Nevada
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95-2636730
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(State of incorporation)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $0.01 per share
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NASDAQ Global Select Market
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
£
(Do not check if a smaller reporting company)
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Smaller reporting company
o
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PART I
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Page
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PART II
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PART III
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PART IV
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•
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changes in production volumes and worldwide demand, including economic conditions that might impact demand;
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•
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volatility of commodity prices for natural gas, NGLs and crude oil;
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•
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the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;
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•
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potential declines in the values of our natural gas and crude oil properties resulting in impairments;
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•
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changes in estimates of
proved reserves
;
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•
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inaccuracy of reserve estimates and expected production rates;
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•
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potential for production decline rates from our wells to be greater than expected;
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•
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timing and extent of our success in discovering, acquiring, developing and producing reserves;
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•
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our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
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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 natural gas and crude oil wells;
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•
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our future cash flows, liquidity and financial condition;
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•
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competition in the oil and gas industry;
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•
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availability and cost of capital to us;
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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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availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production, particularly in the Wattenberg Field, and the impact of these facilities on the prices we receive for our production;
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•
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our success in marketing natural gas, NGLs and crude oil;
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•
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effect of natural gas and crude oil 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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potential obstacles to completing our pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions that may be unfavorable to us;
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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 future operations of the Company.
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Proved Reserves at December 31, 2012
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|||||||
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Proved Reserves (Bcfe)
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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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Production (MMcfe)
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|||
Western
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Wattenberg Field
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893.5
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77
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%
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41
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%
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62
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%
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33.4
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26,748
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Other
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84.6
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8
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%
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100
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%
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1
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%
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5.1
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16,672
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Total Western
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978.1
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85
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%
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46
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%
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56
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%
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22.5
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43,420
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Eastern
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Appalachian Basin
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178.8
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15
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%
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23
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%
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—
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%
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28.9
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6,192
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Total Eastern
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178.8
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15
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%
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23
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%
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—
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%
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28.9
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6,192
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Total proved reserves
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1,156.9
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|
100
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%
|
|
42
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%
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|
48
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%
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23.3
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49,612
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•
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Multi-year project inventory targeting highly economic oil and NGL production growth.
We have a significant operational presence in three key U.S. onshore basins and have identified a substantial inventory of approximately 4,100 gross capital projects across our assets. This inventory includes approximately 3,300 gross projects in the liquid-rich Wattenberg Field, of which approximately 1,400 are horizontal Niobrara and Codell proved and probable locations that we expect to be capable of providing liquid-rich production growth for the next several years at attractive rates of return based on current strip prices. Potential downspacing of future drill sites would provide the opportunity for additional locations. In the core area of the Wattenberg Field, we have achieved an average of 335 MBoe gross reserves per horizontal well, with approximately 75% liquids contribution. In the Appalachian Basin, we have approximately 600 gross Marcellus Shale drilling locations in inventory, of which approximately 360 gross wells in our core focus area would be expected to generate reserves of 5 to 7 Bcfe per well. In addition, our leasehold position in the emerging Utica Shale play is expected to provide approximately 200 horizontal drilling opportunities in liquid rich areas. With the development of the horizontal Niobrara and Codell and exploration and
delineation
of acreage in the Utica Shale, we are focused on transitioning our portfolio to a higher mix of oil and NGLs that we believe is capable of delivering higher margins and improved capital efficiencies.
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•
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Track record of reserve and production growth.
Our proved reserves have grown from 323 Bcfe at December 31, 2006 to approximately 1.2 Tcfe at December 31, 2012, representing a compound annual growth rate (“CAGR”) of 23.7%. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 52.7%. Our annual production grew from 16.9 Bcfe in 2006 to 49.6 Bcfe in 2012 from continuing operations, representing a CAGR of 19.7%.
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•
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Horizontal drilling and completion experience.
We have a proven track record of applying technical expertise toward developing
unconventional resources
through horizontal drilling, having drilled 108 Niobrara, Codell, Marcellus and Utica horizontal wells as of December 31, 2012. We have begun multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We have approximately 2,000 gross horizontal proved and probable locations in inventory from our Wattenberg and Marcellus positions. Our current leasehold position in the emerging Utica Shale play is expected to provide approximately 200 horizontal drilling opportunities in liquid-rich areas.
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•
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Significant operational control in our core areas.
As a result of successfully executing our strategy over time of acquiring largely concentrated acreage positions with a high
working interest
, we operate and manage approximately 89% of our oil and natural gas properties. 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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Access to liquidity.
As of December 31, 2012, we had $2.5 million of cash and cash equivalents and $396.1 million available for
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•
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Management experience and operational expertise.
We have a management team with a proven track record of performance and a technical and operational staff with significant expertise in the basins in which we operate, particularly with horizontal well development activities.
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•
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Natural gas
. We primarily sell our natural gas to midstream marketers, utilities, industrial end-users and other wholesale purchasers. We generally sell the natural gas that we produce under contracts with indexed or
NYMEX
monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers
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•
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NGLs
. The majority of our NGLs are sold to one NGL marketer in the Wattenberg Field. Our NGL production is sold under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price.
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•
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Crude oil
. We do not refine any of our crude oil production. We sell our crude oil to oil marketers and refiners. Our crude oil production is sold to purchasers at or near our wells under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price.
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•
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Wattenberg Field, DJ Basin, Colorado.
Currently, wells drilled in this area are horizontal wells targeting the liquid-rich reservoirs in the Codell and Niobrara formations. These horizontal wells have a vertical depth range from approximately 7,000 to 8,000 feet, with an average lateral length of 4,000 feet. We drill multi-well pads to further optimize costs and enhance horizontal drilling efficiencies in the Wattenberg Field. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We have approximately 3,300 gross projects, including over 1,400 proved and probable horizontal projects, in the liquid-rich Wattenberg Field.
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•
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Piceance Basin, Colorado.
Wells in this area predominately target natural gas from the Williams Fork formation. For 2012, we removed all PUD reserves in the Piceance Basin due to low natural gas prices. Our 2012 Piceance natural gas reserves were 66.5 Bcfe, or approximately 6% of our total proved equivalent reserves. Our Piceance reserves represent approximately 2% of our
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•
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Northeastern Colorado
.
Wells drilled in this area range from 1,500 to 3,000 feet in depth and target natural gas reserves in the shallow Niobrara reservoir. Well spacing is approximately 40 acres per well.
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•
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Utica Shale, Ohio.
We have acquired approximately 45,000 net acres targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. To date, we have drilled and completed two horizontal wells in Guernsey County that are currently waiting on first production, as well as two stratigraphic vertical test wells to collect engineering and geologic data to test the productivity of the acreage. The horizontal wells have a vertical depth range of approximately 7,000 feet, with an average lateral length of 4,000 feet.
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•
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Marcellus Shale, West Virginia.
Through our joint venture, PDCM, we have over 236,000 net acres in the Appalachian Basin, with approximately 152,000 acres prospective for the Marcellus Shale, the majority of which is in northern West Virginia. PDCM is primarily focused on horizontal drilling and has approximately 600 Marcellus Shale gross drilling locations on the West Virginia acreage. These wells have a vertical depth range from approximately 7,000 to 8,000 feet, with lateral lengths ranging from 4,000 to 6,000 feet.
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Productive Wells
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||||||||||||||||
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As of December 31, 2012
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||||||||||||||||
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Natural Gas
|
|
Crude Oil
|
|
Total
|
||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
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|
Gross
|
|
Net
|
||||||
Western
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Wattenberg Field
|
|
2,523
|
|
|
2,181.2
|
|
|
91
|
|
|
71.8
|
|
|
2,614
|
|
|
2,253.0
|
|
Other
|
|
1,057
|
|
|
800.7
|
|
|
—
|
|
|
—
|
|
|
1,057
|
|
|
800.7
|
|
Total Western
|
|
3,580
|
|
|
2,981.9
|
|
|
91
|
|
|
71.8
|
|
|
3,671
|
|
|
3,053.7
|
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
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|
||||||
Appalachian Basin
|
|
3,565
|
|
|
1,654.5
|
|
|
6
|
|
|
3.7
|
|
|
3,571
|
|
|
1,658.2
|
|
Total Eastern
|
|
3,565
|
|
|
1,654.5
|
|
|
6
|
|
|
3.7
|
|
|
3,571
|
|
|
1,658.2
|
|
Total productive wells
|
|
7,145
|
|
|
4,636.4
|
|
|
97
|
|
|
75.5
|
|
|
7,242
|
|
|
4,711.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2012 (5)
|
|
2011 (4)(5)
|
|
2010 (4)(5)
|
||||||
Proved reserves
|
|
|
|
|
|
||||||
Natural gas
(MMcf)
|
604,038
|
|
|
672,145
|
|
|
657,306
|
|
|||
Crude oil and condensate
(MBbls) (1)
|
59,310
|
|
|
37,636
|
|
|
23,236
|
|
|||
NGLs
(MBbls) (1)
|
32,827
|
|
|
19,588
|
|
|
10,649
|
|
|||
Total proved reserves
(MMcfe)
|
1,156,860
|
|
|
1,015,489
|
|
|
860,616
|
|
|||
Proved developed reserves
(MMcfe)
(2)
|
490,515
|
|
|
471,347
|
|
|
301,141
|
|
|||
Estimated future net cash flows
(in millions)
|
$
|
2,756
|
|
|
$
|
2,290
|
|
|
$
|
1,315
|
|
PV-10% (
in millions
) (3)
|
$
|
1,709
|
|
|
$
|
1,350
|
|
|
$
|
693
|
|
Standardized measure
(in millions)
|
$
|
1,168
|
|
|
$
|
941
|
|
|
$
|
488
|
|
(1)
|
Approximately 49% of the increase in crude oil and condensate and 38% of the increase in NGLs from December 31, 2011 to December 31, 2012 is due to the addition of horizontal Niobrara and Codell
proved developed
and undeveloped reserves in the Wattenberg Field.
|
(2)
|
Approximately 73% of the increase in proved developed reserves from December 31, 2010 to December 31, 2011 was due to the reclassification of our estimated Wattenberg refracture reserves from PUDs to proved developed as a result of the greater cost differential between the cost of a refracture versus the cost of drilling a new well.
|
(3)
|
PV-10% is a non-U.S. GAAP financial measure. This non-U.S. GAAP measures is not a measure of financial or operating performance under U.S. GAAP and 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.
|
(4)
|
Includes estimated reserve data related to our Permian assets, which were classified as held for sale as of December 31, 2011. On February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.
|
|
As of December 31,
|
||||||
|
2011
|
|
2010
|
||||
Proved reserves
|
|
|
|
||||
Natural gas
(MMcf)
|
6,242
|
|
|
4,979
|
|
||
Crude oil and condensate
(MBbls)
|
7,825
|
|
|
3,331
|
|
||
NGLs
(MBbls)
|
1,971
|
|
|
1,190
|
|
||
Total proved reserves
(MMcfe)
|
65,018
|
|
|
32,105
|
|
||
Proved developed reserves
(MMcfe)
|
15,940
|
|
|
11,416
|
|
||
Estimated future net cash flows
(in millions)
|
$
|
348
|
|
|
$
|
129
|
|
(5)
|
Includes estimated reserve data related to our Piceance and NECO assets, which are to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets.
