the Company, any non-vested Restricted Stock will vest in full.
|
||
Voting Rights
|
You will not have voting rights on non-vested Restricted Stock.
|
|
Dividends
|
You will be entitled to receive all regular cash dividends on non-vested shares of Restricted Stock. However, all regular cash dividends accruing during the period when the related shares of Restricted Stock are non-vested shall be accumulated and paid on the date on which the related shares of Restricted Stock become vested. In the event the shares of Restricted Stock to which the dividends relate are forfeited, the related accumulated dividends will also be forfeited.
|
|
Other Terms and Conditions
|
Are set forth in the accompanying Restricted Stock Grant Terms and Conditions, the accompanying General Terms and Conditions, and the Plan.
|
Shares of Common Stock Covered by SARs
|
__________ Shares
|
|
Exercise Price
|
$37.18 per Share, which is equal to the Fair Market Value per Share on the Grant Date.
|
|
Vesting Schedule
|
Except as set forth below, your SARs shall vest in equal annual installments over three (3) years beginning on the first anniversary of the Grant Date, provided you remain in Continuous Service (as defined above) from the Grant Date to the applicable Vesting Date, as set forth below:
|
|
SARs Vested
|
Vesting Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Special Vesting Events
|
Termination of Continuous Service
|
|
|
|
|
In the event of the termination of your Continuous Service due to death or Disability, as defined in the Plan, or due to a termination without Cause or your voluntary resignation for Good Reason (as the terms “Cause” and “Good Reason” are defined in your employment agreement, if any, or if none, in any Company severance plan in which you are a participant), any non-vested SARs will vest as of your date of termination.
|
||
|
|
|
Change in Control
|
|
|
|
|
|
In the event of a “Change in Control” (as defined in the Plan) while you are in the Continuous Service of the Company, any non-vested SARs will vest in full.
|
||
Expiration Date
|
January 15, 2024, or in the event your Continuous Service to the Company or its Affiliates terminates sooner, then at the date the SARs expire or cease to be exercisable as provided in Sections SR6 of the accompanying Stock Appreciation Rights Terms and Conditions.
|
|
Payment Amount Upon Exercise
|
Upon exercise of your SARs, you shall be entitled to receive an amount equal to the product of (x) the excess of (A) the Fair Market Value per Share on the date of exercise
over
(B) the Exercise Price stated above, multiplied by (y) the number of SARs exercised (the “Appreciation Amount”). The Appreciation Amount shall be paid in accordance with Section SR4 of the accompanying Stock Appreciation Rights Terms and Conditions.
|
|
Other Terms and Conditions
|
Are set forth in the accompanying Stock Appreciation Rights Grant Terms and Conditions, the accompanying General Terms and Conditions, and the Plan.
|
|
|
|
|
•
|
If the Company is ranked at or above the 90
th
percentile of the Peer Companies, 200% of the Target Award
|
•
|
If the Company is ranked at the 50
th
percentile or median of the Peer Companies, including the Company, 100% of the Target Award
|
•
|
If the Company is ranked at the 25
th
percentile of the Peer Companies, including the Company, 50% of the Target Award
|
•
|
If the Company is ranked below the 25
th
percentile of the Peer Companies, including the Company, no award will be paid
|
•
|
Bill Barrett Corporation
|
•
|
Bonanza Creek Energy, Inc.
|
•
|
Carrizo Oil & Gas, Inc.
|
•
|
Comstock Resources, Inc.
|
•
|
EXCO Resources, Inc.
|
•
|
Gulfport Energy
|
•
|
Laredo Petroleum Holdings, Inc.
|
•
|
Magnum Hunter Resources Corp.
|
•
|
Penn Virginia Corp.
|
•
|
Rex Energy Corporation
|
•
|
Rosetta Resources Inc.
|
•
|
Stone Energy Corporation
|
•
|
Synergy Resources
|
•
|
Ultra Petroleum Corp.
|
Special Vesting Events
|
Certain Terminations of Continuous Employment
|
|
|
|
|
In the event of the termination of your continuous employment due to death or Disability, or pursuant to a Committee-approved retirement in accordance with any then-existing retirement policy adopted by the Committee under the Plan, any non-vested Restricted Stock Units will vest as of your date of termination. You will also receive any accelerated vesting to which you may be entitled under any other applicable agreement you have with the Company or its Affiliates or in any Company sponsored severance plan in which you are a participant.
