Delaware
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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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reductions in the borrowing base under our revolving credit facility;
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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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declines in the value of our crude oil, natural gas and NGLs properties resulting in further 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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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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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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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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•
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Multi-year project inventory in premier crude oil, natural gas and NGLs plays.
We have a significant operational presence in the Wattenberg Field, a key U.S. onshore basin, and have identified a substantial inventory of 791 gross proved undeveloped horizontal drilling locations and approximately 1,400 probable horizontal drilling locations in this play. These location counts are based on wells expected to be drilled with an average lateral length of approximately 4,700 feet. Further, with our leaseholds in Ohio, we have the ability to pursue developmental drilling in the emerging Utica Shale play and are focusing our development in the condensate and wet natural gas window of the play. 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 price projections and our current projected cost structure.
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•
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Strong liquidity position.
As of
December 31, 2015
, we had a total liquidity position of
$402.2 million
, comprised of
$0.9 million
of cash and cash equivalents and
$401.3 million
available for borrowing under our revolving credit facility. We had
$37.0 million
outstanding on our revolving credit facility as of
December 31, 2015
. Our liquidity position will be reduced by $115 million upon the maturity of our 3.25% convertible senior notes in May 2016. Pursuant to the related indenture, we will settle the principal amount of the notes in cash and issue common stock for the excess conversion value upon maturity. In September 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $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, 2015
could have been
$652.2 million
.
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•
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Significant control in our core areas.
Our operational control is enhanced by the fact that substantially all of our Wattenberg Field leasehold position is held-by-production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and held-by-production acreage. As a result, we can adjust our drilling plans if commodity prices deteriorate further in order to balance cash flows from operations and cash flows from investing activities, which primarily consist of our capital expenditures. Our leaseholds that are held-by-production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria. Additionally, as a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately
87%
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.
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•
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2016 derivative program.
We have hedged a portion of our short-term future exposure to commodity price fluctuations by entering into crude oil and natural gas collars, fixed-price swaps and basis protection swaps. 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. As of
December 31, 2015
, we had hedge positions covering approximately
4,140
MBbls of 2016 crude oil production, or approximately
45%
to
50%
of our expected crude oil production for the year. These hedges were at a weighted-average minimum price of
$77.26
per Bbl and a weighted-average maximum price of
$86.88
per Bbl. As of the same date, we had hedged approximately
29.8
Bcf, or approximately
59%
to
65%
, of our expected natural gas production in
2016
, at a weighted-average minimum price of
$3.62
per Mcf and a weighted-average maximum price of
$3.72
per Mcf. As of
December 31, 2015
, we had hedged a much lower percentage of our expected production for the next 12 to 24 months than we have hedged historically.
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•
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Technology focused team.
We have a proven track record of continuing improvement in both costs and productivity of our well operations. Recently, our teams have focused on transitioning to multi-well pad drilling, extended laterals, increased frac stage density, enhanced frac design and drilling efficiencies. In 2015, we introduced tighter frac stage density and, in 40% of our spuds, extended reach laterals that are 6,500 to 7,000 feet in length. We also began testing plug-and-perf completions along with diverting agents that have provided an uplift to our new well production. We have completed wells at various densities ranging from 16 wells per section equivalent to 26 wells per section equivalent, providing added information on the reserves that can potentially be recovered. Finally, our drilling team has made great strides in reducing drill times for one mile laterals from an average of approximately 14 days to seven days spud-to-spud over the year.
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•
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Track record of reserve and production growth.
Our proved reserves have grown from
50
MMBoe at December 31,
2010
, after adjusting for subsequent divestitures, to approximately
273
MMBoe at
December 31, 2015
, representing a compound annual growth rate (“CAGR”) of
40%
. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of
42%
. Our annual production from continuing operations grew from
3.3
MMBoe in
2010
to
15.4
MMBoe in
2015
, representing a CAGR of
36%
. Future development of the Wattenberg Field provides the opportunity to add further proved, probable and possible reserves to our portfolio. Similarly, we believe the Utica Shale provides the opportunity for additional proved, probable and possible reserves in a more favorable crude oil and natural gas pricing environment. As a result of data generated from our downspacing testing in the Wattenberg Field, Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm, has increased the density of our proven undeveloped locations, year-over-year, in the Niobrara formation. In general, at December 31, 2013, Niobrara PUD locations were booked at an equivalent density of six wells per section, at December 31, 2014, Niobrara PUD locations were booked at an equivalent density of eight wells per section and at December 31, 2015, Niobrara PUD locations are booked at the equivalent density of 16 wells per section.
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•
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Strong environmental health and safety compliance programs.
We have focused on establishing effective environmental health and safety programs that are able to earn trust and respect from regulatory agencies and public officials. We believe this is an important part of our strategy in competing in today’s intensive regulatory and public debate climate, and in working with the 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 of 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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SRL
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MRL
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XRL
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Estimated average lateral length (in feet)
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4,200
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6,900
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9,500
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Expected drilling days (spud-to-spud)
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7
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11
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14
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Estimated percentage of 2016 wells spud
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36%
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34%
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30%
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Estimated percentage of 2016 wells turned-in-line
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50%
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40%
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10%
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Estimated cost per well (in millions)(1)
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$2.6
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$3.6
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$4.6
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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 under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into longer term commitments ranging from three months to one year to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to earlier in 2015. We continue to pursue various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking of production. We began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline in July 2015. This is one of several agreements we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and expect the system to be fully operational in the first quarter of 2016. 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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•
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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 in the Wattenberg Field 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 with 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. We have entered into firm gathering and processing agreements for all of our gas production to ensure there is infrastructure available to process the gas and get it to market. 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 by the end of 2016. Pursuant to the agreement, AKA is required to install and operate, or contract for use of, facilities necessary to receive and purchase the production volumes committed under the agreement. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm gathering and processing 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"). The natural gas sales from the Blue Racer Plant are based on TETCO M-2 pricing. The gas sold at the tailgate of the MarkWest plant is sold at a price relative to the Chicago/Midwest market. Our sale of a significant portion of our Utica Shale gas to the Midwest market has helped to reduce the impact of the significant differentials that exist between the TETCO M-2 realizations and the NYMEX gas price. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas, which make economics challenging, will continue well into 2016.
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•
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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. Due to an oversupply and growing inventories of nearly all domestic NGLs products, our realized sales price for NGLs declined significantly during 2015 and, while these prices have stabilized, we expect pricing to remain at depressed levels well into 2016 and perhaps beyond.
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Productive Wells
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As of December 31, 2015
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||||||||||||||||
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Crude Oil
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Natural Gas
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Total
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||||||||||||
Operating Region/Area
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Gross
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Net
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Gross
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Net
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Gross
|
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Net
|
||||||
Wattenberg Field
|
|
625
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|
|
380.9
|
|
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2,329
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|
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2,102.9
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|
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2,954
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|
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2,483.8
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Utica Shale
|
|
25
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|
|
19.9
|
|
|
3
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|
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3.0
|
|
|
28
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|
|
22.9
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||||||
Total productive wells
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650
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|
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400.8
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|
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2,332
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2,105.9
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2,982
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|
|
2,506.7
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Proved Reserves at December 31, 2015
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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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2015 Production (MBoe)
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||||
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||||
Wattenberg Field
|
270
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|
99
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%
|
|
25
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%
|
|
60
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%
|
|
18.9
|
|
14,232
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Utica Shale
|
3
|
|
1
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%
|
|
100
|
%
|
|
55
|
%
|
|
2.8
|
|
1,138
|
|
Total proved reserves
|
273
|
|
100
|
%
|
|
26
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%
|
|
60
|
%
|
|
17.8
|
|
15,370
|
|
|
As of December 31,
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2015
|
|
2014
|
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2013 (3)
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||||||
Proved reserves
|
|
|
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||||||
Crude oil and condensate
(MMBbls)
|
99
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|
101
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94
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Natural gas
(Bcf)
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661
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|
537
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740
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NGLs
(MMBbls)
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64
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|
60
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49
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Total proved reserves
(MMBoe)
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273
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|
250
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266
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Proved developed reserves
(MMBoe)
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70
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75
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76
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Estimated future net cash flows
(in millions)
(1)
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$
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2,259
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$
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4,938
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$
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4,323
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PV-10 (
in millions)
(2)
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$
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1,338
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$
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3,450
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$
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2,704
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Standardized measure
(in millions)
|
$
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1,097
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$
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2,306
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$
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1,782
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(1)
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Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately
$2.8 billion
,
$7.3 billion
and
$6.4 billion
as of December 31,
2015
,
2014
and
2013
, respectively, less an internally-estimated future income tax expense of approximately
$0.5 billion
,
$2.3 billion
and
$2.1 billion
, respectively.
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(2)
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PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.
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(3)
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Includes estimated reserve data related to our Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of these assets.
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December 31, 2013
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Proved reserves
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Natural gas
(Bcf)
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237
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Total proved reserves
(MMBoe)
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40
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Proved developed reserves (MMBoe)
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9
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Estimated future net cash flows
(in millions)
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$
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394
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As of December 31, 2015
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Operating Region/Area
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Crude Oil and Condensate (MBbls)
|
|
Natural Gas
(MMcf) |
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NGLs
(MBbls)
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Crude Oil
Equivalent (MBoe) |
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Percent
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|||||
Proved developed
|
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|||||
Wattenberg Field
|
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25,240
|
|
|
166,679
|
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14,284
|
|
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67,304
|
|
|
95
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%
|
Utica Shale
|
|
1,017
|
|
|
8,688
|
|
|
727
|
|
|
3,192
|
|
|
5
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%
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Total proved developed
|
|
26,257
|
|
|
175,367
|
|
|
15,011
|
|
|
70,496
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|
|
100
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%
|
Proved undeveloped
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
72,718
|
|
|
485,370
|
|
|
48,716
|
|
|
202,329
|
|
|
100
|
%
|
Utica Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
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%
|
Total proved undeveloped
|
|
72,718
|
|
|
485,370
|
|
|
48,716
|
|
|
202,329
|
|
|
100
|
%
|
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
97,958
|
|
|
652,049
|
|
|
63,000
|
|
|
269,633
|
|
|
99
|
%
|
Utica Shale
|
|
1,017
|
|
|
8,688
|
|
|
727
|
|
|
3,192
|
|
|
1
|
%
|
Total proved reserves
|
|
98,975
|
|
|
660,737
|
|
|
63,727
|
|
|
272,825
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing Scenario - NYMEX
|
|
|
|
|
||||||||
|
Crude Oil (per Bbl) (1)
|
|
Natural Gas (per MMBtu) (1)
|
|
Proved Reserves (MMBoe)
|
|
% Change from December 31, 2015 Estimated Reserves
|
||||||
2015 Reserve Report (2)
|
$
|
50.28
|
|
|
$
|
2.59
|
|
|
272.8
|
|
|
—
|
|
Scenario A
|
40.00
|
|
|
2.59
|
|
|
266.1
|
|
|
(2
|
)%
|
||
Scenario B
|
30.00
|
|
|
2.59
|
|
|
256.5
|
|
|
(6
|
)%
|
(1)
|
These prices are indices and do not include basin differentials for crude oil and natural gas. The above scenarios were calculated using the indicated index prices, less any basin differentials, transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity.
|
(2)
|
The NYMEX prices used for the 2015 Reserve Report are based on SEC price parameters using the unweighted average of the prices in effect on the first day of the month for each month within the period of January 2015 through December 2015.
|
|
|
As of December 31, 2015
|
||||||||||||||||
|
|
Developed
|
|
Undeveloped
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field
|
|
97,600
|
|
|
89,400
|
|
|
7,600
|
|
|
6,300
|
|
|
105,200
|
|
|
95,700
|
|
Utica Shale
|
|
3,166
|
|
|
2,670
|
|
|
66,132
|
|
|
62,044
|
|
|
69,298
|
|
|
64,714
|
|
Total acreage
|
|
100,766
|
|
|
92,070
|
|
|
73,732
|
|
|
68,344
|
|
|
174,498
|
|
|
160,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
Operating Region
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Wattenberg Field, operated wells
|
|
140
|
|
|
113.5
|
|
|
88
|
|
|
71.0
|
|
|
62
|
|
|
53.3
|
|
Wattenberg Field, non-operated wells
|
|
58
|
|
|
9.3
|
|
|
70
|
|
|
14.9
|
|
|
35
|
|
|
7.9
|
|
Utica Shale
|
|
4
|
|
|
3.0
|
|
|
9
|
|
|
8.0
|
|
|
11
|
|
|
8.7
|
|
Other (1)
|
|
—
|
|
|
—
|
|
|
4
|
|
|
2.0
|
|
|
10
|
|
|
5.0
|
|
Total wells drilled
|
|
202
|
|
|
125.8
|
|
|
171
|
|
|
95.9
|
|
|
118
|
|
|
74.9
|
|
(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,
|
||||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Dry (1)
|
|
Productive
|
|
In-Process
|
|
Dry (1)
|
|
Productive
|
|
In-Process
|
|
Dry
|
||||||
Wattenberg Field, operated wells
|
|
110.8
|
|
50.6
|
|
2.7
|
|
75.8
|
|
|
36.5
|
|
|
1.7
|
|
|
40.5
|
|
|
—
|
|
|
—
|
|
Wattenberg Field, non-operated wells
|
|
9.3
|
|
4.6
|
|
—
|
|
14.9
|
|
|
6.3
|
|
|
—
|
|
|
13.0
|
|
|
15.6
|
|
|
0.1
|
|
Utica Shale
|
|
3.0
|
|
4.2
|
|
—
|
|
7.0
|
|
|
3.0
|
|
|
1.0
|
|
|
3.0
|
|
|
2.0
|
|
|
—
|
|
Other (2)
|
|
—
|
|
—
|
|
—
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
3.5
|
|
|
2.0
|
|
|
—
|
|
Total net development wells
|
|
123.1
|
|
59.4
|
|
2.7
|
|
99.7
|
|
|
45.8
|
|
|
2.7
|
|
|
60.0
|
|
|
19.6
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents mechanical failures 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
|
|||||||
|
|
December 31, 2013
|
|||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Dry
|
|||
Utica Shale
|
|
4.2
|
|
|
—
|
|
|
—
|
|
Other (1)
|
|
1.5
|
|
|
—
|
|
|
—
|
|
Total net exploratory wells
|
|
5.7
|
|
|
—
|
|
|
—
|
|
(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
|
•
|
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.
|
•
|
Our derivatives counterparties are, or 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.
|
|
|
||||||
|
High
|
|
Low
|
||||
|
|
|
|
||||
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
|
|
||
January 1 - March 31, 2015
|
55.47
|
|
|
37.62
|
|
||
April 1 - June 30, 2015
|
61.41
|
|
|
51.01
|
|
||
July 1 - September 30, 2015
|
61.55
|
|
|
41.17
|
|
||
October 1 - December 31, 2015
|
64.99
|
|
|
52.46
|
|
Period
|
|
Total Number of Shares Purchased (1)
|
|
Average Price Paid per Share
|
|||
|
|
|
|
|
|||
October 1 - 31, 2015
|
|
3,190
|
|
|
$
|
54.76
|
|
November 1 - 30, 2015
|
|
3,598
|
|
|
61.19
|
|
|
December 1 - 31, 2015
|
|
20,178
|
|
|
53.78
|
|
|
Total fourth quarter purchases
|
|
26,966
|
|
|
54.89
|
|
(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,
|
||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
|
(in millions, except per share data and as noted)
|
||||||||||||||||||
Statement of Operations (From Continuing Operations):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude oil, natural gas and NGLs sales
|
|
$
|
378.7
|
|
|
$
|
471.4
|
|
|
$
|
340.8
|
|
|
$
|
228.0
|
|
|
$
|
216.1
|
|
Commodity price risk management gain (loss), net
|
|
203.2
|
|
|
$
|
310.3
|
|
|
(23.9
|
)
|
|
29.3
|
|
|
39.4
|
|
||||
Total revenues
|
|
595.3
|
|
|
856.2
|
|
|
392.7
|
|
|
307.1
|
|
|
323.3
|
|
|||||
Income (loss) from continuing operations
|
|
(68.3
|
)
|
|
107.3
|
|
|
(21.1
|
)
|
|
(19.4
|
)
|
|
23.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
(1.74
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.65
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
0.98
|
|
Diluted
|
|
(1.74
|
)
|
|
2.93
|
|
|
(0.65
|
)
|
|
(0.70
|
)
|
|
0.97
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash from:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
411.1
|
|
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
$
|
174.7
|
|
|
$
|
166.8
|
|
Investing activities
|
|
(604.3
|
)
|
|
(474.1
|
)
|
|
(217.1
|
)
|
|
(451.9
|
)
|
|
(456.4
|
)
|
|||||
Financing activities
|
|
178.0
|
|
|
60.3
|
|
|
248.7
|
|
|
271.4
|
|
|
243.4
|
|
|||||
Capital expenditures
|
|
604.7
|
|
|
628.6
|
|
|
394.9
|
|
|
347.7
|
|
|
334.5
|
|
|||||
Acquisitions of crude oil and natural gas properties
|
|
—
|
|
|
—
|
|
|
9.7
|
|
|
312.2
|
|
|
145.9
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
2,370.5
|
|
|
$
|
2,331.1
|
|
|
$
|
1,991.7
|
|
|
$
|
1,777.9
|
|
|
$
|
1,676.1
|
|
Working capital
|
|
30.7
|
|
|
89.5
|
|
|
90.0
|
|
|
(67.6
|
)
|
|
(38.1
|
)
|
|||||
Total debt,
net of unamortized discount and debt issuance costs
|
|
642.4
|
|
|
655.5
|
|
|
593.9
|
|
|
637.5
|
|
|
502.4
|
|
|||||
Total equity
|
|
1,287.2
|
|
|
1,137.4
|
|
|
967.6
|
|
|
703.2
|
|
|
664.1
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pricing and Lease Operating Expenses From Continuing Operations (per Boe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Average sales price (excluding net settlements on derivatives)
|
|
$
|
24.64
|
|
|
$
|
50.72
|
|
|
$
|
52.23
|
|
|
$
|
46.85
|
|
|
$
|
49.97
|
|
Average lease operating expenses
|
|
3.71
|
|
|
4.56
|
|
|
5.18
|
|
|
5.54
|
|
|
4.95
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production (MBoe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production from continuing operations
|
|
15,369.4
|
|
|
9,294.4
|
|
|
6,524.7
|
|
|
4,866.5
|
|
|
4,324.4
|
|
|||||
Production from discontinued operations
|
|
—
|
|
|
1,093.0
|
|
|
2,032.6
|
|
|
3,458.7
|
|
|
3,596.3
|
|
|||||
Total production
|
|
15,369.4
|
|
|
10,387.4
|
|
|
8,557.3
|
|
|
8,325.2
|
|
|
7,920.7
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total proved reserves (MMBoe) (1)(2)(3)
|
|
272.8
|
|
|
250.1
|
|
|
265.8
|
|
|
192.8
|
|
|
169.3
|
|
(1)
|
Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe, 30 MMBoe and 22 MMBoe as of December 31, 2013, 2012 and 2011, respectively. See Note 15, 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 North Eastern Colorado ("NECO") assets of
14
MMBoe and
59
MMBoe as of December 31, 2012 and 2011, respectively. See Note 15, 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 as of December 31, 2011. See Note 15, 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.