|
|
As of December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Proved reserves
|
|
|
|
|
|
||||||
Natural gas
(MMcf)
|
83,656
|
|
|
354,080
|
|
|
454,886
|
|
|||
Crude oil and condensate
(MBbls)
|
148
|
|
|
441
|
|
|
548
|
|
|||
NGLs
(MBbls)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total proved reserves
(MMcfe)
|
84,544
|
|
|
356,726
|
|
|
458,174
|
|
|||
Proved developed reserves
(MMcfe)
|
84,544
|
|
|
141,802
|
|
|
142,949
|
|
|||
Estimated future net cash flows
(in millions)
|
$
|
43
|
|
|
$
|
32
|
|
|
$
|
52
|
|
|
|
As of December 31, 2012
|
|||||||||||||
Operating Region/Area
|
|
Natural Gas
(MMcf) |
|
NGLs
(MBbls)
|
|
Crude Oil and Condensate (MBbls)
|
|
Natural Gas
Equivalent (MMcfe) |
|
Percent
|
|||||
Proved developed
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
158,192
|
|
|
14,353
|
|
|
20,226
|
|
|
365,666
|
|
|
74
|
%
|
Piceance Basin
|
|
65,609
|
|
|
—
|
|
|
148
|
|
|
66,497
|
|
|
14
|
%
|
Other
|
|
18,047
|
|
|
—
|
|
|
—
|
|
|
18,047
|
|
|
4
|
%
|
Total Western
|
|
241,848
|
|
|
14,353
|
|
|
20,374
|
|
|
450,210
|
|
|
92
|
%
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
|||||
Appalachian Basin
|
|
40,077
|
|
|
—
|
|
|
38
|
|
|
40,305
|
|
|
8
|
%
|
Total Eastern
|
|
40,077
|
|
|
—
|
|
|
38
|
|
|
40,305
|
|
|
8
|
%
|
Total proved developed
|
|
281,925
|
|
|
14,353
|
|
|
20,412
|
|
|
490,515
|
|
|
100
|
%
|
Proved undeveloped
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
183,618
|
|
|
18,474
|
|
|
38,898
|
|
|
527,850
|
|
|
79
|
%
|
Total Western
|
|
183,618
|
|
|
18,474
|
|
|
38,898
|
|
|
527,850
|
|
|
79
|
%
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
|||||
Appalachian Basin
|
|
138,495
|
|
|
—
|
|
|
—
|
|
|
138,495
|
|
|
21
|
%
|
Total Eastern
|
|
138,495
|
|
|
—
|
|
|
—
|
|
|
138,495
|
|
|
21
|
%
|
Total proved undeveloped
|
|
322,113
|
|
|
18,474
|
|
|
38,898
|
|
|
666,345
|
|
|
100
|
%
|
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
341,810
|
|
|
32,827
|
|
|
59,124
|
|
|
893,516
|
|
|
77
|
%
|
Piceance Basin
|
|
65,609
|
|
|
—
|
|
|
148
|
|
|
66,497
|
|
|
6
|
%
|
Other
|
|
18,047
|
|
|
—
|
|
|
—
|
|
|
18,047
|
|
|
2
|
%
|
Total Western
|
|
425,466
|
|
|
32,827
|
|
|
59,272
|
|
|
978,060
|
|
|
85
|
%
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
|||||
Appalachian Basin
|
|
178,572
|
|
|
—
|
|
|
38
|
|
|
178,800
|
|
|
15
|
%
|
Total Eastern
|
|
178,572
|
|
|
—
|
|
|
38
|
|
|
178,800
|
|
|
15
|
%
|
Total proved reserves
|
|
604,038
|
|
|
32,827
|
|
|
59,310
|
|
|
1,156,860
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2012
|
|||||||||||||||||
|
|
Developed
|
|
Undeveloped (1)
|
|
Total
|
|||||||||||||
Operating Region/Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|||||||
Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Wattenberg Field
|
|
92,300
|
|
|
81,700
|
|
|
33,100
|
|
|
23,300
|
|
|
125,400
|
|
|
105,000
|
|
|
Piceance Basin
|
|
3,100
|
|
|
3,100
|
|
|
4,900
|
|
|
4,900
|
|
|
8,000
|
|
|
8,000
|
|
|
NECO
|
|
23,600
|
|
|
19,600
|
|
|
64,600
|
|
|
54,600
|
|
|
88,200
|
|
|
74,200
|
|
|
Other
|
|
—
|
|
|
—
|
|
|
21,800
|
|
|
17,700
|
|
|
21,800
|
|
|
17,700
|
|
|
Total Western
|
|
119,000
|
|
|
104,400
|
|
|
124,400
|
|
|
100,500
|
|
|
243,400
|
|
|
204,900
|
|
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Appalachian Basin, other
|
—
|
|
263,900
|
|
|
107,300
|
|
|
32,000
|
|
|
17,950
|
|
|
295,900
|
|
|
125,250
|
|
Utica Shale
|
|
800
|
|
|
400
|
|
|
48,200
|
|
|
45,300
|
|
|
49,000
|
|
|
45,700
|
|
|
Total Eastern
|
|
264,700
|
|
|
107,700
|
|
|
80,200
|
|
|
63,250
|
|
|
344,900
|
|
|
170,950
|
|
|
Total acreage
|
|
383,700
|
|
|
212,100
|
|
|
204,600
|
|
|
163,750
|
|
|
588,300
|
|
|
375,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
With the exception of our Eastern Operating Region properties prospective for the Utica Shale, substantially all of our undeveloped acreage is related to leaseholds that are held by production. Approximately
10%
of our undeveloped leaseholds expire during 2013, none of which is material to any one specific area.
|
|
|
Drilling Activity
|
||||||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||
Operating Region
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Western (1)
|
|
57
|
|
|
39.0
|
|
|
186
|
|
|
139.6
|
|
|
204
|
|
|
164.9
|
|
Eastern
|
|
6
|
|
|
4.0
|
|
|
9
|
|
|
5.2
|
|
|
9
|
|
|
5.2
|
|
Total wells drilled
|
|
63
|
|
|
43.0
|
|
|
195
|
|
|
144.8
|
|
|
213
|
|
|
170.1
|
|
Refractures and Recompletions (2)
|
|
85
|
|
|
79.9
|
|
|
192
|
|
|
177.6
|
|
|
46
|
|
|
33.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes drilling activity in the Permian Basin. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.
|
(2)
|
83 of the refractures and recompletions in 2012 occurred in the Wattenberg Field.
|
|
|
Net Development Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|||||||||
Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Wattenberg Field
|
|
31.3
|
|
|
7.7
|
(2)
|
|
—
|
|
|
86.5
|
|
|
13.1
|
|
|
—
|
|
|
106.9
|
|
|
26.5
|
|
|
—
|
|
Piceance Basin
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14.0
|
|
|
3.0
|
|
|
—
|
|
|
18.0
|
|
|
7.0
|
|
|
—
|
|
Permian Basin (1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14.5
|
|
|
5.5
|
|
|
2.0
|
|
|
—
|
|
|
5.0
|
|
|
—
|
|
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
Total Western
|
|
31.3
|
|
|
7.7
|
|
|
—
|
|
|
115.0
|
|
|
21.6
|
|
|
2.0
|
|
|
125.4
|
|
|
38.5
|
|
|
—
|
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Appalachian Basin
|
|
1.5
|
|
|
—
|
|
|
—
|
|
|
0.9
|
|
|
2.0
|
|
|
—
|
|
|
0.6
|
|
|
1.1
|
|
|
—
|
|
Total Eastern
|
|
1.5
|
|
|
—
|
|
|
—
|
|
|
0.9
|
|
|
2.0
|
|
|
—
|
|
|
0.6
|
|
|
1.1
|
|
|
—
|
|
Total net development wells
|
|
32.8
|
|
|
7.7
|
|
|
—
|
|
|
115.9
|
|
|
23.6
|
|
|
2.0
|
|
|
126.0
|
|
|
39.6
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.
|
(2)
|
On a gross basis, wells in-process as of December 31, 2012 consisted of 10 wells in the Wattenberg Field.
|
|
|
Net Exploratory Well Drilling Activity
|
|||||||||||||||||||||||||
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|||||||||||||||||||||
Operating Region/Area
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|
Productive
|
|
In-Process
|
|
Dry
|
|||||||||
Western
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Wattenberg Field
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Western
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
Eastern
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Appalachian Basin
|
|
—
|
|
|
1.5
|
|
|
1.0
|
|
|
—
|
|
|
2.3
|
|
|
—
|
|
|
2.8
|
|
|
0.7
|
|
|
—
|
|
Total Eastern
|
|
—
|
|
|
1.5
|
|
|
1.0
|
|
|
—
|
|
|
2.3
|
|
|
—
|
|
|
2.8
|
|
|
0.7
|
|
|
—
|
|
Total net exploratory wells
|
|
—
|
|
|
1.5
|
|
|
1.0
|
|
|
—
|
|
|
3.3
|
|
|
—
|
|
|
2.8
|
|
|
1.7
|
|
|
—
|
|
•
|
Colorado: Evans, Parachute and Wray
|
•
|
Pennsylvania: Indiana and Mahaffey
|
•
|
West Virginia: Bridgeport, Buckhannon and Glenville
|
•
|
Ohio: Marietta
|
•
|
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.
|
•
|
the economically recoverable quantities of natural gas, NGLs and crude oil 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 the future net cash flows;
|
•
|
timing of our capital expenditures; and
|
•
|
the amount of funds available for us to utilize under our revolving credit facility.
|
•
|
negotiation and execution of a merger agreement with a special committee, comprised entirely of non-employee directors, of our board of directors;
|
•
|
clearance from the SEC upon completion by each of the partnerships of their SEC proxy disclosure review process before the partnerships can request approval of the merger transactions from their non-affiliated investors; and
|
•
|
approval by the holders of a majority of the limited partnership units held by the non-affiliated investors of each respective partnership.
|
•
|
unusual or unexpected geological formations;
|
•
|
pressures;
|
•
|
fires;
|
•
|
loss of well control;
|
•
|
loss of drilling fluid circulation;
|
•
|
title problems;
|
•
|
facility or equipment malfunctions;
|
•
|
unexpected operational events;
|
•
|
shortages or delivery delays of equipment and services;
|
•
|
compliance with environmental and other governmental requirements; and
|
•
|
adverse weather conditions.
|
•
|
our proved reserves;
|
•
|
the amount of natural gas, NGLs and crude oil we are able to produce from existing wells;
|
•
|
the prices at which natural gas, NGLs and crude oil are sold;
|
•
|
the costs to produce natural gas, NGLs and crude oil; and
|
•
|
our ability to acquire, locate and produce new reserves.
|
•
|
require us to dedicate a substantial portion of our cash flows from operations to service our existing debt obligations, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
|
•
|
increase our vulnerability to economic downturns and impair our ability to withstand sustained declines in commodity prices;
|
•
|
subject us to covenants that limit our ability to fund future working capital, capital expenditures, exploration costs and other general corporate requirements;
|
•
|
prevent us from borrowing additional funds for operational or strategic purposes (including to fund future acquisitions), disposing of assets or paying cash dividends;
|
•
|
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
|
•
|
require us to devote a substantial portion of our cash flows from operations to payments on our indebtedness, thereby reducing the availability of our cash flows to fund exploration efforts, working capital, capital expenditures and other general corporate purposes; and
|
•
|
place us at a competitive disadvantage relative to our competitors that have less debt outstanding.
|
•
|
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 decrease our ability to enter into hedging transactions, and this would expose us to additional risks related to commodity price volatility; commodity price decreases would then have an immediate adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.
|
•
|
If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.
|
•
|
Our derivatives counterparties will be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us.
|
•
|
The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms.
|
•
|
the organization of our board of directors as a classified board, which allows no more than one-third of our directors to be elected each year;
|
•
|
limitations on the ability of our shareholders to call special meetings; and
|
•
|
certain antitakeover provisions of the Nevada private corporations statute.
|
|
Price Range
|
||||||
|
High
|
|
Low
|
||||
|
|
|
|
||||
January 1 - March 31, 2011
|
$
|
49.60
|
|
|
$
|
39.93
|
|
April 1 - June 30, 2011
|
48.51
|
|
|
28.67
|
|
||
July 1 - September 30, 2011
|
39.50
|
|
|
19.35
|
|
||
October 1 - December 31, 2011
|
37.77
|
|
|
15.08
|
|
||
January 1 - March 31, 2012
|
40.26
|
|
|
28.61
|
|
||
April 1 - June 30, 2012
|
37.63
|
|
|
19.33
|
|
||
July 1 - September 30, 2012
|
34.25
|
|
|
23.27
|
|
||
October 1 - December 31, 2012
|
36.55
|
|
|
25.76
|
|
Period
|
|
Total Number
of Shares Purchased (1) |
|
Average Price
Paid per Share |
|
Total Number
of Shares Purchased as Part of Publicly Announced Plans or Programs |
|
Maximum Number
of Shares that May Yet Be Purchased Under the Plans or Programs |
|||||
|
|
|
|
|
|
|
|
|
|||||
October 1 - 31, 2012
|
|
709
|
|
|
$
|
31.93
|
|
|
—
|
|
|
—
|
|
November 1 - 30, 2012
|
|
9,786
|
|
|
31.53
|
|
|
—
|
|
|
—
|
|
|
December 1 - 31, 2012
|
|
254
|
|
|
33.25
|
|
|
—
|
|
|
—
|
|
|
Total fourth quarter purchases
|
|
10,749
|
|
|
31.59
|
|
|
|
|
|
(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 December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
|
|
(in millions, except per share data and as noted)
|
||||||||||||||||||
Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas, NGLs and crude oil sales
|
|
$
|
270.3
|
|
|
$
|
276.6
|
|
|
$
|
205.0
|
|
|
$
|
171.2
|
|
|
$
|
304.9
|
|
Commodity price risk management gain (loss), net
|
|
32.3
|
|
|
46.1
|
|
|
59.9
|
|
|
(10.1
|
)
|
|
127.8
|
|
|||||
Total revenues
|
|
356.1
|
|
|
396.0
|
|
|
343.0
|
|
|
230.9
|
|
|
572.5
|
|
|||||
Income (loss) from continuing operations
|
|
(144.8
|
)
|
|
3.1
|
|
|
6.0
|
|
|
(80.1
|
)
|
|
105.8
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share from continuing operations
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
(5.23
|
)
|
|
$
|
0.13
|
|
|
$
|
0.33
|
|
|
$
|
(4.76
|
)
|
|
$
|
7.19
|
|
Diluted
|
|
(5.23
|
)
|
|
0.13
|
|
|
0.32
|
|
|
(4.76
|
)
|
|
7.13
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash from:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
174.7
|
|
|
$
|
166.8
|
|
|
$
|
151.8
|
|
|
$
|
143.9
|
|
|
$
|
139.1
|
|
Investing activities
|
|
(451.9
|
)
|
|
(456.4
|
)
|
|
(300.9
|
)
|
|
(142.3
|
)
|
|
(323.0
|
)
|
|||||
Financing activities
|
|
271.4
|
|
|
243.4
|
|
|
171.5
|
|
|
(20.6
|
)
|
|
150.1
|
|
|||||
Capital expenditures
|
|
347.7
|
|
|
334.5
|
|
|
162.7
|
|
|
143.0
|
|
|
323.2
|
|
|||||
Acquisitions of natural gas and crude oil properties
|
|
312.2
|
|
|
145.9
|
|
|
158.1
|
|
|
—
|
|
|
—
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
1,826.8
|
|
|
$
|
1,698.0
|
|
|
$
|
1,389.0
|
|
|
$
|
1,250.3
|
|
|
$
|
1,402.7
|
|
Working capital (deficit)
|
|
(31.4
|
)
|
|
(22.0
|
)
|
|
16.2
|
|
|
32.9
|
|
|
31.3
|
|
|||||
Long-term debt
|
|
676.6
|
|
|
532.2
|
|
|
295.7
|
|
|
280.7
|
|
|
394.9
|
|
|||||
Total equity
|
|
703.2
|
|
|
664.1
|
|
|
642.2
|
|
|
538.6
|
|
|
512.3
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pricing and Lifting Costs Relating to Continuing Operations (per Mcfe):
|
|
|
|
|
|
|
|
|
||||||||||||
Average sales price (excluding gains/losses on derivatives)
|
|
$
|
5.45
|
|
|
$
|
6.15
|
|
|
$
|
5.63
|
|
|
$
|
4.19
|
|
|
$
|
8.37
|
|
Average sales price (including realized gains/losses on derivatives)
|
|
6.44
|
|
|
6.53
|
|
|
6.89
|
|
|
6.77
|
|
|
8.62
|
|
|||||
Average lifting cost (1)
|
|
0.85
|
|
|
0.92
|
|
|
1.05
|
|
|
0.78
|
|
|
1.04
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production (Bcfe):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Production from continuing operations
|
|
49.6
|
|
|
45.0
|
|
|
37.0
|
|
|
41.6
|
|
|
36.9
|
|
|||||
Production from discontinued operations
|
|
0.4
|
|
|
2.5
|
|
|
1.6
|
|
|
1.7
|
|
|
1.8
|
|
|||||
Total production
|
|
50.0
|
|
|
47.5
|
|
|
38.6
|
|
|
43.3
|
|
|
38.7
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total proved reserves (Bcfe) (2)
|
|
1,156.9
|
|
|
1,015.5
|
|
|
860.6
|
|
|
717.3
|
|
|
753.1
|
|
(1)
|
Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis.