|
||
|
|
|
Change in Control
|
|
|
|
||
In the event of a “Change in Control” (as defined in the Plan) while you are in the continuous employment of the Company or its Affiliates, any non-vested Restricted Stock Units will vest in full.
|
||
Payment
|
The Company shall issue to you one share of Common Stock for each Restricted Stock Unit that vests hereunder, with the delivery of such Common Stock to occur upon the first of: (i) the Scheduled Vesting Date of such Restricted Stock Units, (ii) your “
Separation from Service
” (as defined in the Plan), or (ii) a Change in Control (the “
Applicable Payment Event
”). Notwithstanding the foregoing, if and only if (i) the Restricted Stock Units provided hereunder are non-qualified deferred compensation subject to Code Section 409A, (ii) you are a “specified employee” as defined for purposes of Code Section 409A, and (iii) distribution would otherwise be made on the date of the your Separation from Service, then distribution shall be delayed until the sooner of (x) the date that is 6 months and one day following the date of such Separation from Service, (y) your death, or (z) such sooner date as may be permitted under Code Section 409A.
|
|
Dividend Equivalent Right
|
Restricted Stock Units shall have related dividend equivalent rights, which shall entitle you to receive an additional amount in cash in respect of your vested Restricted Stock Units equal to the value of all dividends and distributions made between the Grant Date and the payment date with respect to a number of shares of Common Stock equal to the number of Restricted Stock Units paid on such date (the “
Dividend Equivalent Amounts
”). The Dividend Equivalent Amounts shall be accumulated and paid at the same time as the vested Restricted Stock Units to which they relate. In the event the related Restricted Stock Units are forfeited, the accumulated Dividends Equivalent Amounts will also be forfeited.
|
|
Stockholder Rights
|
You have no stockholder rights with respect to the Restricted Stock Units.
|
|
Other Terms and Conditions
|
Are set forth in the accompanying Restricted Stock Unit Grant Terms and Conditions and the Plan.
|
Special Vesting Events
|
Certain Terminations of Continuous Service
|
|
|
||
In the event of the termination of your Continuous Service due to death or Disability, as defined in the Plan, or due to a termination without Cause or your voluntary resignation for Good Reason (as the terms “
Cause
” and “
Good Reason
” are defined in your employment agreement, if any, or if none, in any Company severance plan in which you are a participant), any non-vested SARs will vest as of your date of termination.
|
||
|
|
|
Change in Control
|
|
|
|
|
|
In the event of a “
Change in Control
” (as defined in the Plan) while you are in the Continuous Service of the Company, any non-vested SARs will vest in full.
|
||
Expiration Date
|
January __, 2025, or in the event your Continuous Service to the Company or its Affiliates terminates sooner, then at the date the SARs expire or cease to be exercisable as provided in Section 6 of the accompanying Stock Appreciation Rights Terms and Conditions.
|
|
Payment Amount Upon Exercise
|
Upon exercise of your SARs, you shall be entitled to receive an amount equal to the product of (x) the excess of (A) the Fair Market Value per Share on the date of exercise
over
(B) the Exercise Price stated above, multiplied by (y) the number of SARs exercised (the “
Appreciation Amount
”). The Appreciation Amount shall be paid in Shares in accordance with Section 4 of the accompanying Stock Appreciation Rights Terms and Conditions.
|
|
Other Terms and Conditions
|
Are set forth in the accompanying Stock Appreciation Rights Grant Terms and Conditions and the Plan.
|
PDC ENERGY, INC.