|
•
|
Crude oil, natural gas and NGLs sales decreased to
$378.7 million
in
2015
compared to
$471.4 million
in
2014
, due to a
51%
decrease in the weighted-average realized prices of crude oil, natural gas and NGLs, offset in part by a
65%
increase in production;
|
•
|
Negative net change in the fair value of unsettled derivative positions in
2015
was
$35.8 million
compared to a positive net change in the fair value of unsettled derivative positions of
$311.1 million
in
2014
, primarily attributable to crude oil and natural gas derivatives that settled in
2015
;
|
•
|
General and administrative expense decreased to
$90.0 million
in
2015
compared to
$123.6 million
in
2014
, primarily attributable to $40.3 million recorded in
2014
in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships;
|
•
|
Impairment of crude oil and natural gas properties was
$161.6 million
in
2015
compared to
$166.8 million
in
2014
, both primarily related to the write-down of our Utica Shale producing and non-producing crude oil and natural gas properties; and
|
•
|
Depreciation, depletion and amortization expense increased to
$303.3 million
in
2015
compared to
$192.5 million
in
2014
, primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization rates.
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
|
|
Percent Change
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2015-2014
|
|
2014-2013
|
||||||||
|
(dollars in millions, except per unit data)
|
|
|
|
|
||||||||||||
Production (1)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (MBbls)
|
6,983.8
|
|
|
4,321.9
|
|
|
2,909.7
|
|
|
61.6
|
%
|
|
48.5
|
%
|
|||
Natural gas (MMcf)
|
33,301.7
|
|
|
19,298.0
|
|
|
15,431.2
|
|
|
72.6
|
%
|
|
25.1
|
%
|
|||
NGLs (MBbls)
|
2,835.3
|
|
|
1,756.2
|
|
|
1,043.2
|
|
|
61.4
|
%
|
|
68.3
|
%
|
|||
Crude oil equivalent (MBoe) (2)
|
15,369.4
|
|
|
9,294.4
|
|
|
6,524.7
|
|
|
65.4
|
%
|
|
42.4
|
%
|
|||
Average MBoe per day
|
42.1
|
|
|
25.5
|
|
|
17.9
|
|
|
65.4
|
%
|
|
42.4
|
%
|
|||
Crude Oil, Natural Gas and NGLs Sales
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil
|
$
|
280.3
|
|
|
$
|
348.6
|
|
|
$
|
261.6
|
|
|
(19.6
|
)%
|
|
33.3
|
%
|
Natural gas
|
68.0
|
|
|
74.7
|
|
|
50.0
|
|
|
(9.0
|
)%
|
|
49.4
|
%
|
|||
NGLs
|
30.4
|
|
|
48.1
|
|
|
29.2
|
|
|
(36.8
|
)%
|
|
64.7
|
%
|
|||
Total crude oil, natural gas and NGLs sales
|
$
|
378.7
|
|
|
$
|
471.4
|
|
|
$
|
340.8
|
|
|
(19.7
|
)%
|
|
38.3
|
%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net Settlements on Derivatives (3)
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
30.0
|
|
|
$
|
(3.1
|
)
|
|
$
|
14.3
|
|
|
*
|
|
|
*
|
|
Crude oil
|
208.9
|
|
|
2.3
|
|
|
(3.1
|
)
|
|
*
|
|
|
*
|
|
|||
Total net settlements on derivatives
|
$
|
238.9
|
|
|
$
|
(0.8
|
)
|
|
$
|
11.2
|
|
|
*
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price (excluding net settlements on derivatives)
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil (per Bbl)
|
$
|
40.14
|
|
|
$
|
80.67
|
|
|
$
|
89.92
|
|
|
(50.2
|
)%
|
|
(10.3
|
)%
|
Natural gas (per Mcf)
|
2.04
|
|
|
3.87
|
|
|
3.24
|
|
|
(47.3
|
)%
|
|
19.4
|
%
|
|||
NGLs (per Bbl)
|
10.72
|
|
|
27.39
|
|
|
27.97
|
|
|
(60.9
|
)%
|
|
(2.1
|
)%
|
|||
Crude oil equivalent (per Boe)
|
24.64
|
|
|
50.72
|
|
|
52.23
|
|
|
(51.4
|
)%
|
|
(2.9
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Lease Operating Expenses (per Boe) (4)
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
$
|
3.78
|
|
|
$
|
4.82
|
|
|
$
|
4.68
|
|
|
(21.6
|
)%
|
|
3.0
|
%
|
Utica Shale
|
2.79
|
|
|
1.87
|
|
|
2.63
|
|
|
49.2
|
%
|
|
(28.9
|
)%
|
|||
Other
|
—
|
|
|
3.19
|
|
|
14.81
|
|
|
*
|
|
|
(78.5
|
)%
|
|||
Weighted-average
|
3.71
|
|
|
4.56
|
|
|
5.18
|
|
|
(18.6
|
)%
|
|
(12.0
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Natural Gas Marketing Contribution Margin (5)
|
$
|
(0.8
|
)
|
|
$
|
(0.4
|
)
|
|
$
|
(0.3
|
)
|
|
(100.0
|
)%
|
|
(33.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Other Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||||
Production taxes
|
$
|
18.4
|
|
|
$
|
25.6
|
|
|
$
|
21.8
|
|
|
(28.0
|
)%
|
|
17.7
|
%
|
Transportation, gathering and processing expenses
|
10.2
|
|
|
4.6
|
|
|
5.2
|
|
|
121.1
|
%
|
|
(10.9
|
)%
|
|||
Exploration expense
|
1.1
|
|
|
0.9
|
|
|
6.3
|
|
|
16.4
|
%
|
|
(85.0
|
)%
|
|||
Impairment of crude oil and natural gas properties
|
161.6
|
|
|
166.8
|
|
|
52.9
|
|
|
(3.1
|
)%
|
|
215.6
|
%
|
|||
General and administrative expense
|
90.0
|
|
|
123.6
|
|
|
63.7
|
|
|
(27.2
|
)%
|
|
93.9
|
%
|
|||
Depreciation, depletion and amortization
|
303.3
|
|
|
192.5
|
|
|
115.6
|
|
|
57.5
|
%
|
|
66.5
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Interest expense
|
$
|
47.6
|
|
|
$
|
47.8
|
|
|
$
|
50.1
|
|
|
(0.6
|
)%
|
|
(4.6
|
)%
|
*
|
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 lease operating expenses, exclusive of production taxes, on a per unit basis.
|
(5)
|
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
|
|
2015
|
|
2014
|
|
2013
|
|
2015-2014
|
|
2014-2013
|
|||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
6,490.4
|
|
|
4,026.7
|
|
|
2,783.1
|
|
|
61.2
|
%
|
|
44.7
|
%
|
Utica Shale
|
|
493.4
|
|
|
295.2
|
|
|
122.8
|
|
|
67.1
|
%
|
|
140.4
|
%
|
Other
|
|
—
|
|
|
—
|
|
|
3.8
|
|
|
*
|
|
|
*
|
|
Total
|
|
6,983.8
|
|
|
4,321.9
|
|
|
2,909.7
|
|
|
61.6
|
%
|
|
48.5
|
%
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
30,752.8
|
|
|
17,108.9
|
|
|
12,724.3
|
|
|
79.7
|
%
|
|
34.5
|
%
|
Utica Shale
|
|
2,548.9
|
|
|
2,152.9
|
|
|
561.1
|
|
|
18.4
|
%
|
|
283.7
|
%
|
Other
|
|
—
|
|
|
36.2
|
|
|
2,145.8
|
|
|
*
|
|
|
(98.3
|
)%
|
Total
|
|
33,301.7
|
|
|
19,298.0
|
|
|
15,431.2
|
|
|
72.6
|
%
|
|
25.1
|
%
|
NGLs (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
2,615.9
|
|
|
1,605.7
|
|
|
1,034.4
|
|
|
62.9
|
%
|
|
55.2
|
%
|
Utica Shale
|
|
219.4
|
|
|
150.5
|
|
|
8.8
|
|
|
45.8
|
%
|
|
*
|
|
Total
|
|
2,835.3
|
|
|
1,756.2
|
|
|
1,043.2
|
|
|
61.4
|
%
|
|
68.3
|
%
|
Crude oil equivalent (MBoe)
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
14,231.7
|
|
|
8,483.8
|
|
|
5,938.2
|
|
|
67.8
|
%
|
|
42.9
|
%
|
Utica Shale
|
|
1,137.7
|
|
|
804.6
|
|
|
225.2
|
|
|
41.4
|
%
|
|
257.3
|
%
|
Other
|
|
—
|
|
|
6.0
|
|
|
361.3
|
|
|
*
|
|
|
(98.3
|
)%
|
Total
|
|
15,369.4
|
|
|
9,294.4
|
|
|
6,524.7
|
|
|
65.4
|
%
|
|
42.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
*
|
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)
|
|
2015
|
|
2014
|
|
2013
|
|
2015-2014
|
|
2014-2013
|
||||||||
Crude oil (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
$
|
40.03
|
|
|
$
|
80.61
|
|
|
$
|
89.83
|
|
|
(50.3
|
)%
|
|
(10.3
|
)%
|
Utica Shale
|
|
41.59
|
|
|
81.52
|
|
|
91.90
|
|
|
(49.0
|
)%
|
|
(11.3
|
)%
|
|||
Other
|
|
—
|
|
|
—
|
|
|
92.88
|
|
|
*
|
|
|
*
|
|
|||
Weighted-average price
|
|
40.14
|
|
|
80.67
|
|
|
89.92
|
|
|
(50.2
|
)%
|
|
(10.3
|
)%
|
|||
Natural gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
2.06
|
|
|
3.94
|
|
|
3.25
|
|
|
(47.7
|
)%
|
|
21.2
|
%
|
|||
Utica Shale
|
|
1.85
|
|
|
3.35
|
|
|
2.74
|
|
|
(44.8
|
)%
|
|
22.3
|
%
|
|||
Other
|
|
—
|
|
|
3.90
|
|
|
3.31
|
|
|
*
|
|
|
17.8
|
%
|
|||
Weighted-average price
|
|
2.04
|
|
|
3.87
|
|
|
3.24
|
|
|
(47.3
|
)%
|
|
19.4
|
%
|
|||
NGLs (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
10.58
|
|
|
25.95
|
|
|
27.83
|
|
|
(59.2
|
)%
|
|
(6.8
|
)%
|
|||
Utica Shale
|
|
12.43
|
|
|
42.76
|
|
|
43.70
|
|
|
(70.9
|
)%
|
|
(2.2
|
)%
|
|||
Weighted-average price
|
|
10.72
|
|
|
27.39
|
|
|
27.97
|
|
|
(60.9
|
)%
|
|
(2.1
|
)%
|
|||
Crude oil equivalent (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
24.64
|
|
|
51.10
|
|
|
53.91
|
|
|
(51.8
|
)%
|
|
(5.2
|
)%
|
|||
Utica Shale
|
|
24.59
|
|
|
46.87
|
|
|
58.68
|
|
|
(47.5
|
)%
|
|
(20.1
|
)%
|
|||
Other
|
|
—
|
|
|
23.42
|
|
|
20.59
|
|
|
*
|
|
|
13.7
|
%
|
|||
Weighted-average price
|
|
24.64
|
|
|
50.72
|
|
|
52.23
|
|
|
(51.4
|
)%
|
|
(2.9
|
)%
|
*
|
Percentage change is not meaningful or equal to or greater than 300%.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in millions)
|
||||||
Increase in production
|
$
|
298.5
|
|
|
$
|
159.5
|
|
Decrease in average crude oil price
|
(283.1
|
)
|
|
(40.0
|
)
|
||
Increase (decrease) in average natural gas price
|
(60.9
|
)
|
|
12.1
|
|
||
Decrease in average NGLs price
|
(47.2
|
)
|
|
(1.0
|
)
|
||
Total increase (decrease) in crude oil, natural gas and NGLs sales revenue
|
$
|
(92.7
|
)
|
|
$
|
130.6
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Commodity price risk management gain (loss), net:
|
|
|
|
|
|
||||||
Net settlements:
|
|
|
|
|
|
||||||
Natural gas
|
$
|
30.0
|
|
|
$
|
(3.1
|
)
|
|
$
|
14.3
|
|
Crude oil
|
208.9
|
|
|
2.3
|
|
|
(3.1
|
)
|
|||
Total net settlements
|
238.9
|
|
|
(0.8
|
)
|
|
11.2
|
|
|||
Change in fair value of unsettled derivatives:
|
|
|
|
|
|
||||||
Reclassification of settlements included in prior period changes in fair value of derivatives
|
(186.9
|
)
|
|
13.3
|
|
|
(28.7
|
)
|
|||
Natural gas fixed price swaps
|
40.5
|
|
|
30.6
|
|
|
4.3
|
|
|||
Natural gas basis swaps
|
(1.4
|
)
|
|
—
|
|
|
(4.3
|
)
|
|||
Natural gas collars
|
12.8
|
|
|
11.1
|
|
|
3.8
|
|
|||
Crude oil fixed price swaps
|
57.0
|
|
|
206.5
|
|
|
(9.1
|
)
|
|||
Crude oil collars
|
42.3
|
|
|
49.6
|
|
|
(1.1
|
)
|
|||
Net change in fair value of unsettled derivatives
|
(35.7
|
)
|
|
311.1
|
|
|
(35.1
|
)
|
|||
Total commodity price risk management gain (loss), net
|
$
|
203.2
|
|
|
$
|
310.3
|
|
|
$
|
(23.9
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Natural gas sales revenue
|
$
|
10.4
|
|
|
$
|
71.4
|
|
|
$
|
68.9
|
|
Net settlements from derivatives
|
0.8
|
|
|
(0.2
|
)
|
|
0.5
|
|
|||
Net change in fair value of unsettled derivatives
|
(0.3
|
)
|
|
0.4
|
|
|
0.4
|
|
|||
Total sales from natural gas marketing
|
10.9
|
|
|
71.6
|
|
|
69.8
|
|
|||
|
|
|
|
|
|
||||||
Costs of natural gas purchases
|
10.3
|
|
|
70.1
|
|
|
68.1
|
|
|||
Net settlements from derivatives
|
0.7
|
|
|
(0.3
|
)
|
|
0.3
|
|
|||
Net change in fair value of unsettled derivatives
|
(0.3
|
)
|
|
0.4
|
|
|
0.4
|
|
|||
Other
|
1.0
|
|
|
1.8
|
|
|
1.3
|
|
|||
Total costs of natural gas marketing
|
11.7
|
|
|
72.0
|
|
|
70.1
|
|
|||
|
|
|
|
|
|
||||||
Natural gas marketing contribution margin
|
$
|
(0.8
|
)
|
|
$
|
(0.4
|
)
|
|
$
|
(0.3
|
)
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Geological and geophysical costs
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.7
|
|
Operating, personnel and other
|
|
1.1
|
|
|
0.9
|
|
|
5.6
|
|
|||
Total exploration expense
|
|
$
|
1.1
|
|
|
$
|
0.9
|
|
|
$
|
6.3
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Continuing operations:
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
$
|
154.6
|
|
|
$
|
161.6
|
|
|
$
|
49.7
|
|
Amortization of individually insignificant unproved properties
|
7.0
|
|
|
4.4
|
|
|
3.2
|
|
|||
Other
|
—
|
|
|
0.8
|
|
|
—
|
|
|||
Total impairment of crude oil and natural gas properties
|
$
|
161.6
|
|
|
$
|
166.8
|
|
|
$
|
52.9
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in millions)
|
||||||
Increase in production
|
|
$
|
123.4
|
|
|
$
|
48.9
|
|
Increase (decrease) in weighted-average depreciation, depletion and amortization rates
|
|
(13.1
|
)
|
|
28.0
|
|
||
Total increase in DD&A expense related to crude oil and natural gas properties
|
|
$
|
110.3
|
|
|
$
|
76.9
|
|
|
|
Year Ended December 31,
|
||||||||||
Operating Region/Area
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(per Boe)
|
||||||||||
Wattenberg Field
|
|
$
|
20.13
|
|
|
$
|
19.26
|
|
|
$
|
17.68
|
|
Utica Shale
|
|
10.74
|
|
|
31.19
|
|
|
24.87
|
|
|||
Other
|
|
—
|
|
|
—
|
|
|
2.66
|
|
|||
Total weighted-average
|
|
19.44
|
|
|
20.28
|
|
|
17.05
|
|
|
|
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)
|
|
$
|
652.0
|
|
|
$
|
115.0
|
|
|
$
|
—
|
|
|
$
|
37.0
|
|
|
$
|
500.0
|
|
Derivative contracts (3)
|
|
2.3
|
|
|
1.6
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
|||||
Capital leases (4)
|
|
1.4
|
|
|
0.4
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|||||
Production tax liability
|
|
45.5
|
|
|
26.5
|
|
|
19.0
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
89.5
|
|
|
5.5
|
|
|
12.9
|
|
|
14.0
|
|
|
57.1
|
|
|||||
Other liabilities (5)
|
|
4.3
|
|
|
0.3
|
|
|
1.3
|
|
|
1.5
|
|
|
1.2
|
|
|||||
|
|
795.0
|
|
|
149.3
|
|
|
34.9
|
|
|
52.5
|
|
|
558.3
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commitments, contingencies and other arrangements (6)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest on long-term debt (7)
|
|
275.8
|
|
|
42.9
|
|
|
82.5
|
|
|
81.0
|
|
|
69.4
|
|
|||||
Operating leases
|
|
10.5
|
|
|
2.4
|
|
|
4.1
|
|
|
3.9
|
|
|
0.1
|
|
|||||
Firm transportation and processing agreements (8)
|
|
84.6
|
|
|
17.6
|
|
|
33.4
|
|
|
26.4
|
|
|
7.2
|
|
|||||
|
|
370.9
|
|
|
62.9
|
|
|
120.0
|
|
|
111.3
|
|
|
76.7
|
|
|||||
Total
|
|
$
|
1,165.9
|
|
|
$
|
212.2
|
|
|
$
|
154.9
|
|
|
$
|
163.8
|
|
|
$
|
635.0
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Table does not include deferred income tax liability to taxing authorities of
$143.5 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
$1.9 million
of unamortized debt discount and
$7.8 million
of unamortized debt issuance costs. 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)
|
Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets.