|
(2)
|
Includes total proved reserves related to our Permian Basin assets of 65.0 Bcfe and 32.1 Bcfe as of December 31, 2011 and 2010, respectively. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets.
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
|
|
Change
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
|
2012-2011
|
|
2011-2010
|
||||||||
|
(dollars in millions, except per unit data)
|
|
|
|
|
||||||||||||
Production (1)
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (MMcf)
|
32,409.8
|
|
|
30,429.7
|
|
|
26,239.1
|
|
|
6.5
|
%
|
|
16.0
|
%
|
|||
NGLs (MBbls)
|
841.3
|
|
|
719.2
|
|
|
569.6
|
|
|
17.0
|
%
|
|
26.3
|
%
|
|||
Crude oil (MBbls)
|
2,025.9
|
|
|
1,709.9
|
|
|
1,231.4
|
|
|
18.5
|
%
|
|
38.9
|
%
|
|||
Natural gas equivalent (MMcfe) (2)
|
49,612.4
|
|
|
45,004.8
|
|
|
37,044.9
|
|
|
10.2
|
%
|
|
21.5
|
%
|
|||
Average MMcfe per day
|
135.6
|
|
|
123.3
|
|
|
101.5
|
|
|
10.0
|
%
|
|
21.5
|
%
|
|||
Natural Gas, NGLs and Crude Oil Sales
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
70.8
|
|
|
$
|
99.6
|
|
|
$
|
94.6
|
|
|
(28.9
|
)%
|
|
5.3
|
%
|
NGLs
|
23.0
|
|
|
27.2
|
|
|
22.6
|
|
|
(15.4
|
)%
|
|
20.4
|
%
|
|||
Crude oil
|
176.5
|
|
|
149.8
|
|
|
91.1
|
|
|
17.8
|
%
|
|
64.4
|
%
|
|||
Provision for underpayment of natural gas sales
|
—
|
|
|
—
|
|
|
(3.3
|
)
|
|
—
|
%
|
|
(100.0
|
)%
|
|||
Total natural gas, NGLs and crude oil sales
|
$
|
270.3
|
|
|
$
|
276.6
|
|
|
$
|
205.0
|
|
|
(2.3
|
)%
|
|
34.9
|
%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Realized Gain (Losses) on Derivatives, net (3)
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
49.9
|
|
|
$
|
29.1
|
|
|
$
|
40.0
|
|
|
71.5
|
%
|
|
(27.3
|
)%
|
Crude oil
|
(0.5
|
)
|
|
(11.9
|
)
|
|
7.1
|
|
|
(95.8
|
)%
|
|
(267.6
|
)%
|
|||
Total realized gain on derivatives, net
|
$
|
49.4
|
|
|
$
|
17.2
|
|
|
$
|
47.1
|
|
|
187.2
|
%
|
|
(63.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price (excluding gain/loss on derivatives)
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
$
|
2.18
|
|
|
$
|
3.27
|
|
|
$
|
3.61
|
|
|
(33.3
|
)%
|
|
(9.4
|
)%
|
NGLs (per Bbl)
|
27.36
|
|
|
37.82
|
|
|
39.66
|
|
|
(27.7
|
)%
|
|
(4.6
|
)%
|
|||
Crude oil (per Bbl)
|
87.14
|
|
|
87.63
|
|
|
73.96
|
|
|
(0.6
|
)%
|
|
18.5
|
%
|
|||
Natural gas equivalent (per Mcfe)
|
5.45
|
|
|
6.15
|
|
|
5.63
|
|
|
(11.4
|
)%
|
|
9.2
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Sales Price (including realized gain/loss on derivatives)
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
$
|
3.72
|
|
|
$
|
4.23
|
|
|
$
|
5.13
|
|
|
(12.1
|
)%
|
|
(17.5
|
)%
|
NGLs (per Bbl)
|
27.36
|
|
|
37.82
|
|
|
39.66
|
|
|
(27.7
|
)%
|
|
(4.6
|
)%
|
|||
Crude oil (per Bbl)
|
86.87
|
|
|
80.69
|
|
|
79.70
|
|
|
7.7
|
%
|
|
1.2
|
%
|
|||
Natural gas equivalent (per Mcfe)
|
6.44
|
|
|
6.53
|
|
|
6.89
|
|
|
(1.4
|
)%
|
|
(5.2
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Average Lifting Cost (per Mcfe) (4)
|
|
|
|
|
|
|
|
|
|
||||||||
Western operating region
|
$
|
0.77
|
|
|
$
|
0.87
|
|
|
$
|
1.01
|
|
|
(11.5
|
)%
|
|
(13.9
|
)%
|
Eastern operating region
|
1.38
|
|
|
1.33
|
|
|
1.55
|
|
|
3.8
|
%
|
|
(14.2
|
)%
|
|||
Weighted-average
|
0.85
|
|
|
0.92
|
|
|
1.05
|
|
|
(7.6
|
)%
|
|
(12.4
|
)%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Natural Gas Marketing Contribution Margin (5)
|
$
|
0.5
|
|
|
$
|
0.9
|
|
|
$
|
1.1
|
|
|
(44.4
|
)%
|
|
(18.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
||||||||
Other Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||||
Exploration expense
|
$
|
22.6
|
|
|
$
|
6.3
|
|
|
$
|
13.7
|
|
|
261.5
|
%
|
|
(54.3
|
)%
|
Impairment of natural gas and crude oil properties
|
168.1
|
|
|
25.2
|
|
|
6.5
|
|
|
*
|
|
|
288.2
|
%
|
|||
General and administrative expense
|
58.8
|
|
|
61.5
|
|
|
42.2
|
|
|
(4.3
|
)%
|
|
45.7
|
%
|
|||
Depreciation, depletion, and amortization
|
146.9
|
|
|
128.9
|
|
|
108.1
|
|
|
13.9
|
%
|
|
19.3
|
%
|
|||
|
|
|
|
|
|
|
|
|
|
||||||||
Loss on extinguishment of debt
|
$
|
23.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
100.0
|
%
|
|
—
|
%
|
Interest Expense
|
$
|
48.3
|
|
|
$
|
37.0
|
|
|
$
|
33.3
|
|
|
30.6
|
%
|
|
11.2
|
%
|
*
|
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 included in this report.
|
(2)
|
Six Mcf of natural gas equals one Bbl of crude oil or NGL.
|
(3)
|
Represents realized derivative gains and losses related to natural gas, NGLs and crude oil sales, which do not include realized derivative gains and losses 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 realized and unrealized derivative gains and losses related to natural gas marketing activities.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
|
|
|
|
|
|
Change
|
|||||||
Production by Operating Region
|
|
2012
|
|
2011
|
|
2010
|
|
2012-2011
|
|
2011-2010
|
|||||
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
9,845.2
|
|
|
8,980.2
|
|
|
7,229.7
|
|
|
9.6
|
%
|
|
24.2
|
%
|
Piceance Basin (1)
|
|
13,226.9
|
|
|
13,350.0
|
|
|
12,001.5
|
|
|
(0.9
|
)%
|
|
11.2
|
%
|
NECO, other (1)
|
|
3,194.3
|
|
|
3,709.6
|
|
|
4,481.9
|
|
|
(13.9
|
)%
|
|
(17.2
|
)%
|
Total Western
|
|
26,266.4
|
|
|
26,039.8
|
|
|
23,713.1
|
|
|
0.9
|
%
|
|
9.8
|
%
|
Eastern
|
|
6,143.4
|
|
|
4,389.9
|
|
|
2,526.0
|
|
|
39.9
|
%
|
|
73.8
|
%
|
Total
|
|
32,409.8
|
|
|
30,429.7
|
|
|
26,239.1
|
|
|
6.5
|
%
|
|
16.0
|
%
|
Crude oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
1,979.7
|
|
|
1,670.9
|
|
|
1,190.3
|
|
|
18.5
|
%
|
|
40.4
|
%
|
Piceance Basin (1)
|
|
37.7
|
|
|
33.2
|
|
|
33.1
|
|
|
13.6
|
%
|
|
0.3
|
%
|
NECO, other (1)
|
|
0.4
|
|
|
1.0
|
|
|
2.1
|
|
|
(60.0
|
)%
|
|
(52.4
|
)%
|
Total Western
|
|
2,017.8
|
|
|
1,705.1
|
|
|
1,225.5
|
|
|
18.3
|
%
|
|
39.1
|
%
|
Eastern
|
|
8.1
|
|
|
4.8
|
|
|
5.9
|
|
|
68.8
|
%
|
|
(18.6
|
)%
|
Total
|
|
2,025.9
|
|
|
1,709.9
|
|
|
1,231.4
|
|
|
18.5
|
%
|
|
38.9
|
%
|
NGLs (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
837.3
|
|
|
712.1
|
|
|
561.1
|
|
|
17.6
|
%
|
|
26.9
|
%
|
NECO, other (1)
|
|
4.0
|
|
|
7.1
|
|
|
8.5
|
|
|
(43.7
|
)%
|
|
(16.5
|
)%
|
Total
|
|
841.3
|
|
|
719.2
|
|
|
569.6
|
|
|
17.0
|
%
|
|
26.3
|
%
|
Natural gas equivalent (MMcfe)
|
|
|
|
|
|
|
|
|
|
|
|||||
Western
|
|
|
|
|
|
|
|
|
|
|
|||||
Wattenberg Field
|
|
26,747.0
|
|
|
23,278.4
|
|
|
17,738.4
|
|
|
14.9
|
%
|
|
31.2
|
%
|
Piceance Basin (1)
|
|
13,453.1
|
|
|
13,549.3
|
|
|
12,199.9
|
|
|
(0.7
|
)%
|
|
11.1
|
%
|
NECO, other (1)
|
|
3,220.1
|
|
|
3,758.2
|
|
|
4,545.2
|
|
|
(14.3
|
)%
|
|
(17.3
|
)%
|
Total Western
|
|
43,420.2
|
|
|
40,585.9
|
|
|
34,483.5
|
|
|
7.0
|
%
|
|
17.7
|
%
|
Eastern
|
|
6,192.2
|
|
|
4,418.9
|
|
|
2,561.4
|
|
|
40.1
|
%
|
|
72.5
|
%
|
Total
|
|
49,612.4
|
|
|
45,004.8
|
|
|
37,044.9
|
|
|
10.2
|
%
|
|
21.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
On February 4, 2013, we entered into a purchase and sale agreement pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture.