|
|
||||||||||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges
|
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
||||||||||
|
|
(dollars in thousands)
|
|
||||||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
177,228
|
|
|
$
|
(32,963
|
)
|
|
$
|
(30,688
|
)
|
|
$
|
35,268
|
|
|
$
|
34,753
|
|
|
Fixed charges (see below)
|
|
53,512
|
|
|
54,002
|
|
|
50,228
|
|
|
40,127
|
|
|
34,990
|
|
|
|||||
Amortization of capitalized interest
|
|
1,379
|
|
|
1,096
|
|
|
871
|
|
|
675
|
|
|
788
|
|
|
|||||
Interest capitalized
|
|
(3,468
|
)
|
|
(1,709
|
)
|
|
(896
|
)
|
|
(1,454
|
)
|
|
(300
|
)
|
|
|||||
Total adjusted earnings (loss) available for fixed charges
|
|
$
|
228,651
|
|
|
$
|
20,426
|
|
|
$
|
19,515
|
|
|
$
|
74,616
|
|
|
$
|
70,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and debt expense (a)
|
|
$
|
47,842
|
|
|
$
|
50,143
|
|
|
$
|
47,505
|
|
|
$
|
36,759
|
|
|
$
|
33,239
|
|
|
Interest capitalized
|
|
3,468
|
|
|
1,709
|
|
|
896
|
|
|
1,454
|
|
|
300
|
|
|
|||||
Interest component of rental expense (b)
|
|
2,202
|
|
|
2,150
|
|
|
1,827
|
|
|
1,914
|
|
|
1,451
|
|
|
|||||
Total fixed charges
|
|
$
|
53,512
|
|
|
$
|
54,002
|
|
|
$
|
50,228
|
|
|
$
|
40,127
|
|
|
$
|
34,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
4.3
|
x
|
|
0.4
|
x
|
(c)
|
0.4
|
x
|
(c)
|
1.9
|
x
|
|
2.0
|
x
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2013 and 2012, earnings were insufficient to cover total fixed charges by
$33.6 million
and
$30.7 million
, respectively.
|
|
\s\Ryder Scott Company, L.P.
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
TBPE Firm Registration No. F-1580
|
|
|
Denver, CO
|
|
February 19, 2015
|
|
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 19, 2015
|
|
/s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief 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 19, 2015
|
|
/s/ Gysle R. Shellum
|
|
Gysle R. Shellum
|
|
Chief 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 19, 2015
|
Barton R. Brookman
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
February 19, 2015
|
Gysle R. Shellum
|
|
|
Chief Financial Officer
|
|
|
As of December 31, 2014
|
||||||||||||||||
|
|
Proved
|
||||||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
||||||||
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate - MBarrels
|
|
22,820.3
|
|
|
3,977.6
|
|
|
73,717.2
|
|
|
100,515.1
|
|
||||
Plant Products - MBarrels
|
|
13,141.5
|
|
|
3,860.3
|
|
|
43,116.9
|
|
|
60,118.7
|
|
||||
Gas - MMCF
|
|
149,519
|
|
|
37,114
|
|
|
350,339
|
|
|
536,972
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data M$
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
$
|
2,935,331
|
|
|
$
|
574,848
|
|
|
$
|
8,802,092
|
|
|
12,312,271
|
|
|
Deductions
|
|
921,282
|
|
|
243,102
|
|
|
3,872,938
|
|
|
5,037,322
|
|
||||
Future Net Income (FNI)
|
|
$
|
2,014,049
|
|
|
$
|
331,746
|
|
|
$
|
4,929,154
|
|
|
$
|
7,274,949
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
$
|
1,280,750
|
|
|
$
|
136,664
|
|
|
$
|
2,032,653
|
|
|
$
|
3,450,067
|
|
|
|
Discounted Future Net Income - M$
|
||||
|
|
As of December 31, 2014
|
||||
Discount Rate Percent
|
|
|
Total Proved
|
|
||
|
|
|
|
|
||
5
|
|
|
$
|
4,797,371
|
|
|
15
|
|
|
$
|
2,629,249
|
|
|
20
|
|
|
$
|
2,087,520
|
|
|
25
|
|
|
$
|
1,708,688
|
|
|
Geographic
Area
|
Product
|
Price
Reference
|
Avg Benchmark
Prices
|
Avg Realized
Prices
|
North America
|
|
|
|
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$94.99/Bbl
|
$84.65/Bbl
|
|
NGLs
|
WTI Cushing
|
$94.99/Bbl
|
$32.27/Bbl
|
|
Gas
|
Henry Hub
|
$4.35/MMBTU
|
$3.92/MCF
|