|
(5)
|
Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.
|
(6)
|
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 12, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report.
|
(7)
|
Amounts presented include $263.2 million to the holders of our 7.75% senior notes due 2022 and $1.4 million payable to the holders of our 3.25% convertible senior notes due 2016. Amounts also include $11.0 million payable to the participating banks in our revolving credit facility, of which interest of $6.6 million is related to unutilized commitments at a rate of 0.38% per annum, $4.3 million related to the outstanding borrowings on our revolving credit facility of
$37.0 million
and $0.2 million related to our undrawn letters of credit.
|
(8)
|
Represents our gross commitment. See Note 12, 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,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Adjusted cash flows from operations:
|
|
|
|
|
|
||||||
Adjusted cash flows from operations
|
$
|
420.8
|
|
|
$
|
250.2
|
|
|
$
|
207.8
|
|
Changes in assets and liabilities
|
(9.7
|
)
|
|
(13.5
|
)
|
|
(48.6
|
)
|
|||
Net cash from operating activities
|
$
|
411.1
|
|
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
|
|
|
|
|
||||||
Adjusted net income (loss):
|
|
|
|
|
|
||||||
Adjusted net income (loss)
|
$
|
(46.1
|
)
|
|
$
|
(37.7
|
)
|
|
$
|
0.5
|
|
Gain on commodity derivative instruments
|
203.2
|
|
|
309.3
|
|
|
(23.7
|
)
|
|||
Net settlements on commodity derivative instruments
|
(239.0
|
)
|
|
2.0
|
|
|
(13.1
|
)
|
|||
Tax effect of above adjustments
|
13.6
|
|
|
(118.2
|
)
|
|
14.0
|
|
|||
Net income (loss)
|
$
|
(68.3
|
)
|
|
$
|
155.4
|
|
|
$
|
(22.3
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA to net income (loss):
|
|
|
|
|
|
||||||
Adjusted EBITDA
|
$
|
443.2
|
|
|
$
|
364.3
|
|
|
$
|
241.4
|
|
Gain on commodity derivative instruments
|
203.2
|
|
|
309.3
|
|
|
(23.7
|
)
|
|||
Net settlements on commodity derivative instruments
|
(239.0
|
)
|
|
2.0
|
|
|
(13.1
|
)
|
|||
Interest expense, net
|
(42.8
|
)
|
|
(48.6
|
)
|
|
(51.4
|
)
|
|||
Income tax provision
|
38.3
|
|
|
(99.2
|
)
|
|
12.6
|
|
|||
Impairment of crude oil and natural gas properties
|
(161.6
|
)
|
|
(167.3
|
)
|
|
(53.8
|
)
|
|||
Depreciation, depletion and amortization
|
(303.3
|
)
|
|
(201.7
|
)
|
|
(129.5
|
)
|
|||
Accretion of asset retirement obligations
|
(6.3
|
)
|
|
(3.4
|
)
|
|
(4.8
|
)
|
|||
Net income (loss)
|
$
|
(68.3
|
)
|
|
$
|
155.4
|
|
|
$
|
(22.3
|
)
|
|
|
|
|
|
|
||||||
Adjusted EBITDA to net cash from operating activities:
|
|
|
|
|
|
||||||
Adjusted EBITDA
|
$
|
443.2
|
|
|
$
|
364.3
|
|
|
$
|
241.4
|
|
Interest expense, net
|
(42.8
|
)
|
|
(48.6
|
)
|
|
(51.4
|
)
|
|||
Stock-based compensation
|
20.1
|
|
|
17.5
|
|
|
12.9
|
|
|||
Amortization of debt discount and issuance costs
|
7.0
|
|
|
6.9
|
|
|
6.8
|
|
|||
(Gain) loss on sale of properties and equipment
|
(0.4
|
)
|
|
(76.0
|
)
|
|
3.7
|
|
|||
Other
|
(6.3
|
)
|
|
(13.9
|
)
|
|
(5.6
|
)
|
|||
Changes in assets and liabilities
|
(9.7
|
)
|
|
(13.5
|
)
|
|
(48.6
|
)
|
|||
Net cash from operating activities
|
$
|
411.1
|
|
|
$
|
236.7
|
|
|
$
|
159.2
|
|
|
|
|
|
|
|
||||||
PV-10:
|
|
|
|
|
|
||||||
PV-10
|
$
|
1,337.5
|
|
|
$
|
3,450.1
|
|
|
$
|
2,703.9
|
|
Present value of estimated future income tax discounted at 10%
|
(240.6
|
)
|
|
(1,143.6
|
)
|
|
(921.7
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,096.9
|
|
|
$
|
2,306.5
|
|
|
$
|
1,782.2
|
|
|
|
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,
2015 (2)
(in millions)
|
|||||||||||||||
|
Floors
|
|
Ceilings
|
|
|
|
|
|
|||||||||||||||||||||
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
NYMEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
2016
|
|
7,820.0
|
|
|
$
|
3.88
|
|
|
$
|
4.24
|
|
|
21,930.0
|
|
|
$
|
3.93
|
|
|
27,600.0
|
|
|
$
|
(0.29
|
)
|
|
$
|
41.2
|
|
2017
|
|
7,920.0
|
|
|
3.59
|
|
|
4.13
|
|
|
24,590.0
|
|
|
3.62
|
|
|
12,000.0
|
|
|
(0.28
|
)
|
|
26.5
|
|
|||||
2018
|
|
1,230.0
|
|
|
3.00
|
|
|
3.67
|
|
|
13,830.0
|
|
|
3.05
|
|
|
—
|
|
|
—
|
|
|
2.1
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total Natural Gas
|
|
16,970.0
|
|
|
|
|
|
|
60,350.0
|
|
|
|
|
39,600.0
|
|
|
|
|
$
|
69.8
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
NYMEX
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
2016
|
|
1,740.0
|
|
|
$
|
77.59
|
|
|
$
|
97.55
|
|
|
2,400.0
|
|
|
$
|
90.37
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
178.8
|
|
2017
|
|
960.0
|
|
|
54.06
|
|
|
73.77
|
|
|
480.0
|
|
|
56.99
|
|
|
—
|
|
|
—
|
|
|
15.1
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total Crude Oil
|
|
2,700.0
|
|
|
|
|
|
|
2,880.0
|
|
|
|
|
—
|
|
|
|
|
193.9
|
|
|||||||||
Total Natural Gas and Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
263.7
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
A standard unit of measurement for natural gas (one BBtu
equals one MMcf).
|
(2)
|
Approximately 34.3% of the fair value of our derivative assets 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,
|
||||||
|
2015
|
|
2014
|
||||
Average Index Closing Price:
|
|
|
|
||||
Crude oil (per Bbl)
|
|
|
|
||||
NYMEX
|
$
|
48.80
|
|
|
$
|
92.91
|
|
Natural gas (per MMBtu)
|
|
|
|
||||
NYMEX
|
$
|
2.66
|
|
|
$
|
4.42
|
|
CIG
|
2.44
|
|
|
4.17
|
|
||
TETCO M-2 (1)
|
1.49
|
|
|
3.35
|
|
||
|
|
|
|
||||
Average Sales Price Realized:
|
|
|
|
||||
Excluding net settlements on derivatives
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
40.14
|
|
|
$
|
80.67
|
|
Natural gas (per Mcf)
|
2.04
|
|
|
3.87
|
|
||
NGLs (per Bbl)
|
10.72
|
|
|
27.39
|
|
Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
|
||
|
|
|
Financial Statements:
|
|
|
|
||
|
||
Consolidated Statements of Operations - Years Ended December 31, 2
015, 2014 and 2013
|
|
|
Consolidated Statements of Cash Flows - Years Ended December 31, 201
5, 2014 and 2013
|
|
|
Consolidated Statements of Equity - Years Ended December 31, 201
5, 2014 and 2013
|
|
|
|
||
|
|
|
Supplemental Information - Unaudited:
|
|
|
|
||
|
||
|
|
|
Financial Statement Schedule:
|
|
|
|
||
|
|
|
As of December 31,
|
|
2015
|
|
2014
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
850
|
|
|
$
|
16,066
|
|
Accounts receivable, net
|
|
104,274
|
|
|
131,204
|
|
||
Fair value of derivatives
|
|
221,659
|
|
|
187,495
|
|
||
Prepaid expenses and other current assets
|
|
5,266
|
|
|
5,954
|
|
||
Total current assets
|
|
332,049
|
|
|
340,719
|
|
||
Properties and equipment, net
|
|
1,937,678
|
|
|
1,827,454
|
|
||
Assets held for sale
|
|
2,874
|
|
|
2,874
|
|
||
Fair value of derivatives
|
|
44,387
|
|
|
112,819
|
|
||
Other assets
|
|
53,555
|
|
|
47,274
|
|
||
Total Assets
|
|
$
|
2,370,543
|
|
|
$
|
2,331,140
|
|
|
|
|
|
|
||||
Liabilities and Shareholders' Equity
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
92,613
|
|
|
$
|
130,321
|
|
Production tax liability
|
|
26,524
|
|
|
21,314
|
|
||
Fair value of derivatives
|
|
1,595
|
|
|
570
|
|
||
Funds held for distribution
|
|
29,894
|
|
|
27,186
|
|
||
Current portion of long-term debt
|
|
112,940
|
|
|
—
|
|
||
Accrued interest payable
|
|
9,057
|
|
|
9,109
|
|
||
Other accrued expenses
|
|
28,709
|
|
|
62,717
|
|
||
Total current liabilities
|
|
301,332
|
|
|
251,217
|
|
||
Long-term debt
|
|
529,437
|
|
|
655,475
|
|
||
Deferred income taxes
|
|
143,452
|
|
|
184,867
|
|
||
Asset retirement obligation
|
|
84,032
|
|
|
71,992
|
|
||
Fair value of derivatives
|
|
695
|
|
|
197
|
|
||
Other liabilities
|
|
24,398
|
|
|
30,033
|
|
||
Total liabilities
|
|
1,083,346
|
|
|
1,193,781
|
|
||
|
|
|
|
|
||||
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, 40,174,776 and 35,927,985 issued as of December 31, 2015 and 2014, respectively
|
|
402
|
|
|
359
|
|
||
Additional paid-in capital
|
|
907,382
|
|
|
689,209
|
|
||
Retained earnings
|
|
380,422
|
|
|
448,702
|
|
||
Treasury shares - at cost, 20,220 and 21,643 as of December 31, 2015 and 2014, respectively
|
|
(1,009
|
)
|
|
(911
|
)
|
||
Total shareholders' equity
|
|
1,287,197
|
|
|
1,137,359
|
|
||
Total Liabilities and Shareholders' Equity
|
|
$
|
2,370,543
|
|
|
$
|
2,331,140
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2015
|
|
2014
|
|
2013
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
|
$
|
378,713
|
|
|
$
|
471,413
|
|
|
$
|
340,795
|
|
Sales from natural gas marketing
|
|
10,920
|
|
|
71,571
|
|
|
69,787
|
|
|||
Commodity price risk management gain (loss), net
|
|
203,183
|
|
|
310,304
|
|
|
(23,919
|
)
|
|||
Well operations, pipeline income and other
|
|
2,510
|
|
|
2,919
|
|
|
6,002
|
|
|||
Total revenues
|
|
595,326
|
|
|
856,207
|
|
|
392,665
|
|
|||
Costs, expenses and other
|
|
|
|
|
|
|
||||||
Lease operating expenses
|
|
56,992
|
|
|
42,402
|
|
|
33,817
|
|
|||
Production taxes
|
|
18,443
|
|
|
25,615
|
|
|
21,758
|
|
|||
Transportation, gathering and processing expenses
|
|
10,151
|
|
|
4,592
|
|
|
5,152
|
|
|||
Cost of natural gas marketing
|
|
11,717
|
|
|
72,015
|
|
|
70,084
|
|
|||
Exploration expense
|
|
1,102
|
|
|
947
|
|
|
6,334
|
|
|||
Impairment of crude oil and natural gas properties
|
|
161,620
|
|
|
166,847
|
|
|
52,873
|
|
|||
General and administrative expense
|
|
89,959
|
|
|
123,559
|
|
|
63,715
|
|
|||
Depreciation, depletion and amortization
|
|
303,258
|
|
|
192,528
|
|
|
115,624
|
|
|||
Accretion of asset retirement obligations
|
|
6,293
|
|
|
3,415
|
|
|
4,566
|
|
|||
(Gain) loss on sale of properties and equipment
|
|
(385
|
)
|
|
507
|
|
|
2,022
|
|
|||
Total cost, expenses and other
|
|
659,150
|
|
|
632,427
|
|
|
375,945
|
|
|||
Income (loss) from operations
|
|
(63,824
|
)
|
|
223,780
|
|
|
16,720
|
|
|||
Interest expense
|
|
(47,571
|
)
|
|
(47,842
|
)
|
|
(50,143
|
)
|
|||
Interest income
|
|
4,807
|
|
|
1,290
|
|
|
460
|
|
|||
Income (loss) from continuing operations before income taxes
|
|
(106,588
|
)
|
|
177,228
|
|
|
(32,963
|
)
|
|||
Provision for income taxes
|
|
38,308
|
|
|
(69,967
|
)
|
|
11,852
|
|
|||
Income (loss) from continuing operations
|
|
(68,280
|
)
|
|
107,261
|
|
|
(21,111
|
)
|
|||
Income (loss) from discontinued operations, net of tax
|
|
—
|
|
|
48,174
|
|
|
(1,190
|
)
|
|||
Net income (loss)
|
|
$
|
(68,280
|
)
|
|
$
|
155,435
|
|
|
$
|
(22,301
|
)
|
|
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(1.74
|
)
|
|
$
|
3.00
|
|
|
$
|
(0.65
|
)
|
Income (loss) from discontinued operations, net of tax
|
|
—
|
|
|
1.34
|
|
|
(0.04
|
)
|
|||
Net income (loss)
|
|
$
|
(1.74
|
)
|
|
$
|
4.34
|
|
|
$
|
(0.69
|
)
|
|
|
|
|
|
|
|
||||||
Diluted
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(1.74
|
)
|
|
$
|
2.93
|
|
|
$
|
(0.65
|
)
|
Income (loss) from discontinued operations, net of tax
|
|
—
|
|
|
1.31
|
|
|
(0.04
|
)
|
|||
Net income (loss)
|
|
$
|
(1.74
|
)
|
|
$
|
4.24
|
|
|
$
|
(0.69
|
)
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
||||||
Basic
|
|
39,153
|
|
|
35,784
|
|
|
32,426
|
|
|||
Diluted
|
|
39,153
|
|
|
36,678
|
|
|
32,426
|
|
|||
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2015
|
|
2014
|
|
2013
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
(68,280
|
)
|
|
$
|
155,435
|
|
|
$
|
(22,301
|
)
|
Adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
|
|
|
|
|
||||||
Net change in fair value of unsettled derivatives
|
|
35,791
|
|
|
(311,281
|
)
|
|
36,801
|
|
|||
Depreciation, depletion and amortization
|
|
303,258
|
|
|
201,656
|
|
|
129,518
|
|
|||
Impairment of crude oil and natural gas properties
|
|
161,620
|
|
|
167,280
|
|
|
53,802
|
|
|||
Accretion of asset retirement obligation
|
|
6,293
|
|
|
3,455
|
|
|
4,747
|
|
|||
Stock-based compensation
|
|
20,068
|
|
|
17,518
|
|
|
12,880
|
|
|||
Excess tax benefits from stock-based compensation
|
|
(1,361
|
)
|
|
(1,999
|
)
|
|
(2,489
|
)
|
|||
(Gain) loss from sale of properties and equipment
|
|
(385
|
)
|
|
(75,972
|
)
|
|
3,722
|
|
|||
Amortization of debt discount and issuance costs
|
|
7,040
|
|
|
6,938
|
|
|
6,783
|
|
|||
Deferred income taxes
|
|
(41,415
|
)
|
|
88,474
|
|
|
(15,883
|
)
|
|||
Other
|
|
(1,855
|
)
|
|
(1,329
|
)
|
|
170
|
|
|||
Total adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
489,054
|
|
|
94,740
|
|
|
230,051
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
24,769
|
|
|
(34,598
|
)
|
|
(41,509
|
)
|
|||
Other assets
|
|
(2,264
|
)
|
|
(3,296
|
)
|
|
3,461
|
|
|||
Restricted cash