|
|
|
Year Ended December 31,
|
||||||||||||||||
Average Sales Price by Operating Region
|
|
|
|
|
|
|
|
Change
|
||||||||||
(excluding gain/loss on derivatives)
|
|
2012
|
|
2011
|
|
2010
|
|
2012-2011
|
|
2011-2010
|
||||||||
Natural gas (per Mcf)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Western
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
$
|
2.61
|
|
|
$
|
3.52
|
|
|
$
|
3.70
|
|
|
(25.9
|
)%
|
|
(4.9
|
)%
|
Piceance Basin (1)
|
|
1.67
|
|
|
2.82
|
|
|
3.38
|
|
|
(40.8
|
)%
|
|
(16.6
|
)%
|
|||
NECO, other (1)
|
|
2.08
|
|
|
3.26
|
|
|
3.60
|
|
|
(36.2
|
)%
|
|
(9.4
|
)%
|
|||
Western
|
|
2.07
|
|
|
3.12
|
|
|
3.52
|
|
|
(33.7
|
)%
|
|
(11.4
|
)%
|
|||
Eastern
|
|
2.66
|
|
|
4.15
|
|
|
4.44
|
|
|
(35.9
|
)%
|
|
(6.5
|
)%
|
|||
Weighted-average price
|
|
2.18
|
|
|
3.27
|
|
|
3.61
|
|
|
(33.3
|
)%
|
|
(9.4
|
)%
|
|||
Crude oil (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Western
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
87.27
|
|
|
87.93
|
|
|
74.46
|
|
|
(0.8
|
)%
|
|
18.1
|
%
|
|||
Piceance Basin (1)
|
|
80.20
|
|
|
78.50
|
|
|
56.60
|
|
|
2.2
|
%
|
|
38.7
|
%
|
|||
NECO, other (1)
|
|
83.80
|
|
|
(95.33
|
)
|
|
40.23
|
|
|
(187.9
|
)%
|
|
(337.0
|
)%
|
|||
Western
|
|
87.14
|
|
|
87.63
|
|
|
73.95
|
|
|
(0.6
|
)%
|
|
18.5
|
%
|
|||
Eastern
|
|
86.43
|
|
|
87.09
|
|
|
77.10
|
|
|
(0.8
|
)%
|
|
13.0
|
%
|
|||
Weighted-average price
|
|
87.14
|
|
|
87.63
|
|
|
73.96
|
|
|
(0.6
|
)%
|
|
18.5
|
%
|
|||
NGLs (per Bbl)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Western
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
27.33
|
|
|
37.62
|
|
|
39.56
|
|
|
(27.4
|
)%
|
|
(4.9
|
)%
|
|||
NECO, other (1)
|
|
32.80
|
|
|
58.07
|
|
|
46.29
|
|
|
(43.5
|
)%
|
|
25.4
|
%
|
|||
Weighted-average price
|
|
27.36
|
|
|
37.82
|
|
|
39.66
|
|
|
(27.7
|
)%
|
|
(4.6
|
)%
|
|||
Natural gas equivalent (per Mcfe)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Western
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg Field
|
|
8.27
|
|
|
8.82
|
|
|
7.81
|
|
|
(6.2
|
)%
|
|
12.9
|
%
|
|||
Piceance Basin (1)
|
|
1.87
|
|
|
2.97
|
|
|
3.40
|
|
|
(37.0
|
)%
|
|
(12.6
|
)%
|
|||
NECO, other (1)
|
|
2.12
|
|
|
3.30
|
|
|
3.65
|
|
|
(35.8
|
)%
|
|
(9.6
|
)%
|
|||
Western
|
|
5.83
|
|
|
6.35
|
|
|
5.71
|
|
|
(8.2
|
)%
|
|
11.2
|
%
|
|||
Eastern
|
|
2.76
|
|
|
4.22
|
|
|
4.55
|
|
|
(34.6
|
)%
|
|
(7.3
|
)%
|
|||
Weighted-average price
|
|
5.45
|
|
|
6.15
|
|
|
5.63
|
|
|
(11.4
|
)%
|
|
9.2
|
%
|
|
Year Ended December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in millions)
|
||||||
Increase in production
|
$
|
38.8
|
|
|
$
|
56.4
|
|
Decrease in average natural gas price
|
(35.3
|
)
|
|
(10.2
|
)
|
||
Decrease in average NGL price
|
(8.8
|
)
|
|
(1.3
|
)
|
||
Increase (decrease) in average crude oil price
|
(1.0
|
)
|
|
23.4
|
|
||
Decrease in provision for underpayment of natural gas sales
|
—
|
|
|
3.3
|
|
||
Total increase (decrease) in natural gas, NGLs and crude oil sales revenue
|
$
|
(6.3
|
)
|
|
$
|
71.6
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in millions)
|
||||||||||
|
|
|
|
|
|
||||||
Lease operating expenses (1)
|
$
|
42.2
|
|
|
$
|
41.3
|
|
|
$
|
38.9
|
|
Production taxes
|
16.1
|
|
|
17.5
|
|
|
11.7
|
|
|||
Cost of well operations, overhead and other production expenses
|
17.2
|
|
|
8.6
|
|
|
13.0
|
|
|||
Total production costs
|
$
|
75.5
|
|
|
$
|
67.4
|
|
|
$
|
63.6
|
|
Total production costs per Mcfe
|
$
|
1.52
|
|
|
$
|
1.50
|
|
|
$
|
1.72
|
|
|
|
|
|
|
|
(1)
|
Prior to 2012, accretion of asset retirement obligations was included in lease operating expenses. In 2012, accretion of asset retirement obligations was reclassified as its own line item in the statement of operations. The amounts reclassified from lease operating expenses for 2011 and 2010 were $1.7 million and $1.3 million, respectively.
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in millions)
|
||||||||||
Commodity price risk management gain (loss), net:
|
|
|
|
|
|
||||||
Realized gains (losses):
|
|
|
|
|
|
||||||
Natural gas
|
$
|
49.9
|
|
|
$
|
29.1
|
|
|
$
|
40.0
|
|
Crude oil
|
(0.5
|
)
|
|
(11.9
|
)
|
|
7.1
|
|
|||
Total realized gains, net
|
49.4
|
|
|
17.2
|
|
|
47.1
|
|
|||
Unrealized gains (losses):
|
|
|
|
|
|
||||||
Reclassification of realized gains included in prior periods unrealized
|
(28.8
|
)
|
|
(10.3
|
)
|
|
(20.1
|
)
|
|||
Unrealized gains for the period
|
11.7
|
|
|
39.2
|
|
|
32.9
|
|
|||
Total unrealized gains (losses), net
|
(17.1
|
)
|
|
28.9
|
|
|
12.8
|
|
|||
Total commodity price risk management gain, net
|
$
|
32.3
|
|
|
$
|
46.1
|
|
|
$
|
59.9
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in millions)
|
||||||||||
Natural gas sales revenue
|
$
|
46.6
|
|
|
$
|
63.6
|
|
|
$
|
63.3
|
|
Realized derivative gains, net
|
2.2
|
|
|
3.0
|
|
|
6.4
|
|
|||
Unrealized derivative losses, net
|
(1.7
|
)
|
|
(0.2
|
)
|
|
(0.6
|
)
|
|||
Total sales from natural gas marketing
|
47.1
|
|
|
66.4
|
|
|
69.1
|
|
|||
|
|
|
|
|
|
||||||
Costs of natural gas purchases
|
44.8
|
|
|
61.6
|
|
|
61.4
|
|
|||
Realized derivative losses, net
|
2.0
|
|
|
2.6
|
|
|
5.9
|
|
|||
Unrealized derivative losses (gains), net
|
(1.6
|
)
|
|
0.1
|
|
|
(0.5
|
)
|
|||
Other
|
1.4
|
|
|
1.2
|
|
|
1.2
|
|
|||
Total costs of natural gas marketing
|
46.6
|
|
|
65.5
|
|
|
68.0
|
|
|||
|
|
|
|
|
|
||||||
Natural gas marketing contribution margin
|
$
|
0.5
|
|
|
$
|
0.9
|
|
|
$
|
1.1
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(in millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Exploratory dry hole costs
|
|
$
|
15.3
|
|
|
$
|
0.2
|
|
|
$
|
4.2
|
|
Geological and geophysical costs
|
|
1.9
|
|
|
1.8
|
|
|
2.3
|
|
|||
Operating, personnel and other
|
|
5.4
|
|
|
4.3
|
|
|
7.2
|
|
|||
Total exploration expense
|
|
$
|
22.6
|
|
|
$
|
6.3
|
|
|
$
|
13.7
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(in millions)
|
||||||||||
|
|
|
|
|
|
|
||||||
Impairment of proved properties
|
|
$
|
161.2
|
|
|
$
|
22.5
|
|
|
$
|
—
|
|
Impairment of individually significant unproved properties
|
|
1.9
|
|
|
1.1
|
|
|
1.5
|
|
|||
Amortization of individually insignificant unproved properties
|
|
5.0
|
|
|
1.6
|
|
|
5.0
|
|
|||
Total impairment of natural gas and crude oil properties
|
|
$
|
168.1
|
|
|
$
|
25.2
|
|
|
$
|
6.5
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
Operating Region/Area
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(per Mcfe)
|
||||||||||
Western
|
|
|
|
|
|
|
||||||
Wattenberg Field
|
|
$
|
3.07
|
|
|
$
|
3.21
|
|
|
$
|
3.08
|
|
Piceance Basin
|
|
3.12
|
|
|
2.53
|
|
|
2.49
|
|
|||
Weighted-average Western
|
|
2.94
|
|
|
2.80
|
|
|
2.72
|
|
|||
Eastern
|
|
1.93
|
|
|
2.00
|
|
|
2.57
|
|
|||
Total weighted-average
|
|
2.81
|
|
|
2.72
|
|
|
2.71
|
|
|
|
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 sheets (1)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt (2)
|
|
$
|
690.3
|
|
|
$
|
—
|
|
|
$
|
75.3
|
|
|
$
|
115.0
|
|
|
$
|
500.0
|
|
Derivative contracts (3)
|
|
28.6
|
|
|
18.5
|
|
|
6.2
|
|
|
3.9
|
|
|
—
|
|
|||||
Derivative contracts - affiliated partnerships (4)
|
|
4.7
|
|
|
4.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Production tax liability
|
|
44.6
|
|
|
25.9
|
|
|
18.7
|
|
|
—
|
|
|
—
|
|
|||||
Asset retirement obligations
|
|
62.6
|
|
|
1.0
|
|
|
2.5
|
|
|
2.5
|
|
|
56.6
|
|
|||||
Other liabilities (5)
|
|
4.9
|
|
|
0.3
|
|
|
0.9
|
|
|
0.6
|
|
|
3.1
|
|
|||||
|
|
835.7
|
|
|
50.4
|
|
|
103.6
|
|
|
122.0
|
|
|
559.7
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commitments, contingencies and other arrangements (6)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest on long-term debt (7)
|
|
403.1
|
|
|
47.0
|
|
|
91.5
|
|
|
78.9
|
|
|
185.7
|
|
|||||
Operating leases
|
|
8.5
|
|
|
2.6
|
|
|
4.3
|
|
|
0.7
|
|
|
0.9
|
|
|||||
Drilling commitment
|
|
0.9
|
|
|
—
|
|
|
—
|
|
|
0.9
|
|
|
—
|
|
|||||
Firm transportation and processing agreements (8)
|
|
199.3
|
|
|
25.8
|
|
|
55.4
|
|
|
44.9
|
|
|
73.2
|
|
|||||
Other
|
|
0.4
|
|
|
0.1
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|||||
|
|
612.2
|
|
|
75.5
|
|
|
151.5
|
|
|
125.4
|
|
|
259.8
|
|
|||||
Total
|
|
$
|
1,447.9
|
|
|
$
|
125.9
|
|
|
$
|
255.1
|
|
|
$
|
247.4
|
|
|
$
|
819.5
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Table does not include deferred income tax liability to taxing authorities of
$148.4 million
, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
(2)
|
Amount presented does not agree with the balance sheet in that it excludes
$13.7 million
in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report.
|
(3)
|
Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner. We have a related receivable from the partnerships of
$2.1 million
.
|
(4)
|
Represents our affiliated partnerships' designated portion of the fair value of our gross derivative assets.
|
(5)
|
Includes funds held from revenue distribution to third-party investors, including our affiliated partnerships, for plugging liabilities related to wells we operate and deferred officer compensation.
|
(6)
|
Table does not include an undrawn $18.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 11, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report.
|
(7)
|
Amounts presented include $12.6 million payable to the holders of our 3.25% convertible senior notes due 2016 and $379.4 million to the holders of our 2022 Senior Notes. Amounts also include $11.1 million payable to the participating banks of our revolving credit facilities, of which interest of $5.6 million is related to unutilized commitments at a rate of 0.5% per annum, $5.3 million related to the outstanding borrowings on our revolving credit facilities of
$75.3 million
and $0.2 million related to our undrawn letters of credit.
|
(8)
|
Represents our gross commitment, including our proportionate share of PDCM. We will recognize in our financial statements our proportionate share based on our working interest; however, with the exception of contracts entered into by PDCM, the costs of all volume shortfalls will be borne by PDC only. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included elsewhere in this report.