|
|
46
|
|
|
2,214
|
|
|
(8
|
)
|
|||
Production tax liability
|
|
(1,629
|
)
|
|
3,358
|
|
|
4,121
|
|
|||
Accounts payable and accrued expenses
|
|
(30,310
|
)
|
|
21,453
|
|
|
(11,485
|
)
|
|||
Other liabilities
|
|
(313
|
)
|
|
(2,617
|
)
|
|
(3,165
|
)
|
|||
Total changes in assets and liabilities
|
|
(9,701
|
)
|
|
(13,486
|
)
|
|
(48,585
|
)
|
|||
Net cash from operating activities
|
|
411,073
|
|
|
236,689
|
|
|
159,165
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(604,668
|
)
|
|
(628,592
|
)
|
|
(394,948
|
)
|
|||
Acquisition of crude oil and natural gas properties, net of cash acquired
|
|
—
|
|
|
—
|
|
|
(9,658
|
)
|
|||
Proceeds from acquisition adjustments
|
|
—
|
|
|
—
|
|
|
7,579
|
|
|||
Proceeds from sale of properties and equipment, net
|
|
405
|
|
|
154,457
|
|
|
179,919
|
|
|||
Net cash from investing activities
|
|
(604,263
|
)
|
|
(474,135
|
)
|
|
(217,108
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from revolving credit facility
|
|
397,000
|
|
|
263,750
|
|
|
260,250
|
|
|||
Repayment of revolving credit facility
|
|
(416,000
|
)
|
|
(200,000
|
)
|
|
(283,500
|
)
|
|||
Payment of debt issuance costs
|
|
(974
|
)
|
|
(88
|
)
|
|
(2,352
|
)
|
|||
Proceeds from sale of common stock, net of issuance costs
|
|
202,851
|
|
|
—
|
|
|
275,847
|
|
|||
Excess tax benefits from stock-based compensation
|
|
1,361
|
|
|
1,999
|
|
|
2,489
|
|
|||
Purchase of treasury shares
|
|
(6,056
|
)
|
|
(5,392
|
)
|
|
(4,133
|
)
|
|||
Principal payments under capital lease obligations
|
|
(208
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from exercise of stock options
|
|
—
|
|
|
—
|
|
|
128
|
|
|||
Net cash from financing activities
|
|
177,974
|
|
|
60,269
|
|
|
248,729
|
|
|||
Net change in cash and cash equivalents
|
|
(15,216
|
)
|
|
(177,177
|
)
|
|
190,786
|
|
|||
Cash and cash equivalents, beginning of year
|
|
16,066
|
|
|
193,243
|
|
|
2,457
|
|
|||
Cash and cash equivalents, end of year
|
|
$
|
850
|
|
|
$
|
16,066
|
|
|
$
|
193,243
|
|
|
|
|
|
|
|
|
||||||
Supplemental cash flow information:
|
|
|
|
|
|
|
||||||
Cash payments for (receipts from):
|
|
|
|
|
|
|
||||||
Interest, net of capitalized interest
|
|
$
|
45,642
|
|
|
$
|
46,809
|
|
|
$
|
48,844
|
|
Income taxes
|
|
10,049
|
|
|
1,800
|
|
|
(3,014
|
)
|
|||
Non-cash investing activities:
|
|
|
|
|
|
|
||||||
Change in accounts payable related to capital expenditures
|
|
(45,230
|
)
|
|
39,667
|
|
|
33,328
|
|
|||
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal
|
|
14,030
|
|
|
33,250
|
|
|
2,112
|
|
|||
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
|
|
|||
Purchase of properties and equipment under capital leases
|
|
1,601
|
|
|
—
|
|
|
—
|
|
Year Ended December 31,
|
|
2015
|
|
2014
|
|
2013
|
||||||
Common shares, issued:
|
|
|
|
|
|
|
||||||
Shares beginning of year
|
|
35,927,985
|
|
|
35,675,656
|
|
|
30,294,224
|
|
|||
Shares issued pursuant to sale of equity
|
|
4,002,000
|
|
|
—
|
|
|
5,175,000
|
|
|||
Exercise of stock options
|
|
7,720
|
|
|
—
|
|
|
10,763
|
|
|||
Issuance of stock awards, net of forfeitures
|
|
237,071
|
|
|
253,032
|
|
|
212,926
|
|
|||
Retirement of treasury shares
|
|
—
|
|
|
(703
|
)
|
|
(17,257
|
)
|
|||
Shares end of year
|
|
40,174,776
|
|
|
35,927,985
|
|
|
35,675,656
|
|
|||
Treasury shares:
|
|
|
|
|
|
|
||||||
Shares beginning of year
|
|
21,643
|
|
|
5,508
|
|
|
5,059
|
|
|||
Purchase of treasury shares
|
|
120,864
|
|
|
97,646
|
|
|
84,642
|
|
|||
Issuance of treasury shares
|
|
(127,159
|
)
|
|
(83,208
|
)
|
|
(67,334
|
)
|
|||
Retirement of treasury shares
|
|
—
|
|
|
(703
|
)
|
|
(17,257
|
)
|
|||
Non-employee directors' deferred compensation plan
|
|
4,872
|
|
|
2,400
|
|
|
398
|
|
|||
Shares end of year
|
|
20,220
|
|
|
21,643
|
|
|
5,508
|
|
|||
Common shares outstanding
|
|
40,154,556
|
|
|
35,906,342
|
|
|
35,670,148
|
|
|||
|
|
|
|
|
|
|
||||||
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
|
|
359
|
|
|
357
|
|
|
303
|
|
|||
Shares issued pursuant to sale of equity
|
|
40
|
|
|
—
|
|
|
52
|
|
|||
Issuance of stock awards, net of forfeitures
|
|
3
|
|
|
2
|
|
|
2
|
|
|||
Balance end of year
|
|
402
|
|
|
359
|
|
|
357
|
|
|||
Additional paid-in capital:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
689,209
|
|
|
674,211
|
|
|
387,494
|
|
|||
Proceeds from sale of equity, net of issuance costs
|
|
202,811
|
|
|
—
|
|
|
275,795
|
|
|||
Exercise of stock options
|
|
—
|
|
|
—
|
|
|
125
|
|
|||
Stock-based compensation expense
|
|
20,207
|
|
|
17,851
|
|
|
12,402
|
|
|||
Issuance of treasury shares
|
|
(6,206
|
)
|
|
(4,817
|
)
|
|
(3,270
|
)
|
|||
Retirement of treasury shares
|
|
—
|
|
|
(35
|
)
|
|
(824
|
)
|
|||
Tax impact of stock-based compensation
|
|
1,361
|
|
|
1,999
|
|
|
2,489
|
|
|||
Balance end of year
|
|
907,382
|
|
|
689,209
|
|
|
674,211
|
|
|||
Retained earnings:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
448,702
|
|
|
293,267
|
|
|
315,568
|
|
|||
Net income (loss) attributable to shareholders
|
|
(68,280
|
)
|
|
155,435
|
|
|
(22,301
|
)
|
|||
Balance end of year
|
|
380,422
|
|
|
448,702
|
|
|
293,267
|
|
|||
Treasury shares, at cost:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
(911
|
)
|
|
(241
|
)
|
|
(184
|
)
|
|||
Purchase of treasury shares
|
|
(6,055
|
)
|
|
(5,392
|
)
|
|
(4,133
|
)
|
|||
Issuance of treasury shares
|
|
6,206
|
|
|
4,817
|
|
|
3,271
|
|
|||
Retirement of treasury shares
|
|
—
|
|
|
35
|
|
|
824
|
|
|||
Non-employee directors' deferred compensation plan
|
|
(249
|
)
|
|
(130
|
)
|
|
(19
|
)
|
|||
Balance end of year
|
|
(1,009
|
)
|
|
(911
|
)
|
|
(241
|
)
|
|||
Total shareholders' equity
|
|
$
|
1,287,197
|
|
|
$
|
1,137,359
|
|
|
$
|
967,594
|
|
|
|
|
|
|
|
|
•
|
Production-related general and administrative costs totaling
$7.7 million
and
$3.8 million
for 2014 and 2013, respectively, have been reclassified from production costs to general and administrative expense;
|
•
|
Prepaid well costs write-offs totaling
$3.3 million
and
$0.4 million
for 2014 and 2013, respectively, have been reclassified from production costs to impairment of crude oil and natural gas properties; and
|
•
|
Prepaid well costs totaling
$27.3 million
in the December 31, 2014 consolidated balance sheet have been reclassified from other assets to properties and equipment, net;
|
•
|
Debt issuance costs totaling
$9.4 million
in the December 31, 2014 consolidated balance sheet have been reclassified from other assets and are presented as a direct deduction from the carrying amount of long-term debt; and
|
•
|
Current deferred income tax liabilities totaling
$59.2 million
in the December 31, 2014 consolidated balance sheet have been reclassified to non-current pursuant to the income tax accounting standards update issued and adopted in 2015.
|
Transportation and other equipment
|
3 - 20 years
|
Buildings
|
20 - 30 years
|
|
As of December 31,
|
||||||||||||||||||||||
|
2015
|
|
2014
|
||||||||||||||||||||
|
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
|
$
|
174,657
|
|
|
$
|
91,288
|
|
|
$
|
265,945
|
|
|
$
|
237,939
|
|
|
$
|
62,356
|
|
|
$
|
300,295
|
|
Basis protection derivative contracts
|
101
|
|
|
—
|
|
|
101
|
|
|
19
|
|
|
—
|
|
|
19
|
|
||||||
Total assets
|
174,758
|
|
|
91,288
|
|
|
266,046
|
|
|
237,958
|
|
|
62,356
|
|
|
300,314
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity-based derivative contracts
|
738
|
|
|
—
|
|
|
738
|
|
|
742
|
|
|
—
|
|
|
742
|
|
||||||
Basis protection derivative contracts
|
1,552
|
|
|
—
|
|
|
1,552
|
|
|
25
|
|
|
—
|
|
|
25
|
|
||||||
Total liabilities
|
2,290
|
|
|
—
|
|
|
2,290
|
|
|
767
|
|
|
—
|
|
|
767
|
|
||||||
Net asset
|
$
|
172,468
|
|
|
$
|
91,288
|
|
|
$
|
263,756
|
|
|
$
|
237,191
|
|
|
$
|
62,356
|
|
|
$
|
299,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Fair value, net asset beginning of period
|
|
$
|
62,356
|
|
|
$
|
1,111
|
|
|
$
|
13,610
|
|
Changes in fair value included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
65,018
|
|
|
62,003
|
|
|
(1,748
|
)
|
|||
Sales from natural gas marketing
|
|
146
|
|
|
(22
|
)
|
|
13
|
|
|||
Settlements included in statement of operations line items:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
(36,169
|
)
|
|
(737
|
)
|
|
(6,361
|
)
|
|||
Sales from natural gas marketing
|
|
(63
|
)
|
|
1
|
|
|
(37
|
)
|
|||
Loss from discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
(4,366
|
)
|
|||
Fair value, net asset end of period
|
|
$
|
91,288
|
|
|
$
|
62,356
|
|
|
$
|
1,111
|
|
|
|
|
|
|
|
|
||||||
Net change in fair value of unsettled derivatives included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain (loss), net
|
|
$
|
43,540
|
|
|
$
|
15,632
|
|
|
$
|
(2,731
|
)
|
Sales from natural gas marketing
|
|
—
|
|
|
3
|
|
|
4
|
|
|||
Total
|
|
$
|
43,540
|
|
|
$
|
15,635
|
|
|
$
|
(2,727
|
)
|
|
|
|
|
|
|
|
•
|
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
2015
, 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
|
|
2015
|
|
2014
|
|||||
|
|
|
|
|
(in thousands)
|
||||||
Derivative assets:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
$
|
221,161
|
|
|
$
|
186,886
|
|
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
441
|
|
|
590
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
57
|
|
|
19
|
|
||
|
|
|
|
|
221,659
|
|
|
187,495
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
44,292
|
|
|
112,599
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
51
|
|
|
220
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
44
|
|
|
—
|
|
||
|
|
|
|
|
44,387
|
|
|
112,819
|
|
||
Total derivative assets
|
|
|
|
|
$
|
266,046
|
|
|
$
|
300,314
|
|
|
|
|
|
|
|
|
|
||||
Derivative liabilities:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
$
|
417
|
|
|
$
|
545
|
|
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
1,178
|
|
|
25
|
|
||
|
|
|
|
|
1,595
|
|
|
570
|
|
||
|
Non-current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
275
|
|
|
—
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
46
|
|
|
197
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to crude oil and natural gas sales
|
|
Fair value of derivatives
|
|
374
|
|
|
—
|
|
||
|
|
|
|
|
695
|
|
|
197
|
|
||
Total derivative liabilities
|
|
|
|
|
$
|
2,290
|
|
|
$
|
767
|
|
|
|
Year Ended December 31,
|
||||||||||
Consolidated statement of operations line item
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
Commodity price risk management gain (loss), net
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
238,935
|
|
|
$
|
(837
|
)
|
|
$
|
11,177
|
|
Net change in fair value of unsettled derivatives
|
|
(35,752
|
)
|
|
311,141
|
|
|
(35,096
|
)
|
|||
Total commodity price risk management gain (loss), net
|
|
$
|
203,183
|
|
|
$
|
310,304
|
|
|
$
|
(23,919
|
)
|
Sales from natural gas marketing
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
778
|
|
|
$
|
(208
|
)
|
|
$
|
446
|
|
Net change in fair value of unsettled derivatives
|
|
(318
|
)
|
|
364
|
|
|
429
|
|
|||
Total sales from natural gas marketing
|
|
$
|
460
|
|
|
$
|
156
|
|
|
$
|
875
|
|
Cost of natural gas marketing
|
|
|
|
|
|
|
||||||
Net settlements
|
|
$
|
(745
|
)
|
|
$
|
346
|
|
|
$
|
(257
|
)
|
Net change in fair value of unsettled derivatives
|
|
279
|
|
|
(451
|
)
|
|
(412
|
)
|
|||
Total cost of natural gas marketing
|
|
$
|
(466
|
)
|
|
$
|
(105
|
)
|
|
$
|
(669
|
)
|
|
|
|
|
|
|
|
As of December 31, 2015
|
|
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
|
|
$
|
266,046
|
|
|
$
|
(1,921
|
)
|
|
$
|
264,125
|
|
|
|
|
|
|
|
|
||||||
Liability derivatives:
|
|
|
|
|
|
|
||||||
Derivative instruments, at fair value
|
|
$
|
2,290
|
|
|
$
|
(1,921
|
)
|
|
$
|
369
|
|
|
|
|
|
|
|
|
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,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Crude oil, natural gas and NGLs sales
|
$
|
41,873
|
|
|
$
|
49,531
|
|
Joint interest billings
|
35,017
|
|
|
52,841
|
|
||
Derivative counterparties
|
24,437
|
|
|
12,582
|
|
||
Insurance reimbursement
|
879
|
|
|
11,212
|
|
||
Other
|
4,077
|
|
|
5,524
|
|
||
Allowance for doubtful accounts
|
(2,009
|
)
|
|
(486
|
)
|
||
Accounts receivable, net
|
$
|
104,274
|
|
|
$
|
131,204
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
Customer
|
|
2015
|
|
2014
|
|
2013
|
|||
|
|
|
|
|
|
|
|||
Concord Energy
|
|
23.2
|
%
|
|
18.3
|
%
|
|
—
|
%
|
Suncor Energy Marketing, Inc.
|
|
14.3
|
%
|
|
19.7
|
%
|
|
35.9
|
%
|
Shell Trading Company
|
|
13.8
|
%
|
|
—
|
%
|
|
—
|
%
|
DCP Midstream, LP
|
|
13.2
|
%
|
|
15.1
|
%
|
|
13.9
|
%
|
Teppco Crude Oil, LLC
|
|
—
|
%
|
|
12.9
|
%
|
|
8.0
|
%
|
|
|
Fair Value of
Derivative Assets |
||
Counterparty Name
|
|
As of December 31, 2015
|
||
|
|
(in thousands)
|
||
|
|
|
||
Canadian Imperial Bank of Commerce (1)
|
|
$
|
78,102
|
|
JP Morgan Chase Bank, N.A (1)
|
|
71,012
|
|
|
Bank of Nova Scotia (1)
|
|
49,758
|
|
|
Wells Fargo Bank, N.A. (1)
|
|
32,474
|
|
|
NATIXIS (1)
|
|
29,754
|
|
|
Other lenders in our revolving credit facility
|
|
4,856
|
|
|
Other (2)
|
|
90
|
|
|
Total
|
|
$
|
266,046
|
|
|
|
|
|
Amount
|
||
|
(in thousands)
|
||
Note receivable:
|
|
||
Principal outstanding, December 31, 2014
|
$
|
39,707
|
|
Paid-in-kind interest
|
3,362
|
|
|
Principal outstanding, December 31, 2015
|
$
|
43,069
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Properties and equipment, net:
|
|
|
|
||||
Crude oil and natural gas properties
|
|
|
|
||||
Proved
|
$
|
2,881,189
|
|
|
$
|
2,267,165
|
|
Unproved
|
60,498
|
|
|
188,206
|
|
||
Total crude oil and natural gas properties
|
2,941,687
|
|
|
2,455,371
|
|
||
Equipment and other
|
30,098
|
|
|
29,562
|
|
||
Land and buildings
|
9,015
|
|
|
9,015
|
|
||
Construction in progress
|
113,115
|
|
|
165,205
|
|
||
Properties and equipment, at cost
|
3,093,915
|
|
|
2,659,153
|
|
||
Accumulated DD&A
|
(1,156,237
|
)
|
|
(831,699
|
)
|
||
Properties and equipment, net
|
$
|
1,937,678
|
|
|
$
|
1,827,454
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Continuing operations:
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
$
|
154,608
|
|
|
$
|
161,604
|
|
|
$
|
49,631
|
|
Amortization of individually insignificant unproved properties
|
7,012
|
|
|
4,465
|
|
|
3,242
|
|
|||
Other
|
—
|
|
|
778
|
|
|
—
|
|
|||
Total continuing operations
|
161,620
|
|
|
166,847
|
|
|
52,873
|
|
|||
Discontinued operations:
|
|
|
|
|
|
||||||
Impairment of proved and unproved properties
|
—
|
|
|
433
|
|
|
566
|
|
|||
Amortization of individually insignificant unproved properties
|
—
|
|
|
—
|
|
|
363
|
|
|||
Total discontinued operations
|
—
|
|
|
433
|
|
|
929
|
|
|||
Total impairment of crude oil and natural gas properties
|
$
|
161,620
|
|
|
$
|
167,280
|
|
|
$
|
53,802
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
(2,944
|
)
|
|
$
|
(1,514
|
)
|
|
$
|
1,355
|
|
State
|
(163
|
)
|
|
966
|
|
|
199
|
|
|||
Total current income taxes
|
(3,107
|
)
|
|
(548
|
)
|
|
1,554
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
37,352
|
|
|
(60,698
|
)
|
|
8,238
|
|
|||
State
|
4,063
|
|
|
(8,721
|
)
|
|
2,060
|
|
|||
Total deferred income taxes
|
41,415
|
|
|
(69,419
|
)
|
|
10,298
|
|
|||
Income tax benefit (expense) from continuing operations
|
$
|
38,308
|
|
|
$
|
(69,967
|
)
|
|
$
|
11,852
|
|
|
|
|
|
|
|
|
Year Ended December, 31,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
|
|
|
|
|
|
|||
Statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State income tax, net
|
2.4
|
|
|
2.8
|
|
|
4.0
|
|
Percentage depletion
|
0.3
|
|
|
(0.3
|
)
|
|
2.2
|
|
Non-deductible compensation
|
(1.2
|
)
|
|
0.7
|
|
|
(4.2
|
)
|
Other
|
(0.6
|
)
|
|
1.3
|
|
|
(1.0
|
)
|
Effective tax rate
|
35.9
|
%
|
|
39.5
|
%
|
|
36.0
|
%
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Deferred compensation
|
$
|
13,104
|
|
|
$
|
10,459
|
|
Asset retirement obligations
|
34,101
|
|
|
28,051
|
|
||
State NOL and tax credit carryforwards, net
|
3,376
|
|
|
3,761
|
|
||
Alternative minimum tax - credit carryforward
|
2,812
|
|
|
2,906
|
|
||
Settlement of class action litigation
|
—
|
|
|
12,259
|
|
||
Other
|
3,412
|
|
|
3,144
|
|
||
Deferred tax assets
|
56,805
|
|
|
60,580
|
|
||
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Properties and equipment
|
99,191
|
|
|
130,155
|
|
||
Net change in fair value of unsettled derivatives
|
100,369
|
|
|
113,007
|
|
||
Convertible debt
|
697
|
|
|
2,285
|
|
||
Total gross deferred tax liabilities
|
200,257
|
|
|
245,447
|
|
||
Net deferred tax liability
|
$
|
143,452
|
|
|
$
|
184,867
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Senior notes:
|
|
|
|
||||
3.25% Convertible senior notes due 2016:
|
|
|
|
||||
Principal amount
|
$
|
115,000
|
|
|
$
|
115,000
|
|
Unamortized discount
|
(1,852
|
)
|
|
(6,077
|
)
|
||
Unamortized debt issuance costs
|
(208
|
)
|
|
(765
|
)
|
||
3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs
|
112,940
|
|
|
108,158
|
|
||
|
|
|
|
||||
7.75% Senior notes due 2022:
|
|
|
|
||||
Principal amount
|
500,000
|
|
|
500,000
|
|
||
Unamortized debt issuance costs
|
(7,563
|
)
|
|
(8,683
|
)
|
||
7.75% Senior notes due 2022, net of unamortized debt issuance costs
|
492,437
|
|
|
491,317
|
|
||
Total senior notes
|
605,377
|
|
|
599,475
|
|
||
|
|
|
|
||||
Revolving credit facility
|
37,000
|
|
|
56,000
|
|
||
Total debt, net of discount and unamortized debt issuance costs
|
642,377
|
|
|
655,475
|
|
||
Less current portion of long-term debt
|
112,940
|
|
|
—
|
|
||
Long-term debt
|
$
|
529,437
|
|
|
$
|
655,475
|
|
|
|
Amount
|
||
|
|
(in thousands)
|
||
Vehicles
|
|
$
|
1,601
|
|
Accumulated depreciation
|
|
(211
|
)
|
|
|
|
$
|
1,390
|
|
For the Twelve Months Ending December 31,
|
|
Amount
|
||
|
|
(in thousands)
|
||
2016
|
|
$
|
492
|
|
2017
|
|
492
|
|
|
2018
|
|
681
|
|
|
|
|
1,665
|
|
|
Less executory cost
|
|
(70
|
)
|
|
Less amount representing interest
|
|
(202
|
)
|
|
Present value of minimum lease payments
|
|
$
|
1,393
|
|
|
|
|
|
|
Short-term capital lease obligations
|
|
$
|
357
|
|
Long-term capital lease obligations
|
|
1,036
|
|
|
|
|
$
|
1,393
|
|
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Balance at beginning of period, January 1, 2015
|
$
|
73,855
|
|
|
$
|
41,030
|
|
Revisions in estimated cash flows
|
11,658
|
|
|
31,945
|
|
||
Obligations incurred with development activities
|
2,373
|
|
|
1,170
|
|
||
Accretion expense
|
6,293
|
|
|
3,455
|
|
||
Obligations discharged with asset retirements
|
(4,687
|
)
|
|
(3,745
|
)
|
||
Balance end of period, December 31, 2015
|
89,492
|
|
|
73,855
|
|
||
Less current portion
|
(5,460
|
)
|
|
(1,863
|
)
|
||
Long-term portion
|
$
|
84,032
|
|
|
$
|
71,992
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||
Area
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020 and
Through Expiration |
|
Total
|
|
Expiration
Date |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Gas Marketing segment
|
|
7,136
|
|
|
7,117
|
|
|
7,117
|
|
|
7,117
|
|
|
18,687
|
|
|
47,174
|
|
|
August 31, 2022
|
||||||
Utica Shale
|
|
2,745
|
|
|
2,737
|
|
|
2,737
|
|
|
2,737
|
|
|
9,811
|
|
|
20,767
|
|
|
July 22, 2023
|
||||||
Total
|
|
9,881
|
|
|
9,854
|
|
|
9,854
|
|
|
9,854
|
|
|
28,498
|
|
|
67,941
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Wattenberg Field
|
|
2,420
|
|
|
2,413
|
|
|
2,413
|
|
|
2,413
|
|
|
1,205
|
|
|
10,864
|
|
|
June 30, 2020
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dollar commitment (in thousands)
|
|
$
|
17,622
|
|
|
$
|
17,156
|
|
|
$
|
16,324
|
|
|
$
|
16,324
|
|
|
$
|
17,193
|
|
|
$
|
84,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||||
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Minimum Lease Payments
|
|
$
|
2,353
|
|
|
$
|
2,166
|
|
|
$
|
1,975
|
|
|
$
|
1,937
|
|
|
$
|
1,967
|
|
|
$
|
124
|
|
|
$
|
10,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Stock-based compensation expense
|
|
$
|
20,068
|
|
|
$
|
17,518
|
|
|
$
|
12,880
|
|
Income tax benefit
|
|
(7,636
|
)
|
|
(5,955
|
)
|
|
(4,697
|
)
|
|||
Net stock-based compensation expense
|
|
$
|
12,432
|
|
|
$
|
11,563
|
|
|
$
|
8,183
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
|
|
|
||||||
Expected term of award
|
5.2 years
|
|
|
6 years
|
|
|
6 years
|
|
|||
Risk-free interest rate
|
1.4
|
%
|
|
2.1
|
%
|
|
1.0
|
%
|
|||
Expected volatility
|
58.0
|
%
|
|
65.6
|
%
|
|
65.5
|
%
|
|||
Weighted-average grant date fair value per share
|
$
|
22.23
|
|
|
$
|
29.96
|
|
|
$
|
21.96
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||||||||||||||||||||||||
|
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,
|
279,011
|
|
|
$
|
38.77
|
|
|
7.8
|
|
|
$
|
1,472
|
|
|
190,763
|
|
|
$
|
33.77
|
|
|
$
|
3,711
|
|
|
118,832
|
|
|
$
|
30.80
|
|
|
$
|
486
|
|
Awarded
|
68,274
|
|
|
39.63
|
|
|
—
|
|
|
—
|
|
|
88,248
|
|
|
49.57
|
|
|
—
|
|
|
87,078
|
|
|
37.18
|
|
|
—
|
|
||||||
Exercised
|
(20,832
|
)
|
|
38.05
|
|
|
—
|
|
|
473
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,147
|
)
|
|
30.06
|
|
|
425
|
|
||||||
Outstanding at December 31,
|
326,453
|
|
|
38.99
|
|
|
7.3
|
|
|
4,697
|
|
|
279,011
|
|
|
38.77
|
|
|
1,472
|
|
|
190,763
|
|
|
33.77
|
|
|
3,711
|
|
||||||
Exercisable at December 31,
|
222,489
|
|
|
37.70
|
|
|
6.8
|
|
|
3,489
|
|
|
139,334
|
|
|
36.27
|
|
|
982
|
|
|
51,922
|
|
|
29.97
|
|
|
1,207
|
|
|
Shares
|
|
Weighted-Average
Grant-Date Fair Value |
|||
|
|
|
|
|||
Non-vested at December 31, 2014
|
564,332
|
|
|
$
|
46.02
|
|
Granted
|
313,639
|
|
|
48.88
|
|
|
Vested
|
(333,167
|
)
|
|
41.59
|
|
|
Forfeited
|
(19,723
|
)
|
|
54.29
|
|
|
Non-vested at December 31, 2015
|
525,081
|
|
|
50.23
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of time-based awards vested
|
$
|
17,077
|
|
|
$
|
18,278
|
|
|
$
|
13,640
|
|
Total intrinsic value of time-based awards non-vested
|
28,029
|
|
|
23,290
|
|
|
34,688
|
|
|||
Market price per common share as of December 31,
|
53.38
|
|
|
41.27
|
|
|
53.22
|
|
|||
Weighted-average grant date fair value per share
|
48.88
|
|
|
56.45
|
|
|
45.53
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
|
|
|
||||
Expected term of award
|
|
3 years
|
|
|
3 years
|
|
||
Risk-free interest rate
|
|
0.9
|
%
|
|
0.8
|
%
|
||
Expected volatility
|
|
53.0
|
%
|
|
55.2
|
%
|
||
Weighted-average grant date fair value per share
|
|
$
|
66.16
|
|
|
$
|
56.87
|
|
|
|
Shares
|
|
Weighted-Average
Grant-Date Fair Value per Share |
|||
|
|
|
|
|
|||
Non-vested at December 31, 2014
|
|
83,721
|
|
|
$
|
52.98
|
|
Granted
|
|
29,398
|
|
|
66.16
|
|
|
Vested
|
|
(41,570
|
)
|
|
49.04
|
|
|
Non-vested at December 31, 2015
|
|
71,549
|
|
|
63.60
|
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of market-based awards vested
|
$
|
4,293
|
|
|
$
|
1,260
|
|
|
$
|
724
|
|
Total intrinsic value of market-based awards non-vested
|
3,819
|
|
|
3,455
|
|
|
3,838
|
|
|||
Market price per common share as of December 31,
|
53.38
|
|
|
41.27
|
|
|
53.22
|
|
|||
Weighted-average grant date fair value per share
|
66.16
|
|
|
56.87
|
|
|
49.04
|
|
|
Year Ended December 31,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common shares outstanding - basic
|
39,153
|
|
|
35,784
|
|
|
32,426
|
|
Dilutive effect of:
|
|
|
|
|
|
|||
Restricted stock
|
—
|
|
|
279
|
|
|
—
|
|
Convertible notes
|
—
|
|
|
564
|
|
|
—
|
|
Other equity-based awards
|
—
|
|
|
51
|
|
|
—
|
|
Weighted-average common shares and equivalents outstanding - diluted
|
39,153
|
|
|
36,678
|
|
|
32,426
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common share equivalents excluded from diluted earnings
|
|
|
|
|
|
|||
per share due to their anti-dilutive effect:
|
|
|
|
|
|
|||
Restricted stock
|
831
|
|
|
8
|
|
|
823
|
|
Convertible notes
|
562
|
|
|
—
|
|
|
518
|
|
Other equity-based awards
|
101
|
|
|
26
|
|
|
83
|
|
Total anti-dilutive common share equivalents
|
1,494
|
|
|
34
|
|
|
1,424
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||
Consolidated statements of operations - discontinued operations
|
|
2014
|
|
2013
|
||||
|
|
(in thousands)
|
||||||
Revenues
|
|
|
|
|
||||
Crude oil, natural gas and NGLs sales
|
|
$
|
24,149
|
|
|
$
|
39,001
|
|
Sales from natural gas marketing
|
|
—
|
|
|
2,825
|
|
||
Commodity price risk management income (loss), net
|
|
(1,085
|
)
|
|
14
|
|
||
Well operations, pipeline income and other
|
|
48
|
|
|
922
|
|
||
Total revenues
|
|
23,112
|
|
|
42,762
|
|
||
|
|
|
|
|
||||
Costs, expenses and other
|
|
|
|
|
||||
Lease operating expenses
|
|
1,280
|
|
|
6,522
|
|
||
Production taxes
|
|
1,579
|
|
|
3,716
|
|
||
Transportation, gathering and processing expenses
|
|
3,536
|
|
|
5,283
|
|
||
Cost of natural gas marketing
|
|
—
|
|
|
2,673
|
|
||
Impairment of crude oil and natural gas properties
|
|
433
|
|
|
954
|
|
||
Depreciation, depletion and amortization
|
|
9,128
|
|
|
13,894
|
|
||
Other
|
|
4,170
|
|
|
8,235
|
|
||
Gain on sale of properties and equipment
|
|
(76,479
|
)
|
|
1,700
|
|
||
Total costs, expenses and other
|
|
(56,353
|
)
|
|
42,977
|
|
||
|
|
|
|
|
||||
Interest expense
|
|
(2,222
|
)
|
|
(1,755
|
)
|
||
Interest income
|
|
194
|
|
|
10
|
|
||
Income from discontinued operations
|
|
77,437
|
|
|
(1,960
|
)
|
||
Provision for income taxes
|
|
(29,263
|
)
|
|
770
|
|
||
Income (loss) from discontinued operations, net of tax
|
|
$
|
48,174
|
|
|
$
|
(1,190
|
)
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||
Supplemental cash flows information - discontinued operations
|
|
2014
|
|
2013
|
||||
|
|
(in thousands)
|
||||||
Cash flows from investing activities:
|
|
|
|
|
||||
Capital expenditures
|
|
$
|
(17,253
|
)
|
|
$
|
(45,277
|
)
|
|
|
|
|
|
||||
Significant non-cash investing items:
|
|
|
|
|
||||
Change in accounts payable related to purchases of properties and equipment
|
|
(5,727
|
)
|
|
(4,738
|
)
|
||
|
|
|
|
|
|
2015
|
|
2014
|
—
|
|
2013
|
||||||
|
(in thousands)
|
|||||||||||
Year Ended December 31,
|
|
|
|
|
|
|||||||
Segment revenues:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
584,406
|
|
|
$
|
784,636
|
|
|
$
|
322,878
|
|
|
Gas marketing
|
10,920
|
|
|
71,571
|
|
|
69,787
|
|
||||
Total revenues
|
$
|
595,326
|
|
|
$
|
856,207
|
|
|
$
|
392,665
|
|
|
|
|
|
|
|
|
|||||||
Segment income (loss) before income taxes:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
31,429
|
|
|
$
|
344,149
|
|
|
$
|
81,913
|
|
|
Gas marketing
|
(797
|
)
|
|
(445
|
)
|
|
(297
|
)
|
||||
Unallocated
|
(137,220
|
)
|
|
(166,476
|
)
|
|
(114,579
|
)
|
||||
Income (loss) before income taxes
|
$
|
(106,588
|
)
|
|
$
|
177,228
|
|
|
$
|
(32,963
|
)
|
|
|
|
|
|
|
|
|||||||
Expenditures for segment long-lived assets:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
599,617
|
|
|
$
|
623,912
|
|
|
$
|
403,227
|
|
|
Unallocated
|
5,051
|
|
|
4,680
|
|
|
1,379
|
|
||||
Total
|
$
|
604,668
|
|
|
$
|
628,592
|
|
|
$
|
404,606
|
|
|
|
|
|
|
|
|
|||||||
As of December 31,
|
|
|
|
|
|
|||||||
Segment assets:
|
|
|
|
|
|
|||||||
Oil and gas exploration and production
|
$
|
2,294,288
|
|
|
$
|
2,258,060
|
|
|
|
|||
Gas marketing
|
4,217
|
|
|
6,979
|
|
|
|
|||||
Unallocated
|
69,164
|
|
|
63,227
|
|
|
|
|||||
Assets held for sale
|
2,874
|
|
|
2,874
|
|
|
|
|||||
Total assets
|
$
|
2,370,543
|
|
|
$
|
2,331,140
|
|
|
|
|||
|
|
|
|
|
|
|
|
Price Used to Estimate Reserves*
|
||||||||||
As of December 31,
|
|
Crude Oil
(per Bbl)
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl)
|
||||||
|
|
|
|
|
|
|
||||||
2015
|
|
$
|
42.10
|
|
|
$
|
2.05
|
|
|
$
|
12.23
|
|
2014
|
|
84.65
|
|
|
3.92
|
|
|
32.27
|
|
|||
2013
|
|
82.18
|
|
|
3.22
|
|
|
29.92
|
|
*
|
These prices are based on the index prices and are net of basin differentials, any transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity.