|
•
|
our operating performance and return on capital as compared to our peers;
|
•
|
the financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis;
|
•
|
our ability to generate sufficient cash to service our debt obligations; and
|
•
|
the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in millions)
|
||||||||||
Adjusted cash flows from operations:
|
|
|
|
|
|
||||||
Adjusted cash flows from operations
|
$
|
163.9
|
|
|
$
|
167.7
|
|
|
$
|
132.2
|
|
Changes in assets and liabilities
|
10.8
|
|
|
(0.9
|
)
|
|
19.6
|
|
|||
Net cash from operating activities
|
$
|
174.7
|
|
|
$
|
166.8
|
|
|
$
|
151.8
|
|
|
|
|
|
|
|
||||||
Adjusted net income (loss) attributable to shareholders:
|
|
|
|
|
|
||||||
Adjusted net income (loss) attributable to shareholders
|
$
|
(120.1
|
)
|
|
$
|
(4.3
|
)
|
|
$
|
0.4
|
|
Unrealized gain (loss) on derivatives, net
|
(17.1
|
)
|
|
28.6
|
|
|
12.6
|
|
|||
Provision for underpayment of natural gas sales
|
—
|
|
|
—
|
|
|
(3.3
|
)
|
|||
Tax effect of above adjustments
|
6.5
|
|
|
(10.9
|
)
|
|
(3.5
|
)
|
|||
Net income (loss) attributable to shareholders
|
$
|
(130.7
|
)
|
|
$
|
13.4
|
|
|
$
|
6.2
|
|
|
|
|
|
|
|
||||||
Adjusted EBITDA to net income (loss) attributable to shareholders:
|
|
|
|
|
|
||||||
Adjusted EBITDA
|
$
|
196.9
|
|
|
$
|
190.2
|
|
|
$
|
150.8
|
|
Unrealized gain (loss) on derivatives, net
|
(17.1
|
)
|
|
28.6
|
|
|
12.6
|
|
|||
Interest expense, net
|
(48.3
|
)
|
|
(36.9
|
)
|
|
(33.2
|
)
|
|||
Income tax provision
|
80.2
|
|
|
(6.2
|
)
|
|
(0.4
|
)
|
|||
Impairment of natural gas and crude oil properties
|
(168.2
|
)
|
|
(25.2
|
)
|
|
(11.1
|
)
|
|||
Depreciation, depletion and amortization
|
(146.9
|
)
|
|
(135.2
|
)
|
|
(111.1
|
)
|
|||
Accretion of asset retirement obligations
|
(4.0
|
)
|
|
(1.9
|
)
|
|
(1.4
|
)
|
|||
Loss on extinguishment of debt
|
(23.3
|
)
|
|
—
|
|
|
—
|
|
|||
Net income (loss) attributable to shareholders
|
$
|
(130.7
|
)
|
|
$
|
13.4
|
|
|
$
|
6.2
|
|
|
|
|
|
|
|
||||||
Adjusted EBITDA to net cash from operating activities:
|
|
|
|
|
|
||||||
Adjusted EBITDA
|
$
|
196.9
|
|
|
$
|
190.2
|
|
|
$
|
150.8
|
|
Interest expense, net
|
(48.3
|
)
|
|
(36.9
|
)
|
|
(33.2
|
)
|
|||
Exploratory dry hole costs
|
15.3
|
|
|
0.2
|
|
|
4.2
|
|
|||
Stock-based compensation
|
8.5
|
|
|
7.4
|
|
|
5.0
|
|
|||
Amortization of debt discount and issuance costs
|
7.9
|
|
|
6.3
|
|
|
4.6
|
|
|||
(Gain) loss from sale of properties and equipment
|
(24.3
|
)
|
|
(4.3
|
)
|
|
0.3
|
|
|||
Other
|
7.9
|
|
|
4.8
|
|
|
0.5
|
|
|||
Changes in assets and liabilities
|
10.8
|
|
|
(0.9
|
)
|
|
19.6
|
|
|||
Net cash from operating activities
|
$
|
174.7
|
|
|
$
|
166.8
|
|
|
$
|
151.8
|
|
|
|
|
|
|
|
||||||
PV-10%:
|
|
|
|
|
|
||||||
PV-10%
|
$
|
1,708.9
|
|
|
$
|
1,350.3
|
|
|
$
|
693.1
|
|
Present value of estimated future income tax discounted at 10%
|
(540.4
|
)
|
|
(409.1
|
)
|
|
(204.7
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,168.5
|
|
|
$
|
941.2
|
|
|
$
|
488.4
|
|
(1)
|
A standard unit of measurement for natural gas (one BBtu
equals one MMcf).
|
(2)
|
Approximately 29.4% of the fair value of our derivative assets and 8% of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report.
|
(3)
|
Pursuant to a purchase and sale agreement entered into on February 4, 2013, approximately 36,546 BBtu of natural gas hedging positions will be assumed by certain affiliates of Caerus Oil and Gas LLC upon the closing of the planned sale. There can be no assurance we will be successful in closing such divestiture. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture of certain of our natural gas properties.
|
|
Year Ended December 31,
|
||||||
|
2012
|
|
2011
|
||||
Average Index Closing Price:
|
|
|
|
||||
Natural Gas (per MMBtu)
|
|
|
|
||||
CIG
|
$
|
2.58
|
|
|
$
|
3.79
|
|
NYMEX
|
2.79
|
|
|
4.04
|
|
||
Crude Oil (per Bbl)
|
|
|
|
||||
NYMEX
|
$
|
94.92
|
|
|
$
|
94.01
|
|
|
|
|
|
||||
Average Sales Price Realized:
|
|
|
|
||||
Excluding realized derivative gains/(losses)
|
|
|
|
||||
Natural Gas (per Mcf)
|
$
|
2.18
|
|
|
$
|
3.27
|
|
Crude Oil (per Bbl)
|
87.14
|
|
|
87.63
|
|
||
Including realized derivative gains/(losses)
|
|
|
|
||||
Natural Gas (per Mcf)
|
$
|
3.72
|
|
|
$
|
4.23
|
|
Crude Oil (per Bbl)
|
86.87
|
|
|
80.69
|
|
(a)
|
(1
|
)
|
Financial Statements:
|
|
|
See Index to Financial Statements and Schedules on page F-1.
|
|
|
(2
|
)
|
Financial Statement Schedule:
|
|
|
See Index to Financial Statements and Schedule on page F-1.
|
|
|
|
Schedules and Financial Statements Omitted
|
|
|
|
All other financial statement schedules are omitted because they are not required, inapplicable or the information is included in the Financial Statements or Notes thereto.
|
|
|
(3
|
)
|
Exhibits:
|
|
|
See Exhibits Index on the following page.
|
|
|
|
|
Incorporated by Reference
|
|
|
||||||
Exhibit
|
|
|
|
|
|
SEC File
|
|
|
|
|
|
Filed
|
Number
|
|
Exhibit Description
|
|
Form
|
|
Number
|
|
Exhibit
|
|
Filing Date
|
|
Herewith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.1
|
|
Third Amended and Restated Articles of Incorporation of PDC Energy, Inc. (the "Company")
|
|
10-Q
|
|
000-07246
|
|
3.1
|
|
8/2/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
By-laws of the Company.
|
|
10-Q
|
|
000-07246
|
|
3.2
|
|
8/2/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.1
|
|
Rights Agreement by and between the Company and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
9/17/2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.2
|
|
Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon, including the form of 3.25% Convertible Senior Note due 2016.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
11/24/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022.
|
|
8-K
|
|
000-07246
|
|
4.1
|
|
10/3/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1*
|
|
Indemnification Agreement with Non-Employee Directors.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
6/13/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.2*
|
|
The Company 401(k) & Profit Sharing Plan.
|
|
10-K
|
|
000-07246
|
|
10.6
|
|
2/24/2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.3*
|
|
Non-Employee Director Deferred Compensation Plan.
|
|
S-8
|
|
333-118222
|
|
99.1
|
|
8/13/2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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*
|
|
Form of SAR Agreement under the 2004 Plan.
|
|
10-K
|
|
000-07246
|
|
10.26
|
|
2/27/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.4.2*
|
|
Form of Restricted Stock Agreement under the 2004 Plan.
|
|
10-K
|
|
000-07246
|
|
10.26
|
|
2/27/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5*
|
|
2010 Long-Term Equity Compensation Plan, dated as of April 11, 2010 ("2010 Plan").
|
|
S-8
|
|
333-167945
|
|
99.1
|
|
7/1/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5.1*
|
|
Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2010 Plan.
|
|
8-K
|
|
000-07246
|
|
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.6*
|
|
Form of 2010 Performance Share Agreement.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
3/17/2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7*
|
|
Form of 2012 Performance Share Agreement.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
1/20/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.8*
|
|
Executive severance compensation plan.
|
|
8-K
|
|
000-07246
|
|
10.2
|
|
9/25/2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.9*
|
|
Form of 2013 Performance Share Agreement.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.10*
|
|
Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement.
|
|
|
|
|
|
|
|
|
|
X
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11*
|
|
Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.2
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.12*
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.13*
|
|
Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.4
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.14*
|
|
Employment Agreement with James M. Trimble, President and Chief Executive Officer, dated as of November 1, 2011.
|
|
10-Q
|
|
000-07246
|
|
10.2
|
|
11/3/2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.15*
|
|
Employment Agreement with Barton R. Brookman, Jr., Senior Vice President of Exploration and Production, dated as of April 19, 2010.
|
|
8-K
|
|
000-07246
|
|
10.5
|
|
4/23/2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.16
|
|
Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009.
|
|
8-K
|
|
000-07246
|
|
2.1
|
|
11/4/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.17
|
|
Limited Liability Company Agreement of PDC Mountaineer, LLC, dated October 29, 2009.
|
|
8-K
|
|
000-07246
|
|
10.1
|
|
11/4/2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PDC ENERGY, INC.
|
|
|
|
By /s/ James M. Trimble
|
|
James M. Trimble
|
|
President and Chief Executive Officer
|
|
|
|
February 27, 2013
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ James M. Trimble
|
|
President, Chief Executive Officer and Director
|
|
February 27, 2013
|
James M. Trimble
|
|
(principal executive officer)
|
|
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
Chief Financial Officer
|
|
February 27, 2013
|
Gysle R. Shellum
|
|
(principal financial officer)
|
|
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
Chief Accounting Officer
|
|
February 27, 2013
|
R. Scott Meyers
|
|
(principal accounting officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey C. Swoveland
|
|
Chairman and Director
|
|
February 27, 2013
|
Jeffrey C. Swoveland
|
|
|
|
|
|
|
|
|
|
/s/ Joseph E. Casabona
|
|
Director
|
|
February 27, 2013
|
Joseph E. Casabona
|
|
|
|
|
|
|
|
|
|
/s/ Anthony J. Crisafio
|
|
Director
|
|
February 27, 2013
|
Anthony J. Crisafio
|
|
|
|
|
|
|
|
|
|
/s/ Larry F. Mazza
|
|
Director
|
|
February 27, 2013
|
Larry F. Mazza
|
|
|
|
|
|
|
|
|
|
/s/ David C. Parke
|
|
Director
|
|
February 27, 2013
|
David C. Parke
|
|
|
|
|
|
|
|
|
|
/s/ Kimberly Luff Wakim
|
|
Director
|
|
February 27, 2013
|
Kimberly Luff Wakim
|
|
|
|
|
Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information
|
||
|
|
|
|
||
Financial Statements:
|
|
|
|
||
|
||
|
||
|
||
|
||
|
||
|
|
|
Supplemental Information - Unaudited:
|
|
|
|
||
|
||
|
|
|
Financial Statement Schedule:
|
|
|
|
||
|
|
|
|
/s/ James M. Trimble
|
|
|
James M. Trimble
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
|
Gysle R. Shellum
|
|
|
Chief Financial Officer
|
|
|
|
|
|
/s/ R. Scott Meyers
|
|
|
R. Scott Meyers
|
|
|
Chief Accounting Officer
|
As of December 31,
|
|
2012
|
|
2011
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
2,457
|
|
|
$
|
8,238
|
|
Restricted cash
|
|
3,942
|
|
|
11,070
|
|
||
Accounts receivable, net
|
|
64,880
|
|
|
59,923
|
|
||
Accounts receivable affiliates
|
|
4,842
|
|
|
8,518
|
|
||
Fair value of derivatives
|
|
52,042
|
|
|
60,809
|
|
||
Deferred income taxes
|
|
36,151
|
|
|
16,127
|
|
||
Prepaid expenses and other current assets
|
|
7,635
|
|
|
8,365
|
|
||
Total current assets
|
|