|
|
Crude Oil, Condensate (MBbls)
|
|
Natural Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Total
(MBoe)
|
||||
Proved Reserves:
|
|
|
|
|
|
|
|
||||
Proved reserves, January 1, 2013 (1)
|
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, including infill reserves in an existing proved field
|
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 (2)
|
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, including infill reserves in an existing proved field
|
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
|
|
Revisions of previous estimates
|
(43,268
|
)
|
|
(154,775
|
)
|
|
(24,407
|
)
|
|
(93,471
|
)
|
Extensions, discoveries and other additions, including infill reserves in an existing proved field
|
48,707
|
|
|
311,709
|
|
|
30,835
|
|
|
131,494
|
|
Purchases of reserves
|
17
|
|
|
215
|
|
|
23
|
|
|
76
|
|
Dispositions
|
(12
|
)
|
|
(82
|
)
|
|
(8
|
)
|
|
(34
|
)
|
Production
|
(6,984
|
)
|
|
(33,302
|
)
|
|
(2,835
|
)
|
|
(15,369
|
)
|
Proved reserves, December 31, 2015
|
98,975
|
|
|
660,737
|
|
|
63,727
|
|
|
272,825
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves, as of:
|
|
|
|
|
|
|
|
||||
January 1, 2013 (1)
|
20,412
|
|
|
281,925
|
|
|
14,353
|
|
|
81,753
|
|
December 31, 2013 (2)
|
23,997
|
|
|
220,387
|
|
|
14,825
|
|
|
75,553
|
|
December 31, 2014
|
26,798
|
|
|
186,633
|
|
|
17,002
|
|
|
74,905
|
|
December 31, 2015
|
26,257
|
|
|
175,367
|
|
|
15,011
|
|
|
70,496
|
|
Proved Undeveloped Reserves, as of:
|
|
|
|
|
|
|
|
||||
January 1, 2013 (1)
|
38,898
|
|
|
322,113
|
|
|
18,474
|
|
|
111,058
|
|
December 31, 2013 (2)
|
69,833
|
|
|
519,253
|
|
|
33,846
|
|
|
190,221
|
|
December 31, 2014
|
73,717
|
|
|
350,339
|
|
|
43,117
|
|
|
175,224
|
|
December 31, 2015
|
72,718
|
|
|
485,370
|
|
|
48,716
|
|
|
202,329
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 15, 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.
|
(2)
|
Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 15, 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, 2013
|
81,753
|
|
|
111,057
|
|
|
192,810
|
|
Production
|
(7,430
|
)
|
|
—
|
|
|
(7,430
|
)
|
Undeveloped reserves converted to developed
|
3,212
|
|
|
(3,212
|
)
|
|
—
|
|
Purchases of reserves
|
1,043
|
|
|
—
|
|
|
1,043
|
|
Dispositions
|
(16,104
|
)
|
|
—
|
|
|
(16,104
|
)
|
Extensions, discoveries and other additions, including infill reserves in an existing proved field
|
19,830
|
|
|
122,105
|
|
|
141,935
|
|
Revisions of previous estimates
|
(6,751
|
)
|
|
(39,729
|
)
|
|
(46,480
|
)
|
Ending proved reserves, December 31, 2013
|
75,553
|
|
|
190,221
|
|
|
265,774
|
|
Production
|
(9,294
|
)
|
|
—
|
|
|
(9,294
|
)
|
Undeveloped reserves converted to developed
|
12,730
|
|
|
(12,730
|
)
|
|
—
|
|
Purchases of reserves
|
17
|
|
|
—
|
|
|
17
|
|
Dispositions
|
(9,231
|
)
|
|
(30,341
|
)
|
|
(39,572
|
)
|
Extensions, discoveries and other additions, including infill reserves in an existing proved field
|
27,957
|
|
|
70,072
|
|
|
98,029
|
|
Revisions of previous estimates
|
(22,827
|
)
|
|
(41,998
|
)
|
|
(64,825
|
)
|
Ending proved reserves, December 31, 2014
|
74,905
|
|
|
175,224
|
|
|
250,129
|
|
Production
|
(15,369
|
)
|
|
—
|
|
|
(15,369
|
)
|
Undeveloped reserves converted to developed
|
29,090
|
|
|
(29,090
|
)
|
|
—
|
|
Purchases of reserves
|
76
|
|
|
—
|
|
|
76
|
|
Dispositions
|
(34
|
)
|
|
—
|
|
|
(34
|
)
|
Extensions, discoveries and other additions, including infill reserves in an existing proved field
|
8,703
|
|
|
122,791
|
|
|
131,494
|
|
Revisions of previous estimates
|
(26,875
|
)
|
|
(66,596
|
)
|
|
(93,471
|
)
|
Ending proved reserves, December 31, 2015
|
70,496
|
|
|
202,329
|
|
|
272,825
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Revenue:
|
|
|
|
|
|
||||||
Crude oil, natural gas and NGLs sales
|
$
|
378,713
|
|
|
$
|
495,562
|
|
|
$
|
379,796
|
|
Commodity price risk management gain (loss), net
|
203,183
|
|
|
309,219
|
|
|
(23,905
|
)
|
|||
|
581,896
|
|
|
804,781
|
|
|
355,891
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Lease operating expenses
|
56,992
|
|
|
43,682
|
|
|
40,339
|
|
|||
Production taxes
|
18,443
|
|
|
27,194
|
|
|
25,474
|
|
|||
Transportation, gathering and processing expenses
|
10,151
|
|
|
8,128
|
|
|
10,435
|
|
|||
Exploration expense
|
1,102
|
|
|
948
|
|
|
7,071
|
|
|||
Impairment of proved crude oil and natural gas properties
|
161,620
|
|
|
167,280
|
|
|
53,827
|
|
|||
Depreciation, depletion, and amortization
|
298,760
|
|
|
201,656
|
|
|
124,202
|
|
|||
Accretion of asset retirement obligations
|
6,293
|
|
|
3,455
|
|
|
4,747
|
|
|||
(Gain) loss on sale of properties and equipment
|
(385
|
)
|
|
(75,972
|
)
|
|
3,722
|
|
|||
|
552,976
|
|
|
376,371
|
|
|
269,817
|
|
|||
Results of operations for crude oil and natural gas producing
activities before provision for income taxes |
28,920
|
|
|
428,410
|
|
|
86,074
|
|
|||
|
|
|
|
|
|
||||||
Provision for income taxes
|
(10,394
|
)
|
|
(166,930
|
)
|
|
(31,109
|
)
|
|||
|
|
|
|
|
|
||||||
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs
|
$
|
18,526
|
|
|
$
|
261,480
|
|
|
$
|
54,965
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Acquisition of properties: (1)
|
|
|
|
|
|
||||||
Proved properties
|
$
|
3,561
|
|
|
$
|
11,973
|
|
|
$
|
28,698
|
|
Unproved properties
|
15
|
|
|
45,999
|
|
|
3,390
|
|
|||
Development costs (2)
|
552,104
|
|
|
608,176
|
|
|
338,294
|
|
|||
Exploration costs: (3)
|
|
|
|
|
|
||||||
Exploratory drilling
|
—
|
|
|
—
|
|
|
58,988
|
|
|||
Geological and geophysical
|
—
|
|
|
1
|
|
|
752
|
|
|||
Total costs incurred
|
$
|
555,680
|
|
|
$
|
666,149
|
|
|
$
|
430,122
|
|
|
|
|
|
|
|
(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, 2015
,
2014
and
2013
,
$207.8 million
,
$125.2 million
and
$40.1 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,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Proved crude oil and natural gas properties
|
$
|
2,881,189
|
|
|
$
|
2,267,165
|
|
Unproved crude oil and natural gas properties
|
60,498
|
|
|
188,206
|
|
||
Uncompleted wells, equipment and facilities
|
109,385
|
|
|
164,402
|
|
||
Capitalized costs
|
3,051,072
|
|
|
2,619,773
|
|
||
Less accumulated DD&A
|
(1,131,705
|
)
|
|
(808,431
|
)
|
||
Capitalized costs, net
|
$
|
1,919,367
|
|
|
$
|
1,811,342
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Future estimated cash flows
|
$
|
6,297,298
|
|
|
$
|
12,550,515
|
|
|
$
|
11,550,917
|
|
Future estimated production costs*
|
(1,577,393
|
)
|
|
(2,816,776
|
)
|
|
(2,329,836
|
)
|
|||
Future estimated development costs
|
(1,952,332
|
)
|
|
(2,458,790
|
)
|
|
(2,778,148
|
)
|
|||
Future estimated income tax expense
|
(508,332
|
)
|
|
(2,336,510
|
)
|
|
(2,119,615
|
)
|
|||
Future net cash flows
|
2,259,241
|
|
|
4,938,439
|
|
|
4,323,318
|
|
|||
10% annual discount for estimated timing of cash flows
|
(1,162,377
|
)
|
|
(2,631,974
|
)
|
|
(2,541,155
|
)
|
|||
Standardized measure of discounted future estimated net cash flows
|
$
|
1,096,864
|
|
|
$
|
2,306,465
|
|
|
$
|
1,782,163
|
|
|
|
|
|
|
|
*
|
Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses and plugging and abandonment costs, net of salvage value.
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Sales of crude oil, natural gas and NGLs production, net of production costs
|
$
|
(293,127
|
)
|
|
$
|
(387,789
|
)
|
|
$
|
(286,021
|
)
|
Net changes in prices and production costs (1)
|
(1,752,921
|
)
|
|
129,213
|
|
|
89,527
|
|
|||
Extensions, discoveries, and improved recovery, including infill reserves in an existing proved field, less related costs (2)
|
489,178
|
|
|
1,444,581
|
|
|
1,529,006
|
|
|||
Sales of reserves (3)
|
(463
|
)
|
|
(402,595
|
)
|
|
(142,724
|
)
|
|||
Purchases of reserves (4)
|
374
|
|
|
238
|
|
|
10,610
|
|
|||
Development costs incurred during the period
|
368,840
|
|
|
161,404
|
|
|
46,366
|
|
|||
Revisions of previous quantity estimates (5)
|
(1,286,462
|
)
|
|
(654,318
|
)
|
|
(397,738
|
)
|
|||
Changes in estimated income taxes (6)
|
902,994
|
|
|
(221,874
|
)
|
|
(381,369
|
)
|
|||
Net changes in future development costs
|
112,958
|
|
|
46,499
|
|
|
(40,707
|
)
|
|||
Accretion of discount
|
345,007
|
|
|
270,389
|
|
|
142,040
|
|
|||
Timing and other
|
(95,979
|
)
|
|
138,554
|
|
|
44,676
|
|
|||
Total
|
$
|
(1,209,601
|
)
|
|
$
|
524,302
|
|
|
$
|
613,666
|
|
|
|
|
|
|
|
(1)
|
Our weighted-average price, net of production costs per Boe, in our 2015 reserve report decreased to
$17.30
as compared to
$37.78
in our 2014 reserve report. This is due to the significant decrease in SEC commodity prices utilized in the 2015 reserve report. Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to
$37.78
from
$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.
|
(2)
|
The
66%
decrease in 2015 indicates a significant decrease in the value of the extensions in 2015 as compared to the value of the extensions in 2014. This is primarily due to lower SEC commodity prices utilized in the 2015 reserve report. 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.
|
(3)
|
The decrease in sales of reserves in 2015 was due to the fact that no major divestitures were completed in 2015. 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.
|
(4)
|
The decrease in purchases of reserves in 2015 and 2014 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 2015 as compared to 2014 was primarily due to adjustments due to our drilling schedule. 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.
|
(6)
|
The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant changes in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately
38%
for each of the three years ended December 31, 2015, 2014 and 2013. 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. Further, future tax deductions for capital expenditures were not affected by the impairment of crude oil and natural gas properties in 2014 and 2015 as such impairments are not tax deductible.