171,949
|
|
|
173,050
|
|
||
Properties and equipment, net
|
|
1,616,706
|
|
|
1,301,716
|
|
||
Assets held for sale
|
|
—
|
|
|
148,249
|
|
||
Fair value of derivatives
|
|
6,883
|
|
|
41,175
|
|
||
Accounts receivable affiliates
|
|
—
|
|
|
2,836
|
|
||
Other assets
|
|
31,310
|
|
|
30,979
|
|
||
Total Assets
|
|
$
|
1,826,848
|
|
|
$
|
1,698,005
|
|
|
|
|
|
|
||||
Liabilities and Shareholders' Equity
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
82,716
|
|
|
$
|
76,027
|
|
Accounts payable affiliates
|
|
5,296
|
|
|
10,176
|
|
||
Production tax liability
|
|
25,899
|
|
|
18,949
|
|
||
Fair value of derivatives
|
|
18,439
|
|
|
27,974
|
|
||
Funds held for distribution
|
|
34,228
|
|
|
28,594
|
|
||
Accrued interest payable
|
|
11,056
|
|
|
11,243
|
|
||
Other accrued expenses
|
|
25,715
|
|
|
22,083
|
|
||
Total current liabilities
|
|
203,349
|
|
|
195,046
|
|
||
Long-term debt
|
|
676,579
|
|
|
532,157
|
|
||
Deferred income taxes
|
|
148,427
|
|
|
207,573
|
|
||
Asset retirement obligation
|
|
61,563
|
|
|
46,316
|
|
||
Fair value of derivatives
|
|
10,137
|
|
|
21,106
|
|
||
Accounts payable affiliates
|
|
—
|
|
|
6,134
|
|
||
Other liabilities
|
|
23,612
|
|
|
25,561
|
|
||
Total liabilities
|
|
1,123,667
|
|
|
1,033,893
|
|
||
|
|
|
|
|
||||
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, 100,000,000 authorized, 30,294,224 and 23,634,958 issued as of December 31, 2012 and 2011, respectively
|
|
303
|
|
|
236
|
|
||
Additional paid-in capital
|
|
387,494
|
|
|
217,707
|
|
||
Retained earnings
|
|
315,568
|
|
|
446,280
|
|
||
Treasury shares - at cost, 5,059 and 2,938 as of December 31, 2012 and 2011, respectively
|
|
(184
|
)
|
|
(111
|
)
|
||
Total shareholders' equity
|
|
703,181
|
|
|
664,112
|
|
||
Total Liabilities and Shareholders' Equity
|
|
$
|
1,826,848
|
|
|
$
|
1,698,005
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2012
|
|
2011
|
|
2010
|
||||||
Revenues:
|
|
|
|
|
|
|
||||||
Natural gas, NGLs and crude oil sales
|
|
$
|
270,327
|
|
|
$
|
276,605
|
|
|
$
|
205,029
|
|
Sales from natural gas marketing
|
|
47,079
|
|
|
66,419
|
|
|
69,071
|
|
|||
Commodity price risk management gain, net
|
|
32,339
|
|
|
46,090
|
|
|
59,891
|
|
|||
Well operations, pipeline income and other
|
|
6,388
|
|
|
6,846
|
|
|
9,030
|
|
|||
Total revenues
|
|
356,133
|
|
|
395,960
|
|
|
343,021
|
|
|||
Costs, expenses and other:
|
|
|
|
|
|
|
||||||
Production costs
|
|
75,485
|
|
|
67,352
|
|
|
63,543
|
|
|||
Cost of natural gas marketing
|
|
46,552
|
|
|
65,465
|
|
|
68,015
|
|
|||
Exploration expense
|
|
22,605
|
|
|
6,253
|
|
|
13,675
|
|
|||
Impairment of natural gas and crude oil properties
|
|
168,149
|
|
|
25,159
|
|
|
6,481
|
|
|||
General and administrative expense
|
|
58,815
|
|
|
61,454
|
|
|
42,188
|
|
|||
Depreciation, depletion, and amortization
|
|
146,879
|
|
|
128,907
|
|
|
108,095
|
|
|||
Accretion of asset retirement obligations
|
|
4,060
|
|
|
1,733
|
|
|
1,329
|
|
|||
Gain on sale of properties and equipment
|
|
(4,353
|
)
|
|
(196
|
)
|
|
(174
|
)
|
|||
Total cost, expenses and other
|
|
518,192
|
|
|
356,127
|
|
|
303,152
|
|
|||
Income (loss) from operations
|
|
(162,059
|
)
|
|
39,833
|
|
|
39,869
|
|
|||
Loss on extinguishment of debt
|
|
(23,283
|
)
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
|
(48,287
|
)
|
|
(36,985
|
)
|
|
(33,250
|
)
|
|||
Interest income
|
|
8
|
|
|
47
|
|
|
71
|
|
|||
Income (loss) from continuing operations before income taxes
|
|
(233,621
|
)
|
|
2,895
|
|
|
6,690
|
|
|||
Provision for income taxes
|
|
88,835
|
|
|
183
|
|
|
(652
|
)
|
|||
Income (loss) from continuing operations
|
|
(144,786
|
)
|
|
3,078
|
|
|
6,038
|
|
|||
Income (loss) from discontinued operations, net of tax
|
|
14,074
|
|
|
10,359
|
|
|
(104
|
)
|
|||
Net income (loss)
|
|
(130,712
|
)
|
|
13,437
|
|
|
5,934
|
|
|||
Net loss attributable to noncontrolling interests
|
|
—
|
|
|
—
|
|
|
280
|
|
|||
Net income (loss) attributable to shareholders
|
|
$
|
(130,712
|
)
|
|
$
|
13,437
|
|
|
$
|
6,214
|
|
|
|
|
|
|
|
|
||||||
Amounts attributable to PDC Energy, Inc. shareholders:
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(144,786
|
)
|
|
$
|
3,078
|
|
|
$
|
6,318
|
|
Income (loss) from discontinued operations, net of tax
|
|
14,074
|
|
|
10,359
|
|
|
(104
|
)
|
|||
Net income (loss) attributable to shareholders
|
|
$
|
(130,712
|
)
|
|
$
|
13,437
|
|
|
$
|
6,214
|
|
|
|
|
|
|
|
|
||||||
Earnings per share:
|
|
|
|
|
|
|
||||||
Basic
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(5.23
|
)
|
|
$
|
0.13
|
|
|
$
|
0.33
|
|
Income (loss) from discontinued operations
|
|
0.51
|
|
|
0.44
|
|
|
(0.01
|
)
|
|||
Net income (loss) attributable to shareholders
|
|
$
|
(4.72
|
)
|
|
$
|
0.57
|
|
|
$
|
0.32
|
|
|
|
|
|
|
|
|
||||||
Diluted
|
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
|
$
|
(5.23
|
)
|
|
$
|
0.13
|
|
|
$
|
0.32
|
|
Income (loss) from discontinued operations
|
|
0.51
|
|
|
0.43
|
|
|
(0.01
|
)
|
|||
Net income (loss) attributable to shareholders
|
|
$
|
(4.72
|
)
|
|
$
|
0.56
|
|
|
$
|
0.31
|
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
||||||
Basic
|
|
27,677
|
|
|
23,521
|
|
|
19,674
|
|
|||
Diluted
|
|
27,677
|
|
|
23,871
|
|
|
19,821
|
|
|||
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2012
|
|
2011
|
|
2010
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
(130,712
|
)
|
|
$
|
13,437
|
|
|
$
|
5,934
|
|
Adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
|
|
|
|
|
||||||
Unrealized (gain) loss on derivatives, net
|
|
17,134
|
|
|
(28,601
|
)
|
|
(12,625
|
)
|
|||
Depreciation, depletion and amortization
|
|
146,879
|
|
|
135,154
|
|
|
111,062
|
|
|||
Impairment of natural gas and crude oil properties
|
|
168,149
|
|
|
25,159
|
|
|
11,147
|
|
|||
Prepaid well costs write-offs
|
|
3,916
|
|
|
1,359
|
|
|
668
|
|
|||
Loss on extinguishment of debt
|
|
23,283
|
|
|
—
|
|
|
—
|
|
|||
Exploratory dry hole costs
|
|
15,347
|
|
|
177
|
|
|
4,199
|
|
|||
Accretion of asset retirement obligation
|
|
4,060
|
|
|
1,897
|
|
|
1,423
|
|
|||
Stock-based compensation
|
|
8,495
|
|
|
8,781
|
|
|
5,314
|
|
|||
Excess tax benefits from stock-based compensation
|
|
—
|
|
|
(1,311
|
)
|
|
(293
|
)
|
|||
(Gain) loss from sale of properties and equipment
|
|
(24,273
|
)
|
|
(4,263
|
)
|
|
299
|
|
|||
Amortization of debt discount and issuance costs
|
|
7,864
|
|
|
6,265
|
|
|
4,618
|
|
|||
Deferred income taxes
|
|
(80,379
|
)
|
|
9,530
|
|
|
1,179
|
|
|||
Inventory adjustment and other
|
|
4,123
|
|
|
135
|
|
|
307
|
|
|||
Total adjustments to net income (loss) to reconcile to net cash from operating activities:
|
|
294,598
|
|
|
154,282
|
|
|
127,298
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
6,843
|
|
|
(3,451
|
)
|
|
2,122
|
|
|||
Other assets
|
|
(2,908
|
)
|
|
(3,893
|
)
|
|
22,616
|
|
|||
Restricted cash
|
|
8,859
|
|
|
(8,603
|
)
|
|
219
|
|
|||
Production tax liability
|
|
2,499
|
|
|
5,436
|
|
|
(6,818
|
)
|
|||
Accounts payable and accrued expenses
|
|
(5,050
|
)
|
|
12,422
|
|
|
1,172
|
|
|||
Other liabilities
|
|
592
|
|
|
(2,796
|
)
|
|
(730
|
)
|
|||
Total changes in assets and liabilities
|
|
10,835
|
|
|
(885
|
)
|
|
18,581
|
|
|||
Net cash from operating activities
|
|
174,721
|
|
|
166,834
|
|
|
151,813
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(347,729
|
)
|
|
(334,496
|
)
|
|
(162,723
|
)
|
|||
Acquisition of oil and gas properties, net of cash acquired
|
|
(312,223
|
)
|
|
(145,894
|
)
|
|
(158,051
|
)
|
|||
Proceeds from acquisition adjustments
|
|
14,469
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of properties and equipment
|
|
193,544
|
|
|
23,140
|
|
|
23,369
|
|
|||
Other
|
|
—
|
|
|
849
|
|
|
(3,527
|
)
|
|||
Net cash from investing activities
|
|
(451,939
|
)
|
|
(456,401
|
)
|
|
(300,932
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from revolving credit facility
|
|
682,000
|
|
|
417,194
|
|
|
414,500
|
|
|||
Payment of revolving credit facility
|
|
(839,750
|
)
|
|
(183,713
|
)
|
|
(494,500
|
)
|
|||
Proceeds from senior notes offering
|
|
500,000
|
|
|
—
|
|
|
115,000
|
|
|||
Redemption of senior notes
|
|
(221,840
|
)
|
|
—
|
|
|
—
|
|
|||
Payment of debt issuance costs
|
|
(11,969
|
)
|
|
(680
|
)
|
|
(8,541
|
)
|
|||
Proceeds from sale of common stock, net of issuance costs
|
|
164,496
|
|
|
—
|
|
|
125,506
|
|
|||
Excess tax benefits from stock-based compensation
|
|
—
|
|
|
1,311
|
|
|
293
|
|
|||
Contribution from noncontrolling interest
|
|
—
|
|
|
12,464
|
|
|
20,077
|
|
|||
Purchase of treasury shares
|
|
(1,500
|
)
|
|
(3,143
|
)
|
|
(788
|
)
|
|||
Net cash from financing activities
|
|
271,437
|
|
|
243,433
|
|
|
171,547
|
|
|||
Net change in cash and cash equivalents
|
|
(5,781
|
)
|
|
(46,134
|
)
|
|
22,428
|
|
|||
Cash and cash equivalents, beginning of year
|
|
8,238
|
|
|
54,372
|
|
|
31,944
|
|
|||
Cash and cash equivalents, end of year
|
|
$
|
2,457
|
|
|
$
|
8,238
|
|
|
$
|
54,372
|
|
|
|
|
|
|
|
|
||||||
Supplemental cash flow information:
|
|
|
|
|
|
|
||||||
Cash payments (receipts) for:
|
|
|
|
|
|
|
||||||
Interest, net of capitalized interest
|
|
$
|
41,768
|
|
|
$
|
29,429
|
|
|
$
|
28,335
|
|
Income taxes
|
|
1,845
|
|
|
(1,498
|
)
|
|
(27,322
|
)
|
|||
Non-cash investing activities:
|
|
|
|
|
|
|
||||||
Change in accounts payable related to purchases of properties and equipment
|
|
288
|
|
|
23,837
|
|
|
15,787
|
|
|||
Change in asset retirement obligation, with a corresponding change to natural gas and crude oil properties, net of disposals
|
|
11,967
|
|
|
17,538
|
|
|
3,624
|
|
|||
Non-cash financing activities:
|
|
|
|
|
|
|
||||||
Change in paid-in capital related to convertible debt, net of tax
|
|
—
|
|
|
—
|
|
|
12,850
|
|
|||
See Note 15,
Acquisitions
, for non-cash transactions related to our acquisitions
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2012
|
|
2011
|
|
2010
|
||||||
Common shares, issued:
|
|
|
|
|
|
|
||||||
Shares beginning of year
|
|
23,634,958
|
|
|
23,462,326
|
|
|
19,242,219
|
|
|||
Shares issued pursuant to sale of equity
|
|
6,500,000
|
|
|
—
|
|
|
4,140,000
|
|
|||
Exercise of stock options
|
|
—
|
|
|
2,814
|
|
|
—
|
|
|||
Issuance of stock awards, net of forfeitures
|
|
173,737
|
|
|
242,334
|
|
|
110,680
|
|
|||
Retirement of treasury shares
|
|
(14,471
|
)
|
|
(72,516
|
)
|
|
(30,573
|
)
|
|||
Shares end of year
|
|
30,294,224
|
|
|
23,634,958
|
|
|
23,462,326
|
|
|||
Treasury shares:
|
|
|
|
|
|
|
||||||
Shares beginning of year
|
|
2,938
|
|
|
2,938
|
|
|
8,273
|
|
|||
Purchase of treasury shares
|
|
44,576
|
|
|
87,588
|
|
|
30,573
|
|
|||
Issuance of treasury shares
|
|
(28,587
|
)
|
|
(15,072
|
)
|
|
—
|
|
|||
Retirement of treasury shares
|
|
(14,471
|
)
|
|
(72,516
|
)
|
|
(30,573
|
)
|
|||
Non-employee directors' deferred compensation plan
|
|
603
|
|
|
—
|
|
|
(5,335
|
)
|
|||
Shares end of year
|
|
5,059
|
|
|
2,938
|
|
|
2,938
|
|
|||
Common shares outstanding
|
|
30,289,165
|
|
|
23,632,020
|
|
|
23,459,388
|
|
|||
|
|
|
|
|
|
|
||||||
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
|
|
236
|
|
|
235
|
|
|