|
|
2015
|
||||||||||||||||||
|
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
|
$
|
74,109
|
|
|
$
|
96,928
|
|
|
$
|
104,483
|
|
|
$
|
103,193
|
|
|
$
|
378,713
|
|
Sales from natural gas marketing
|
3,233
|
|
|
2,523
|
|
|
2,580
|
|
|
2,584
|
|
|
10,920
|
|
|||||
Commodity price risk management gain (loss), net
|
66,662
|
|
|
(49,041
|
)
|
|
123,549
|
|
|
62,013
|
|
|
203,183
|
|
|||||
Well operations, pipeline income and other
|
628
|
|
|
550
|
|
|
488
|
|
|
844
|
|
|
2,510
|
|
|||||
Total revenues
|
144,632
|
|
|
50,960
|
|
|
231,100
|
|
|
168,634
|
|
|
595,326
|
|
|||||
Costs, expenses and other:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expenses
|
16,285
|
|
|
12,639
|
|
|
13,824
|
|
|
14,244
|
|
|
56,992
|
|
|||||
Production taxes
|
3,893
|
|
|
3,837
|
|
|
5,476
|
|
|
5,237
|
|
|
18,443
|
|
|||||
Transportation, gathering and processing expenses
|
1,338
|
|
|
1,308
|
|
|
3,938
|
|
|
3,567
|
|
|
10,151
|
|
|||||
Cost of natural gas marketing
|
3,258
|
|
|
2,836
|
|
|
2,781
|
|
|
2,842
|
|
|
11,717
|
|
|||||
Exploration expense
|
285
|
|
|
275
|
|
|
252
|
|
|
290
|
|
|
1,102
|
|
|||||
Impairment of crude oil and natural gas properties
|
2,772
|
|
|
4,404
|
|
|
154,031
|
|
|
413
|
|
|
161,620
|
|
|||||
General and administrative expense
|
21,045
|
|
|
20,728
|
|
|
20,278
|
|
|
27,908
|
|
|
89,959
|
|
|||||
Depreciation, depletion and amortization
|
55,820
|
|
|
70,106
|
|
|
80,947
|
|
|
96,385
|
|
|
303,258
|
|
|||||
Accretion of asset retirement obligations
|
1,560
|
|
|
1,588
|
|
|
1,594
|
|
|
1,551
|
|
|
6,293
|
|
|||||
(Gain) loss on sale of properties and equipment
|
(21
|
)
|
|
(207
|
)
|
|
(74
|
)
|
|
(83
|
)
|
|
(385
|
)
|
|||||
Total costs, expenses and other
|
106,235
|
|
|
117,514
|
|
|
283,047
|
|
|
152,354
|
|
|
659,150
|
|
|||||
Income (loss) from operations
|
38,397
|
|
|
(66,554
|
)
|
|
(51,947
|
)
|
|
16,280
|
|
|
(63,824
|
)
|
|||||
Interest expense
|
(11,725
|
)
|
|
(11,567
|
)
|
|
(12,092
|
)
|
|
(12,187
|
)
|
|
(47,571
|
)
|
|||||
Interest income
|
1,113
|
|
|
1,135
|
|
|
1,378
|
|
|
1,181
|
|
|
4,807
|
|
|||||
Income (loss) from continuing operations before income taxes
|
27,785
|
|
|
(76,986
|
)
|
|
(62,661
|
)
|
|
5,274
|
|
|
(106,588
|
)
|
|||||
Provision for income taxes
|
(10,723
|
)
|
|
30,116
|
|
|
21,167
|
|
|
(2,252
|
)
|
|
38,308
|
|
|||||
Income (loss) from continuing operations
|
17,062
|
|
|
(46,870
|
)
|
|
(41,494
|
)
|
|
3,022
|
|
|
(68,280
|
)
|
|||||
Income (loss) from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss)
|
$
|
17,062
|
|
|
$
|
(46,870
|
)
|
|
$
|
(41,494
|
)
|
|
$
|
3,022
|
|
|
$
|
(68,280
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
0.47
|
|
|
$
|
(1.17
|
)
|
|
$
|
(1.04
|
)
|
|
$
|
0.08
|
|
|
$
|
(1.74
|
)
|
Income (loss) from discontinued operations
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss)
|
$
|
0.47
|
|
|
$
|
(1.17
|
)
|
|
$
|
(1.04
|
)
|
|
$
|
0.08
|
|
|
$
|
(1.74
|
)
|
Diluted
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
0.46
|
|
|
$
|
(1.17
|
)
|
|
$
|
(1.04
|
)
|
|
$
|
0.07
|
|
|
$
|
(1.74
|
)
|
Income (loss) from discontinued operations
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income (loss)
|
$
|
0.46
|
|
|
$
|
(1.17
|
)
|
|
$
|
(1.04
|
)
|
|
$
|
0.07
|
|
|
$
|
(1.74
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
36,349
|
|
|
40,035
|
|
|
40,085
|
|
|
40,094
|
|
|
39,153
|
|
|||||
Diluted
|
36,981
|
|
|
40,035
|
|
|
40,085
|
|
|
41,264
|
|
|
39,153
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease operating expenses
|
8,371
|
|
|
11,961
|
|
|
11,020
|
|
|
11,050
|
|
|
42,402
|
|
|||||
Production taxes
|
6,390
|
|
|
7,551
|
|
|
8,724
|
|
|
2,950
|
|
|
25,615
|
|
|||||
Transportation, gathering and processing expenses
|
1,235
|
|
|
818
|
|
|
1,208
|
|
|
1,331
|
|
|
4,592
|
|
|||||
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
|
952
|
|
|
2,019
|
|
|
1,962
|
|
|
161,914
|
|
|
166,847
|
|
|||||
General and administrative expense
|
24,529
|
|
|
41,713
|
|
|
36,328
|
|
|
20,989
|
|
|
123,559
|
|
|||||
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) attributable to shareholders
|
$
|
(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) attributable to shareholders
|
$
|
(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
|
|
|||||
|
|
|
|
|
|
|
|
|
|
Description
|
|
Beginning
Balance January 1 |
|
Charged to
Costs and Expenses |
|
Deductions (1)
|
|
Ending
Balance December 31 |
||||||||
|
|
(in thousands)
|
||||||||||||||
|
|
|
|
|
|
|
|
|
||||||||
2015:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for doubtful accounts
|
|
$
|
486
|
|
|
$
|
1,700
|
|
|
$
|
177
|
|
|
$
|
2,009
|
|
Valuation allowance for unproved crude oil and natural gas properties
|
|
9,293
|
|
|
7,012
|
|
|
16,161
|
|
|
144
|
|
||||
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
|
|
(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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.1
|
|
Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company").
|
|
8-K12B
|
|
001-37419
|
|
2.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.1
|
|
Certificate of Incorporation of the Company.
|
|
8-K12B
|
|
001-37419
|
|
3.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
By-laws of the Company.
|
|
8-K12B
|
|
001-37419
|
|
3.2
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.4
|
|
Form of Common Stock Certificate of the Company.
|
|
8-K12B
|
|
001-37419
|
|
4.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1*
|
|
Form of Indemnification Agreement.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
6/8/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.2*
|
|
401(k) and Profit Sharing Plan, as amended on January 1, 2015.
|
|
10-K
|
|
000-07246
|
|
10.2
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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*
|
|
Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.6*
|
|
Executive Severance Compensation Plan, as amended.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7*
|
|
Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.5.2
|
|
2/21/2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.1*
|
|
Form of 2013 Performance Share Agreement.
|
|
10-K
|
|
000-07246
|
|
10.9
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.2*
|
|
Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
10-K
|
|
000-07246
|
|
10.10
|
|
2/27/2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.3*
|
|
Form of 2014 Performance Share Agreement
|
|
10-K
|
|
000-07246
|
|
10.5.4*
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.4*
|
|
Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement
|
|
10-K
|
|
000-07246
|
|
10.5.5*
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.5*
|
|
Form of 2015 Performance Share Agreement
|
|
10-K
|
|
000-07246
|
|
10.5.6*
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.6*
|
|
Form of 2015 Restricted Stock Unit Agreement
|
|
10-K
|
|
000-07246
|
|
10.5.7*
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.7*
|
|
Form of 2015 Stock Appreciation Rights Agreement
|
|
10-K
|
|
000-07246
|
|
10.5.8*
|
|
2/19/2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7.8*
|
|
Form of 2016 Performance Share Agreement
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.8*
|
|
Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.2
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.9*
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.10*
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PDC ENERGY, INC.
|
|
|
|
By: /s/ Barton R. Brookman
|
|
Barton R. Brookman
|
|
President and Chief Executive Officer
|
|
|
|
February 22, 2016
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Barton R. Brookman
|
|
President, Chief Executive Officer and Director
|
|
February 22, 2016
|
Barton R. Brookman
|
|
(principal executive officer)
|
|
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
Chief Financial Officer
|
|
February 22, 2016
|
Gysle R. Shellum
|
|
(principal financial officer)
|
|
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
Chief Accounting Officer
|
|
February 22, 2016
|
R. Scott Meyers
|
|
(principal accounting officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey C. Swoveland
|
|
Chairman and Director
|
|
February 22, 2016
|
Jeffrey C. Swoveland
|
|
|
|
|
|
|
|
|
|
/s/ Joseph E. Casabona
|
|
Director
|
|
February 22, 2016
|
Joseph E. Casabona
|
|
|
|
|
|
|
|
|
|
/s/ Anthony J. Crisafio
|
|
Director
|
|
February 22, 2016
|
Anthony J. Crisafio
|
|
|
|
|
|
|
|
|
|
/s/ Larry F. Mazza
|
|
Director
|
|
February 22, 2016
|
Larry F. Mazza
|
|
|
|
|
|
|
|
|
|
/s/ David C. Parke
|
|
Director
|
|
February 22, 2016
|
David C. Parke
|
|
|
|
|
|
|
|
|
|
/s/ James M. Trimble
|
|
Director
|
|
February 22, 2016
|
James M. Trimble
|
|
|
|
|
|
|
|
|
|
/s/ Kimberly Luff Wakim
|
|
Director
|
|
February 22, 2016
|
Kimberly Luff Wakim
|
|
|
|
|
I.
|
ESTABLISHMENT, OBJECTIVES AND DURATION
|
1.
|
the “Beneficial Ownership” of securities as defined in Rule 13d-3 under the Exchange Act representing more than thirty-three percent (33%) of the combined voting power of the Company is acquired by any “person” as defined in Section 3(a)(9) of the Exchange Act (other than the Company, any trustee or other fiduciary holding securities under an employee benefit plan of the
Company, or any corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company); or
|
2.
|
the consummation of the transactions contemplated by a definitive agreement to merge or consolidate the Company with or into another corporation or to sell or otherwise dispose of all or substantially all of its assets, or the approval by the stockholders of a plan of liquidation; or
|
3.
|
during any period of three consecutive years, individuals who at the beginning of such period were members of the Board cease for any reason to constitute at least a majority thereof (unless the election, or the nomination for election by the Company's stockholders, of each new director was approved by a vote of at least a majority of the directors then still in office who were directors at the beginning of such period or whose election or nomination was previously so approved).
|
4.
|
Change in Ownership
: A change in ownership of the Company occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Company, excluding the acquisition of additional stock by a person or more than one person acting as a group who is considered to own more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Company.
|
5.
|
Change in Effective Control
: A change in effective control of the Company occurs only on either of the following dates:
|
a.
|
The date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending in the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company; or
|
b.
|
The date a majority of the members of the Board is replaced during any (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors before the date of the appointment or election; provided that this paragraph (b) shall apply only to the company for which no other corporation is a majority shareholder.
|
6.
|
Change in Ownership of Substantial Assets
: A change in the ownership of a substantial portion of the Company's assets occurs on the date that any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than ninety percent (90%) of the total gross fair market value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets.
|
1.
|
is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or
|
2.
|
is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under an accident and health plan covering Employees of the Company.
|
1.
|
STOCK OPTIONS: The maximum aggregate number of Shares that may be subject to Stock Options granted in any one fiscal year to any one Participant shall be eight hundred thousand (800,000).
|
2.
|
SARs: The maximum aggregate number of shares that may be granted in the form of SARs granted in any one fiscal year to any one Participant shall be eight hundred thousand (800,000).
|
3.
|
RESTRICTED STOCK: The maximum aggregate grant with respect to Awards of Restricted Stock which are granted in any one fiscal year to any one Participant shall be four hundred thousand (400,000) Shares.
|
4.
|
RESTRICTED STOCK UNITS: The maximum aggregate number of Shares that may be covered by grants of Restricted Stock Units in any one fiscal year to any one Participant shall be four hundred thousand (400,000) Shares; provided, however, that the maximum aggregate grant of Restricted Stock and Restricted Stock Units for any one fiscal year shall be coordinated so that in no event shall any one Participant receive Awards covering more than the four hundred thousand (400,000) Shares taking into account all such grants.
|
5.
|
PERFORMANCE SHARES: The maximum aggregate payout (determined as of the event of the applicable performance period) with respect to Awards of Performance Shares which are granted in any one fiscal year to any one Participant shall be equal to the Fair Market Value of four hundred thousand (400,000) Shares.
|
6.
|
PERFORMANCE UNITS: The maximum aggregate payout (determined as of the end of the applicable performance period) with respect to Awards of Performance Units which are granted in any one fiscal year to any one Participant shall be equal to five million dollars ($5,000,000).
|
1.
|
An Award of an Option;
|
2.
|
An Award of a SAR that may be settled in Shares;
|
3.
|
An Award of Restricted Stock;
|
4.
|
An Award of a Restricted Stock Unit that may be settled in Shares;
|
5.
|
A Performance Share Award that may be settled in Shares; and
|
6.
|
A Performance Unit Award that may be settled in Shares.
|
7.
|
A payout of a SAR or a Tandem SAR, or any other Award, in cash;
|
8.
|
A cancellation, termination, expiration, forfeiture or lapse for any reason (with the exception of the termination of a Tandem SAR upon exercise of the related Options, or the termination of a related Option upon exercise of the corresponding Tandem SAR) of any Award payable in Shares;
|
9.
|
Shares tendered in payment of the exercise price of an Option;
|
10.
|
Shares withheld for payment of federal, state or local taxes;
|
11.
|
Shares repurchased by the Company with proceeds collected in connection with the exercise of outstanding Options; and
|
12.
|
Shares withheld or retained in connection with the exercise of SARs (i.e. only the net Shares issued, as opposed to the full number of Shares underlying the exercised portion of the SAR, shall count against and reduce the number of Shares available for issuance under the Plan).
|
1.
|
INCENTIVE STOCK OPTIONS. No ISO granted under the Plan may be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. Further, all ISOs granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant or the Participant's legal representative (to the extent permitted under Code Section 422).
|
2.
|
NONQUALIFIED STOCK OPTIONS. No NQSO granted under this Article VI may be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. Further, all NQSOs granted to a
Participant under this Article VI shall be exercisable during his or her lifetime only by such Participant or the Participant's legal representative.
|
1.
|
the difference between the Fair Market Value of a Share on the date of exercise over the grant price; by
|
2.
|
the number of Shares with respect to which the SAR is exercised.
|
1.
|
AWARD DATES. Effective as of the date specified by the Committee in its sole discretion, each Non-Employee Director will be awarded such number of Shares of Restricted Stock as determined by the Board, after consideration of the recommendation of the Committee. Non-Employee Directors may, but need not, be awarded the same number of Shares of Restricted Stock. A Non-Employee Director who is first elected to the Board on a date subsequent to the date specified by the Committee in its sole discretion will be awarded such number of Shares of Restricted Stock as of such date of election as determined by the Board, after consideration of the recommendation of the Committee.
|
2.
|
DIVIDEND RIGHTS OF HOLDERS OF RESTRICTED STOCK. Notwithstanding Section VIII.F., upon issuance of a Restricted Stock Agreement, the Non-Employee Director in whose name the Restricted Stock Agreement is registered will, subject to the provisions of the Plan, have the right to receive immediately all cash dividends and other cash distributions thereon.
|
3.
|
PERIOD OF RESTRICTION. Restricted Stock will be subject to forfeiture as set forth in Section VIII.H.4. and the other provisions of the Plan during the Period of Restriction commencing on the date as of which the Restricted Stock is awarded (the “Award Date”) and ending on the earliest of the first to occur of the following:
|
a.
|
the retirement of the Non-Employee Director from the Board in compliance with the Board's retirement policy as then in effect;
|
b.
|
the termination of the Non-Employee Director's service on the Board as a result of the Non-Employee Director's not being nominated for reelection by the Board;
|
c.
|
the termination of the Non-Employee Director's service on the Board because of the Non-Employee Director's resignation or failure to stand for reelection with the consent of the Company's Board (which means approval by at least 80% of the Directors voting, with the affected Non-Employee Director abstaining);
|
d.
|
the termination of the Non-Employee Director's service on the Board because the Non-Employee Director, although nominated for reelection by the Board, is not reelected by the stockholders;
|
e.
|
the termination of the Non-Employee Director's service on the Board because of (i) the Non-Employee's Director's resignation at the request of the Nominating and Governance Committee of the Board (or successor committee), (ii) the Non-Employee Director's removal by action of the stockholders or by the Board, or (iii) a Change in Control of the Company;
|
f.
|
the termination of the Non-Employee Director's service on the Board because of Disability or death; or
|
g.
|
the vesting of the Restricted Stock.
|
4.
|
FORFEITURE OF RESTRICTED STOCK. As of the date (“Termination Date”) a Non-Employee Director ceases to be a member of the Board for any reason, including but not limited to removal or resignation for Cause, the Non-Employee Director shall forfeit to the Company all Restricted Stock awarded to the Non-Employee Director for which the Period of Restriction has not ended pursuant to Section VIII.H.3. as of or prior to the Termination Date.
|
XII.
|
BENEFICIARY DESIGNATION
|
XIII.
|
DEFERRALS
|
XIV.
|
RIGHTS OF EMPLOYEES
|
XX.
|
SUCCESSORS
|
XXI.
|
LEGAL CONSTRUCTION
|
1.
|
Distribution to Specified Employees Upon Separation from Service
. To the extent that payment under an Award which is subject to Code Section 409A is due to a Specified Employee on account of the Specified Employee's Separation from Service from the Company or its Affiliate or Subsidiary, such payment shall be delayed until the first day of the seventh (7th) month following such Separation from Service (or as soon as practicable thereafter) or such earlier time as may be permitted under Code Section 409A. The Committee, in its discretion, may provide in the Award document for the payment of interest at a rate set by the Committee for such six-month period. In the event that a payment under an Award is exempt from Code Section 409A, payment shall be made to a Specified Employee without any such six-month delay.
|
2.
|
No Acceleration of Payment
. To the extent that an Award is subject to Code Section 409A, payment under such Award shall not be accelerated from the date(s) specified in the Award documents as of the date of grant.
|
3.
|
Subsequent Delay in Payment
. To the extent that an Award is subject to Code Section 409A, payment under such Award shall not be deferred beyond the dates specified in the Award document as of the date of grant, unless the Committee or Participant, as the case may be, makes the decision to delay payment at least one year prior to the scheduled payment date, and payment is delayed at least five (5) years.
|
4.
|
No Liability
. Notwithstanding anything to the contrary in this Plan, in no event shall the Company, the Board, the Committee, or any of their respective agents, assigns, or representatives have any liability to any Plan Participant for any taxes, penalties, or interest assessed against such Participant as a result of the application of Code Section 409A to any Award made hereunder.
|
1.
|
Termination of Employment
. The Employee's employment with the Company shall terminate on __________ __, 20__ (the “Termination Date”).
|
2.
|
Severance Benefits
. Pursuant to the terms of the Plan, and in consideration of the Employee's release of claims and the other covenants and agreements contained herein and therein, and provided that the Employee has signed this Release and delivered it to the Company and has not exercised any revocation rights as provided in Section 6 below, the Company shall provide the severance benefits described in Section 5 of the Plan (the “ Benefits ”) in the time and manner provided therein; provided, however, that the Company's obligations will be excused if the Employee breaches any of the provisions of the Plan, including, without limitation, Article VIII thereof. The Employee acknowledges and agrees that the Benefits constitute consideration beyond that which, but for the mutual covenants set forth in this Release and the covenants contained in the Plan, the Company otherwise would not be obligated to provide, nor would the Employee otherwise be entitled to receive.
|
3.
|
Effective Date
. Provided that it has not been revoked pursuant to Section 6 hereof, this Release will become effective on the eighth (8th) day after the date of its execution by the Employee (the “Effective Date”).
|
4.
|
Effect of Revocation
. The Employee acknowledges and agrees that if the Employee revokes this Release pursuant to Section 6 hereof, the Employee will have no right to receive the Benefits.
|
5.
|
General Release
. In consideration of the Company's obligations, the Employee hereby releases, acquits and forever discharges the Company and each of its subsidiaries and affiliates and each of their respective officers, employees, directors, successors and assigns (collectively, the “Released Parties”) from any and all claims, actions or causes of action in any way related to his employment with the Company or the termination thereof, whether arising from tort, statute or contract, including, but not limited to, claims of defamation, claims arising under the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act of 1990, Title VII of the Civil Rights Act of 1964, as amended, the Americans with Disabilities Act, the Family and Medical Leave Act, the discrimination and wage payment laws of Colorado and any other federal, state or local statutes or ordinances of the United States, it being the Employee's intention and the intention of the Company to make this release as broad and as general as the law permits. The Employee understands that this Release does not waive any rights or claims that may arise after his execution of it and does not apply to claims arising under the terms of the Plan with respect to payments the Employee may be owed pursuant to the terms thereof.
|
6.
|
Review and Revocation Period
. The Employee acknowledges that the Company has advised the Employee that the Employee may consult with an attorney of the Employee's own choosing (and at the Employee's expense) prior to signing this Release and that the Employee has been given at least forty-five (45) days during which to consider the provisions of this Release, although the Employee may sign and return it sooner. The Employee further acknowledges that the Employee has been advised by the Company that after executing this Release, the Employee will have seven (7) days to revoke this Release, and that this Release shall not become effective or enforceable until such seven (7) day revocation period has expired. The Employee acknowledges and agrees that if the Employee wishes to revoke this Release, the Employee must do so in writing, and that such revocation must be signed by the Employee and received by [_______________] no later than 5:00 p.m. Mountain Time on the seventh (7th) day after the Employee has executed this Release.
The Employee further acknowledges and agrees that, in the event that the Employee revokes this Release, the Employee will have no right to receive any benefits hereunder, including the Benefits.
The Employee represents that the Employee has read this Release and understands its terms and enters into this Release freely, voluntarily and without coercion.
|
7.
|
Confidentiality, Non-Compete and Non-Solicitation
. The Employee reaffirms his/her commitments in Article VIII of the Plan.
|
8.
|
Cooperation in Litigation
. At the Company's reasonable request, the Employee shall use his/her good faith efforts to cooperate with the Company, its Affiliates (as defined in the Agreement), and each of its and their respective attorneys or other legal representatives (“Attorneys ”) in connection with any claim, litigation or judicial or arbitral proceeding which is material to the Company or its Affiliates and is now pending or may hereinafter be brought against the Released Parties by any third party; provided, that, the Employee's cooperation is essential to the Company's case. The Employee's duty of cooperation will include, but not be limited to: (a) meeting with the Company's and/or its Affiliates' Attorneys by telephone or in person at mutually convenient times and places in order to state truthfully the Employee's knowledge of matters at issue and recollection of events; (b) appearing at the Company's, its Affiliates' and/or their Attorneys' request (and, to the extent possible, at a time convenient to the Employee that does not conflict with the needs or requirements of the Employee's then-current employer) as a witness at depositions or trials, without necessity of a subpoena, in order to state truthfully the Employee's knowledge of matters at issue; and (c) signing at the Company's, its Affiliates' and/or their Attorneys' request, declarations or affidavits that truthfully state matters of
|
9.
|
Non-Admission of Liability
. Nothing in this Release will be construed as an admission of liability by the Employee or the Released Parties; rather, the Employee and the Released Parties are resolving all matters arising out of the employer-employee relationship between the Employee and the Company and all other relationships between the Employee and the Released Parties.
|
10.
|
Nondisparagement
. The Employee agrees not to make negative comments or otherwise disparage the Company or its officers, directors, employees, shareholders or agents, in any manner likely to be harmful to them or their business, business reputation or personal reputation. The Company agrees that the members of the Company’s Board of Directors (the “Board”) and officers of the Company as of the date hereof will not, while employed by the Company or serving as a director of the Company, as the case may be, make negative comments about the Employee or otherwise disparage the Employee in any manner that is likely to be harmful to the Employee's business or personal reputation. The foregoing shall not be violated by truthful statements in response to legal process or required governmental testimony or filings, and the foregoing limitation on the Company's directors and officers will not be violated by statements that they in good faith believe are necessary or appropriate to make in connection with performing their duties for or on behalf of the Company.
|
11.
|
Binding Effect
. This Release will be binding upon the Parties and their respective heirs, administrators, representatives, executors, successors and assigns, and will inure to the benefit of the Parties and their respective heirs, administrators, representatives, executors, successors and assigns.
|
12.
|
Governing Law
. This Release will be governed by and construed and enforced in accordance with the laws of the State of Colorado applicable to agreements negotiated, entered into and wholly to be performed therein, without regard to its conflicts of law or choice of law provisions which would result in the application of the law of any other jurisdiction.
|
13.
|
Severability
. Each of the respective rights and obligations of the Parties hereunder will be deemed independent and may be enforced independently irrespective of any of the other rights and obligations set forth herein. If any provision of this Release should be held illegal or invalid, such illegality or invalidity will not affect in any way other provisions hereof, all of which will continue, nevertheless, in full force and effect.
|
14.
|
Counterparts
. This Release may be signed in counterparts. Each counterpart will be deemed to be an original, but together all such counterparts will be deemed a single agreement.
|
15.
|
Entire Agreement; Modification
. This Release constitutes the entire understanding between the Parties with respect to the subject matter hereof and may not be modified without the express written consent of both Parties. This Release supersedes all prior written and/or oral and all contemporaneous oral agreements, understandings and negotiations regarding its subject matter. This Release may not be modified or canceled in any manner except by a writing signed by both Parties.
|
16.
|
Acceptance
. The Employee may confirm his acceptance of the terms and conditions of this Release by signing and returning two (2) original copies of this Release to [_____________________], no later than 5:00 p.m. Mountain Time forty five (45) days after the Employee's Termination Date.
|
•
|
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 (BBG)
|
•
|
Bonanza Creek Energy, Inc. (BCEI)
|
•
|
Callon Petroleum Company (CPE)
|
•
|
Carrizo Oil & Gas Inc. (CRZO)
|
•
|
Energen Corp. (EGN)
|
•
|
Gulfport Energy Corp. (GPOR)
|
•
|
Laredo Petroleum Holdings, Inc. (LPI)
|
•
|
Matador Resources Company (MTDR)
|
•
|
Oasis Petroleum Inc. (OAS)
|
•
|
Parsley Energy, Inc. (PE)
|
•
|
SM Energy Company (SM)
|
•
|
Synergy Resources Corporation (SYRG)
|
•
|
WPX Energy, Inc. (WPX)
|
|
|
|
BORROWER:
|
||
|
||
PDC ENERGY, INC.
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
||
GUARANTOR:
|
||
|
||
RILEY NATURAL GAS COMPANY
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
JPMORGAN CHASE BANK, N.A.,
as Administrative Agent, Issuing Bank and as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
Authorized Officer
|
|
|
|
BANK OF AMERICA, N.A.,
as a Lender and as a Co-Documentation Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
BANK OF MONTREAL,
as a Lender and as a Co-Documentation Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
THE ROYAL BANK OF SCOTLAND PLC,
as a Lender and as Co-Documentation Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
WELLS FARGO BANK, N.A.,
as a Lender and as Syndication Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
COMPASS BANK,
as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
CREDIT AGRICOLE CORPORATE AND
INVESTMENT BANK,
as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
By:
|
|
|
Name:
|
||
Title:
|
|
|
|
THE BANK OF NOVA SCOTIA,
as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
SCOTIABANC INC.,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
BOKF, NA,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
CAPITAL ONE, N.A.,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
COMERICA BANK,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
NATIXIS,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
TEXAS CAPITAL BANK, N.A.,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
U.S. BANK NATIONAL ASSOCIATION,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
KEYBANK NATIONAL ASSOCIATION,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
BORROWER:
|
||
|
||
PDC ENERGY, INC.
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
||
GUARANTOR:
|
||
|
||
RILEY NATURAL GAS COMPANY
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
JPMORGAN CHASE BANK, N.A.,
as Administrative Agent, Issuing Bank and as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
Authorized Officer
|
|
|
|
BANK OF AMERICA, N.A.,
as a Lender and as a Co-Documentation Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
BANK OF MONTREAL,
as a Lender and as a Co-Documentation Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
THE ROYAL BANK OF SCOTLAND PLC,
as a Lender and as Co-Documentation Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
WELLS FARGO BANK, N.A.,
as a Lender and as Syndication Agent
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
COMPASS BANK,
as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
CREDIT AGRICOLE CORPORATE AND
INVESTMENT BANK,
as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
By:
|
|
|
Name:
|
||
Title:
|
|
|
|
THE BANK OF NOVA SCOTIA,
as a Lender
|
||
|
|
|
By:
|
||
Name:
|
|
|
Title:
|
|
|
|
|
|
SCOTIABANC INC.,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
BOKF, NA,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
CAPITAL ONE, N.A.,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
COMERICA BANK,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
NATIXIS,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
TEXAS CAPITAL BANK, N.A.,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
U.S. BANK NATIONAL ASSOCIATION,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
KEYBANK NATIONAL ASSOCIATION,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
|
|
TORONTO DOMINION (TEXAS) LLC,
|
||
as a Lender
|
||
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
PDC ENERGY, INC.
|
|
||||||||||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges
|
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
|
||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
||||||||||
|
|
(dollars in thousands)
|
|
||||||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
(106,588
|
)
|
|
$
|
177,228
|
|
|
$
|
(32,963
|
)
|
|
$
|
(30,688
|
)
|
|
$
|
35,268
|
|
|
Fixed charges (see below)
|
|
55,844
|
|
|
53,512
|
|
|
54,002
|
|
|
50,228
|
|
|
40,127
|
|
|
|||||
Amortization of capitalized interest
|
|
2,486
|
|
|
1,379
|
|
|
1,096
|
|
|
871
|
|
|
675
|
|
|
|||||
Interest capitalized
|
|
(5,060
|
)
|
|
(3,468
|
)
|
|
(1,709
|
)
|
|
(896
|
)
|
|
(1,454
|
)
|
|
|||||
Total adjusted earnings (loss) available for fixed charges
|
|
$
|
(53,318
|
)
|
|
$
|
228,651
|
|
|
$
|
20,426
|
|
|
$
|
19,515
|
|
|
$
|
74,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and debt expense (a)
|
|
$
|
47,571
|
|
|
$
|
47,842
|
|
|
$
|
50,143
|
|
|
$
|
47,505
|
|
|
$
|
36,759
|
|
|
Interest capitalized
|
|
5,060
|
|
|
3,468
|
|
|
1,709
|
|
|
896
|
|
|
1,454
|
|
|
|||||
Interest component of rental expense (b)
|
|
3,213
|
|
|
2,202
|
|
|
2,150
|
|
|
1,827
|
|
|
1,914
|
|
|
|||||
Total fixed charges
|
|
$
|
55,844
|
|
|
$
|
53,512
|
|
|
$
|
54,002
|
|
|
$
|
50,228
|
|
|
$
|
40,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
(c)
|
4.3
|
x
|
|
—
|
|
(c)
|
—
|
|
(c)
|
1.9
|
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, 2015, 2013 and 2012, earnings were insufficient to cover total fixed charges by
$109.2 million
,
$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 22, 2016
|
|
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 22, 2016
|
|
/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 22, 2016
|
|
/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 22, 2016
|
Barton R. Brookman
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
February 22, 2016
|
Gysle R. Shellum
|
|
|
Chief Financial Officer
|
|
|
As of December 31, 2015
|
||||||||||||||||
|
|
Proved
|
||||||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
||||||||
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate - MBarrels
|
|
25,743.3
|
|
|
513.4
|
|
|
72,718.5
|
|
|
98,975.2
|
|
||||
Plant Products - MBarrels
|
|
14,463.6
|
|
|
547.8
|
|
|
48,715.7
|
|
|
63,727.1
|
|
||||
Gas - MMCF
|
|
168,217
|
|
|
7,150
|
|
|
485,370
|
|
|
660,737
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data (M$)
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
$
|
1,570,122
|
|
|
$
|
42,046
|
|
|
$
|
4,609,355
|
|
|
6,221,523
|
|
|
Deductions
|
|
595,046
|
|
|
53,416
|
|
|
2,805,488
|
|
|
3,453,950
|
|
||||
Future Net Income (FNI)
|
|
$
|
975,076
|
|
|
$
|
(11,370
|
)
|
|
$
|
1,803,867
|
|
|
$
|
2,767,573
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
$
|
690,969
|
|
|
$
|
16,503
|
|
|
$
|
630,000
|
|
|
$
|
1,337,472
|
|
|
|
Discounted Future Net Income - (M$)
|
||||
|
|
As of December 31, 2015
|
||||
Discount Rate Percent
|
|
|
Total Proved
|
|
||
|
|
|
|
|
||
5
|
|
|
$
|
1,878,709
|
|
|
15
|
|
|
$
|
987,727
|
|
|
20
|
|
|
$
|
750,794
|
|
|
25
|
|
|
$
|
584,072
|
|
|
Geographic
Area
|
Product
|
Price
Reference
|
Average Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$50.28/Bbl
|
$42.10/Bbl
|
NGLs
|
WTI Cushing
|
$50.28/Bbl
|
$12.23/Bbl
|
|
Gas
|
Henry Hub
|
$2.59/MMBTU
|
$2.05/MCF
|