192
|
|
|||
Shares issued pursuant to sale of equity
|
|
65
|
|
|
—
|
|
|
41
|
|
|||
Issuance of stock awards, net of forfeitures
|
|
2
|
|
|
1
|
|
|
2
|
|
|||
Balance end of year
|
|
303
|
|
|
236
|
|
|
235
|
|
|||
Additional paid-in capital:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
217,707
|
|
|
209,198
|
|
|
64,406
|
|
|||
Proceeds from sale of equity, net of issuance costs
|
|
164,431
|
|
|
—
|
|
|
125,465
|
|
|||
Convertible debt discount, net of issuance costs and tax
|
|
—
|
|
|
—
|
|
|
12,165
|
|
|||
Stock-based compensation expense
|
|
8,495
|
|
|
8,781
|
|
|
5,314
|
|
|||
Issuance of treasury shares
|
|
(955
|
)
|
|
(472
|
)
|
|
—
|
|
|||
Retirement of treasury shares
|
|
(491
|
)
|
|
(2,671
|
)
|
|
(788
|
)
|
|||
Tax impact of stock-based compensation
|
|
(1,693
|
)
|
|
785
|
|
|
(166
|
)
|
|||
Contribution by investing partner in PDCM
|
|
—
|
|
|
12,464
|
|
|
20,077
|
|
|||
Effect of PDCM deconsolidation/change in ownership interest
|
|
—
|
|
|
(10,378
|
)
|
|
(17,275
|
)
|
|||
Balance end of year
|
|
387,494
|
|
|
217,707
|
|
|
209,198
|
|
|||
Retained earnings:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
446,280
|
|
|
432,843
|
|
|
426,629
|
|
|||
Net income (loss) attributable to shareholders
|
|
(130,712
|
)
|
|
13,437
|
|
|
6,214
|
|
|||
Balance end of year
|
|
315,568
|
|
|
446,280
|
|
|
432,843
|
|
|||
Treasury shares, at cost:
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
(111
|
)
|
|
(111
|
)
|
|
(312
|
)
|
|||
Purchase of treasury shares
|
|
(1,500
|
)
|
|
(3,143
|
)
|
|
(788
|
)
|
|||
Issuance of treasury shares
|
|
955
|
|
|
472
|
|
|
—
|
|
|||
Retirement of treasury shares
|
|
491
|
|
|
2,671
|
|
|
788
|
|
|||
Non-employee directors' deferred compensation plan
|
|
(19
|
)
|
|
—
|
|
|
201
|
|
|||
Balance end of year
|
|
(184
|
)
|
|
(111
|
)
|
|
(111
|
)
|
|||
Total shareholders' equity
|
|
703,181
|
|
|
664,112
|
|
|
642,165
|
|
|||
Noncontrolling interests in subsidiary
|
|
|
|
|
|
|
||||||
Balance beginning of year
|
|
—
|
|
|
76
|
|
|
47,678
|
|
|||
Noncontrolling interest in PDC Mountaineer, LLC
|
|
—
|
|
|
—
|
|
|
(47,322
|
)
|
|||
Net loss attributed to noncontrolling interest in subsidiary
|
|
—
|
|
|
(76
|
)
|
|
(280
|
)
|
|||
Balance end of year
|
|
—
|
|
|
—
|
|
|
76
|
|
|||
Total noncontrolling interests in subsidiary
|
|
—
|
|
|
—
|
|
|
76
|
|
|||
Total Equity
|
|
$
|
703,181
|
|
|
$
|
664,112
|
|
|
$
|
642,241
|
|
|
|
|
|
|
|
|
Pipelines and related facilities
|
10 - 17 years
|
Transportation and other equipment
|
3 - 20 years
|
Buildings
|
30 - 40 years
|
|
As of December 31,
|
||||||||||||||||||||||
|
2012
|
|
2011
|
||||||||||||||||||||
|
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
|
$
|
42,788
|
|
|
$
|
15,734
|
|
|
$
|
58,522
|
|
|
$
|
76,104
|
|
|
$
|
25,837
|
|
|
$
|
101,941
|
|
Basis protection derivative contracts
|
387
|
|
|
16
|
|
|
403
|
|
|
5
|
|
|
38
|
|
|
43
|
|
||||||
Total assets
|
43,175
|
|
|
15,750
|
|
|
58,925
|
|
|
76,109
|
|
|
25,875
|
|
|
101,984
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity-based derivative contracts
|
9,839
|
|
|
2,081
|
|
|
11,920
|
|
|
9,888
|
|
|
3,768
|
|
|
13,656
|
|
||||||
Basis protection derivative contracts
|
16,656
|
|
|
—
|
|
|
16,656
|
|
|
35,424
|
|
|
—
|
|
|
35,424
|
|
||||||
Total liabilities
|
26,495
|
|
|
2,081
|
|
|
28,576
|
|
|
45,312
|
|
|
3,768
|
|
|
49,080
|
|
||||||
Net asset
|
$
|
16,680
|
|
|
$
|
13,669
|
|
|
$
|
30,349
|
|
|
$
|
30,797
|
|
|
$
|
22,107
|
|
|
$
|
52,904
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Fair value, net asset, beginning of year
|
|
$
|
22,107
|
|
|
$
|
10,762
|
|
|
$
|
15,048
|
|
Changes in fair value included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain, net
|
|
7,576
|
|
|
13,487
|
|
|
11,591
|
|
|||
Sales from natural gas marketing
|
|
63
|
|
|
114
|
|
|
580
|
|
|||
Cost of natural gas marketing
|
|
—
|
|
|
—
|
|
|
23
|
|
|||
Changes in fair value included in balance sheet line item (1):
|
|
|
|
|
|
|
||||||
Accounts receivable affiliates
|
|
—
|
|
|
49
|
|
|
231
|
|
|||
Accounts payable affiliates
|
|
(319
|
)
|
|
(454
|
)
|
|
(1,737
|
)
|
|||
Settlements included in statement of operations line items:
|
|
|
|
|
|
|
||||||
Commodity price risk management loss, net
|
|
(15,644
|
)
|
|
(1,712
|
)
|
|
(14,467
|
)
|
|||
Sales from natural gas marketing
|
|
(114
|
)
|
|
(139
|
)
|
|
(484
|
)
|
|||
Cost of natural gas marketing
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|||
Fair value, net asset end of year
|
|
$
|
13,669
|
|
|
$
|
22,107
|
|
|
$
|
10,762
|
|
|
|
|
|
|
|
|
||||||
Changes in unrealized gains (losses) relating to assets (liabilities) still held
|
|
|
|
|
|
|
||||||
as of year-end, included in statement of operations line item:
|
|
|
|
|
|
|
||||||
Commodity price risk management gain, net
|
|
$
|
3,665
|
|
|
$
|
11,669
|
|
|
$
|
9,594
|
|
Sales from natural gas marketing
|
|
1
|
|
|
(3
|
)
|
|
54
|
|
|||
Total
|
|
$
|
3,666
|
|
|
$
|
11,666
|
|
|
$
|
9,648
|
|
|
|
|
|
|
|
|
(1)
|
Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.
|
•
|
For natural gas and crude oil 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.
|
•
|
Floor options (puts) are arrangements where, 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 put strike price, then no payment is due from us to the counterparty;
|
•
|
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 have negative differentials to NYMEX, 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.
|
Derivatives instruments:
|
|
Balance sheet line item
|
|
2012
|
|
2011
|
|||||
|
|
|
|
|
(in thousands)
|
||||||
Derivative assets:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas and crude oil sales
|
|
Fair value of derivatives
|
|
$
|
47,016
|
|
|
$
|
51,220
|
|
|
Related to affiliated partnerships (1)
|
|
Fair value of derivatives
|
|
4,707
|
|
|
8,018
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
302
|
|
|
1,528
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
17
|
|
|
43
|
|
||
|
|
|
|
|
52,042
|
|
|
60,809
|
|
||
|
Non Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas and crude oil sales
|
|
Fair value of derivatives
|
|
6,671
|
|
|
34,938
|
|
||
|
Related to affiliated partnerships (1)
|
|
Fair value of derivatives
|
|
—
|
|
|
6,134
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
203
|
|
|
103
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
9
|
|
|
—
|
|
||
|
|
|
|
|
6,883
|
|
|
41,175
|
|
||
Total derivative assets
|
|
|
|
|
$
|
58,925
|
|
|
$
|
101,984
|
|
|
|
|
|
|
|
|
|
||||
Derivative liabilities:
|
Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas and crude oil sales
|
|
Fair value of derivatives
|
|
$
|
1,744
|
|
|
$
|
7,498
|
|
|
Related to affiliated partnerships (2)
|
|
Fair value of derivatives
|
|
—
|
|
|
211
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
226
|
|
|
1,384
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas and crude oil sales
|
|
Fair value of derivatives
|
|
14,329
|
|
|
15,762
|
|
||
|
Related to affiliated partnerships (2)
|
|
Fair value of derivatives
|
|
2,140
|
|
|
3,116
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
—
|
|
|
3
|
|
||
|
|
|
|
|
18,439
|
|
|
27,974
|
|
||
|
Non Current
|
|
|
|
|
|
|
||||
|
Commodity contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas and crude oil sales
|
|
Fair value of derivatives
|
|
9,969
|
|
|
4,357
|
|
||
|
Related to affiliated partnerships (2)
|
|
Fair value of derivatives
|
|
—
|
|
|
113
|
|
||
|
Related to natural gas marketing
|
|
Fair value of derivatives
|
|
168
|
|
|
93
|
|
||
|
Basis protection contracts
|
|
|
|
|
|
|
||||
|
Related to natural gas and crude oil sales
|
|
Fair value of derivatives
|
|
—
|
|
|
13,820
|
|
||
|
Related to affiliated partnerships (2)
|
|
Fair value of derivatives
|
|
—
|
|
|
2,723
|
|
||
|
|
|
|
|
10,137
|
|
|
21,106
|
|
||
Total derivative liabilities
|
|
|
|
|
$
|
28,576
|
|
|
$
|
49,080
|
|
(1)
|
Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets.
|
(2)
|
Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities.
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||||||||||||||||||||
Statement of operations line item
|
|
Reclassification
of Realized Gains (Losses) Included in Prior Periods Unrealized |
|
Realized and Unrealized
Gains (Losses) For the Current Period |
|
Total
|
|
Reclassification
of Realized Gains (Losses) Included in Prior Periods Unrealized |
|
Realized and Unrealized
Gains (Losses) For the Current Period |
|
Total
|
|
Reclassification
of Realized Gains (Losses) Included in Prior Periods Unrealized |
|
Realized and Unrealized
Gains (Losses) For the Current Period |
|
Total
|
||||||||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||||||||||||||
Commodity price risk management gain (loss), net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Realized gains
|
|
$
|
28,819
|
|
|
$
|
20,597
|
|
|
$
|
49,416
|
|
|
$
|
10,329
|
|
|
$
|
6,914
|
|
|
$
|
17,243
|
|
|
$
|
20,148
|
|
|
$
|
26,947
|
|
|
$
|
47,095
|
|
Unrealized gains (losses)
|
|
(28,819
|
)
|
|
11,742
|
|
|
(17,077
|
)
|
|
(10,329
|
)
|
|
39,176
|
|
|
28,847
|
|
|
(20,148
|
)
|
|
32,944
|
|
|
12,796
|
|
|||||||||
Total commodity price risk management gain, net
|
|
$
|
—
|
|
|
$
|
32,339
|
|
|
$
|
32,339
|
|
|
$
|
—
|
|
|
$
|
46,090
|
|
|
$
|
46,090
|
|
|
$
|
—
|
|
|
$
|
59,891
|
|
|
$
|
59,891
|
|
Sales from natural gas marketing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Realized gains
|
|
$
|
1,571
|
|
|
$
|
599
|
|
|
$
|
2,170
|
|
|
$
|
1,827
|
|
|
$
|
1,143
|
|
|
$
|
2,970
|
|
|
$
|
2,390
|
|
|
$
|
3,991
|
|
|
$
|
6,381
|
|
Unrealized gains (losses)
|
|
(1,571
|
)
|
|
(87
|
)
|
|
(1,658
|
)
|
|
(1,827
|
)
|
|
1,666
|
|
|
(161
|
)
|
|
(2,390
|
)
|
|
1,745
|
|
|
(645
|
)
|
|||||||||
Total sales from natural gas marketing
|
|
$
|
—
|
|
|
$
|
512
|
|
|
$
|
512
|
|
|
$
|
—
|
|
|
$
|
2,809
|
|
|
$
|
2,809
|
|
|
$
|
—
|
|
|
$
|
5,736
|
|
|
$
|
5,736
|
|
Cost of natural gas marketing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Realized losses
|
|
$
|
(1,387
|
)
|
|
$
|
(642
|
)
|
|
$
|
(2,029
|
)
|
|
$
|
(1,441
|
)
|
|
$
|
(1,130
|
)
|
|
$
|
(2,571
|
)
|
|
$
|
(1,905
|
)
|
|
$
|
(3,996
|
)
|
|
$
|
(5,901
|
)
|
Unrealized gains (losses)
|
|
1,387
|
|
|
214
|
|
|
1,601
|
|
|
1,441
|
|
|
(1,526
|
)
|
|
(85
|
)
|
|
1,905
|
|
|
(1,431
|
)
|
|
474
|
|
|||||||||
Total cost of natural gas marketing
|
|
$
|
—
|
|
|
$
|
(428
|
)
|
|
$
|
(428
|
)
|
|
$
|
—
|
|
|
$
|
(2,656
|
)
|
|
$
|
(2,656
|
)
|
|
$
|
—
|
|
|
$
|
(5,427
|
)
|
|
$
|
(5,427
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Natural gas, NGLs and crude oil sales
|
$
|
39,837
|
|
|
$
|
42,388
|
|
Natural gas marketing
|
8,209
|
|
|
6,225
|
|
||
Reimbursements for title defects
|
7,579
|
|
|
—
|
|
||
Joint interest billings
|
6,896
|
|
|
7,465
|
|
||
Other
|
3,385
|
|
|
4,766
|
|
||
Allowance for doubtful accounts
|
(1,026
|
)
|
|
(921
|
)
|
||
Accounts receivable, net
|
$
|
64,880
|
|
|
$
|
59,923
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
Customer
|
|
2012
|
|
2011
|
|
2010
|
|||
|
|
|
|
|
|
|
|||
Suncor Energy Marketing, Inc.
|
|
29.8
|
%
|
|
25.7
|
%
|
|
19.6
|
%
|
DCP Midstream, LP
|
|
12.2
|
%
|
|
11.5
|
%
|
|
9.6
|
%
|
WPX Energy Rocky Mountain, LLC
|
|
5.6
|
%
|
|
9.9
|
%
|
|
12.5
|
%
|
|
|
Fair Value of
Derivative Assets |
||
Counterparty Name
|
|
As of December 31, 2012
|
||
|
|
(in thousands)
|
||
|
|
|
||
JPMorgan Chase Bank, N.A. (1)
|
|
$
|
41,323
|
|
Wells Fargo Bank, N.A. (1)
|
|
4,782
|
|
|
Bank of Nova Scotia (1)
|
|
4,315
|
|
|
Other lenders in our revolving credit facility
|
|
8,146
|
|
|
Various (2)
|
|
359
|
|
|
Total
|
|
$
|
58,925
|
|
|
|
|
|
As of December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in thousands)
|
||||||
Properties and equipment, net:
|
|
|
|
||||
Natural gas and crude oil properties
|
|
|
|
||||
Proved
|
$
|
2,075,924
|
|
|
$
|
1,694,694
|
|
Unproved
|
319,327
|
|
|
102,466
|
|
||
Total natural gas and crude oil properties
|
2,395,251
|
|
|
1,797,160
|
|
||
Pipelines and related facilities
|
47,786
|
|
|
40,721
|
|
||
Transportation and other equipment
|
34,858
|
|
|
32,475
|
|
||
Land and buildings
|
14,935
|
|
|
14,572
|
|
||
Construction in progress
|
67,217
|
|
|
69,633
|
|
||
Gross properties and equipment
|
2,560,047
|
|
|
1,954,561
|
|
||
Accumulated depreciation, depletion and amortization
|
(943,341
|
)
|
|
(652,845
|
)
|
||
Properties and equipment, net
|
$
|
1,616,706
|
|
|
$
|
1,301,716
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
Continuing operations:
|
|
|
|
|
|
||||||
Impairment of proved properties
|
$
|
161,185
|
|
|
$
|
22,460
|
|
|
$
|
—
|
|
Impairment of individually significant unproved properties
|
1,943
|
|
|
1,108
|
|
|
1,477
|
|
|||
Amortization of individually insignificant unproved properties
|
5,021
|
|
|
1,591
|
|
|
5,004
|
|
|||
Total continuing operations
|
168,149
|
|
|
25,159
|
|
|
6,481
|
|
|||
Discontinued operations:
|
|
|
|
|
|
||||||
Impairment of proved properties
|
—
|
|
|
—
|
|
|
4,666
|
|
|||
Total discontinued operations
|
—
|
|
|
—
|
|
|
4,666
|
|
|||
Total impairment of natural gas and crude oil properties
|
$
|
168,149
|
|
|
$
|
25,159
|
|
|
$
|
11,147
|
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands, except for number of wells)
|
||||||||||
|
|
|
|
|
|
||||||
Balance beginning of year, January 1,
|
$
|
4,432
|
|
|
$
|
2,297
|
|
|
$
|
1,174
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
30,482
|
|
|
3,692
|
|
|
4,353
|
|
|||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
|
—
|
|
|
(1,557
|
)
|
|
(2,231
|
)
|
|||
Deconsolidation of PDCM and change in ownership interest
|
—
|
|
|
—
|
|
|
(462
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
(15,347
|
)
|
|
—
|
|
|
(537
|
)
|
|||
Balance end of year, December 31,
|
$
|
19,567
|
|
|
$
|
4,432
|
|
|
$
|
2,297
|
|
|
|
|
|
|
|
||||||
Number of wells pending determination at December 31,
|
2
|
|
|
6
|
|
|
3
|
|
|||
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Exploratory well costs capitalized for a period of one year or less
|
$
|
19,567
|
|
|
$
|
3,587
|
|
|
$
|
2,297
|
|
Exploratory well costs capitalized for a period greater than one year since commencement of drilling
|
—
|
|
|
845
|
|
|
—
|
|
|||
Balance end of year, December 31,
|
$
|
19,567
|
|
|
$
|
4,432
|
|
|
$
|
2,297
|
|
Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling
|
—
|
|
|
2
|
|
|
—
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
—
|
|
|
$
|
3,172
|
|
|
$
|
1,616
|
|
State
|
(199
|
)
|
|
172
|
|
|
(904
|
)
|
|||
Total current income taxes
|
(199
|
)
|
|
3,344
|
|
|
712
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
78,425
|
|
|
(2,868
|
)
|
|
(3,990
|
)
|
|||
State
|
10,609
|
|
|
(293
|
)
|
|
2,626
|
|
|||
Total deferred income taxes
|
89,034
|
|
|
(3,161
|
)
|
|
(1,364
|
)
|
|||
Provision for income taxes from continuing operations
|
$
|
88,835
|
|
|
$
|
183
|
|
|
$
|
(652
|
)
|
|
|
|
|
|
|
|
Year Ended December, 31,
|
|||||||
|
2012
|
|
2011
|
|
2010
|
|||
|
|
|
|
|
|
|||
Statutory tax rate
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State income tax, net
|
2.9
|
|
|
(9.4
|
)
|
|
1.3
|
|
Percentage depletion
|
0.3
|
|
|
(29.5
|
)
|
|
(11.3
|
)
|
Non-deductible compensation
|
(0.1
|
)
|
|
—
|
|
|
4.4
|
|
Non-deductible meals and entertainment
|
(0.1
|
)
|
|
3.1
|
|
|
1.2
|
|
State deferred rate change
|
—
|
|
|
15.4
|
|
|
(26.2
|
)
|
Unrecognized tax benefits
|
—
|
|
|
(30.3
|
)
|
|
2.4
|
|
State tax credits
|
—
|
|
|
—
|
|
|
(3.3
|
)
|
Federal return examination adjustments
|
—
|
|
|
4.2
|
|
|
4.7
|
|
Return to provision adjustments
|
—
|
|
|
3.7
|
|
|
—
|
|
Other
|
—
|
|
|
1.5
|
|
|
1.5
|
|
Effective tax rate
|
38.0
|
%
|
|
(6.3
|
)%
|
|
9.7
|
%
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Provision for underpayment of natural gas sales
|
$
|
—
|
|
|
$
|
3,334
|
|
Deferred compensation
|
7,216
|
|
|
4,319
|
|
||
Asset retirement obligations
|
10,325
|
|
|
9,438
|
|
||
State NOL and tax credit carryforwards, net
|
6,117
|
|
|
5,240
|
|
||
Percentage depletion - carryforward
|
4,702
|
|
|
3,733
|
|
||
Alternative minimum tax - credit carryforward
|
2,351
|
|
|
2,351
|
|
||
Federal NOL carryforward
|
21,281
|
|
|
12,210
|
|
||
Other
|
2,276
|
|
|
2,621
|
|
||
Deferred tax assets
|
54,268
|
|
|
43,246
|
|
||
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
||||
Properties and equipment
|
122,742
|
|
|
184,657
|
|
||
Investment in PDCM
|
31,445
|
|
|
30,919
|
|
||
Unrealized gains - derivatives
|
7,163
|
|
|
12,612
|
|
||
Convertible debt
|
5,194
|
|
|
6,504
|
|
||
Total gross deferred tax liabilities
|
166,544
|
|
|
234,692
|
|
||
Net deferred tax liability
|
$
|
112,276
|
|
|
$
|
191,446
|
|
|
|
|
|
||||
Classification in the balance sheets:
|
|
|
|
||||
Deferred income tax assets
|
$
|
36,151
|
|
|
$
|
16,127
|
|
Deferred income tax liability
|
148,427
|
|
|
207,573
|
|
||
Net deferred tax liability
|
$
|
112,276
|
|
|
$
|
191,446
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Balance beginning of year, January 1
|
|
$
|
179
|
|
|
$
|
1,093
|
|
|
$
|
566
|
|
Additions for tax positions of prior years
|
|
—
|
|
|
—
|
|
|
253
|
|
|||
Additions for tax positions of current year
|
|
—
|
|
|
—
|
|
|
274
|
|
|||
Reductions due to settlements
|
|
—
|
|
|
(782
|
)
|
|
—
|
|
|||
Reductions due to lapse of statute of limitations
|
|
—
|
|
|
(132
|
)
|
|
—
|
|
|||
Balance end of year, December 31
|
|
$
|
179
|
|
|
$
|
179
|
|
|
$
|
1,093
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in thousands)
|
||||||
Senior notes
|
|
|
|
||||
3.25% Convertible senior notes due 2016:
|
|
|
|
||||
Principal amount
|
$
|
115,000
|
|
|
$
|
115,000
|
|
Unamortized discount
|
(13,671
|
)
|
|
(17,079
|
)
|
||
3.25% Convertible senior notes due 2016, net of discount
|
101,329
|
|
|
97,921
|
|
||
7.75% Senior notes due 2022:
|
|
|
|
||||
Principal amount
|
500,000
|
|
|
—
|
|
||
12% Senior notes due 2018:
|
|
|
|
||||
Principal amount
|
—
|
|
|
203,000
|
|
||
Unamortized discount
|
—
|
|
|
(1,764
|
)
|
||
12% Senior notes due 2018, net of discount
|
—
|
|
|
201,236
|
|
||
Total senior notes
|
601,329
|
|
|
299,157
|
|
||
Credit facilities
|
|
|
|
||||
Corporate
|
49,000
|
|
|
209,000
|
|
||
PDCM
|
26,250
|
|
|
24,000
|
|
||
Total credit facilities
|
75,250
|
|
|
233,000
|
|
||
Total long-term debt
|
$
|
676,579
|
|
|
$
|
532,157
|
|
|
|
|
|
•
|
at least 65% of the aggregate principal amount of the notes issued on October 3, 2012 remains outstanding after each such redemption; and
|
•
|
the redemption occurs within 180 days after the closing of the equity offering.
|
|
2012
|
|
2011
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Balance beginning of year, January 1
|
$
|
46,566
|
|
|
$
|
28,047
|
|
Obligations incurred with development activities and assumed with acquisitions
|
14,169
|
|
|
9,625
|
|
||
Accretion expense
|
4,060
|
|
|
1,897
|
|
||
Obligations discharged with disposal of properties and asset retirements
|
(2,232
|
)
|
|
(990
|
)
|
||
Deconsolidation of PDCM and change in ownership interest
|
—
|
|
|
(916
|
)
|
||
Revisions in estimated cash flows
|
—
|
|
|
8,903
|
|
||
Balance end of year, December 31 (1)
|
62,563
|
|
|
46,566
|
|
||
Less current portion
|
(1,000
|
)
|
|
(250
|
)
|
||
Long-term portion
|
$
|
61,563
|
|
|
$
|
46,316
|
|
|
|
|
|
(1)
|
Includes
$2 million
as of December 31, 2011 related to assets held for sale.
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||
Area
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
Through Expiration |
|
Total
|
|
Expiration
Date |
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Volume (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Piceance Basin
|
|
30,710
|
|
|
36,168
|
|
|
30,603
|
|
|
26,053
|
|
|
85,895
|
|
|
209,429
|
|
|
May 31, 2021
|
||||||
Appalachian Basin
|
|
20,316
|
|
|
24,353
|
|
|
23,361
|
|
|
24,862
|
|
|
168,296
|
|
|
261,188
|
|
|
September 20, 2025
|
||||||
NECO
|
|
2,190
|
|
|
1,825
|
|
|
1,825
|
|
|
1,825
|
|
|
—
|
|
|
7,665
|
|
|
December 31, 2016
|
||||||
Total
|
|
53,216
|
|
|
62,346
|
|
|
55,789
|
|
|
52,740
|
|
|
254,191
|
|
|
478,282
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dollar commitment
(in thousands) |
|
$
|
25,756
|
|
|
$
|
29,283
|
|
|
$
|
26,163
|
|
|
$
|
24,075
|
|
|
$
|
94,033
|
|
|
$
|
199,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
||||||||||||||||||||||
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
Thereafter
|
|
Total
|
||||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Minimum Lease Payments
|
|
$
|
2,607
|
|
|
$
|
2,386
|
|
|
$
|
1,929
|
|
|
$
|
461
|
|
|
$
|
255
|
|
|
$
|
887
|
|
|
$
|
8,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2012
|
|
2011 (1)
|
|
2010
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Stock-based compensation expense
|
|
$
|
8,495
|
|
|
$
|
8,781
|
|
|
$
|
5,314
|
|
Income tax benefit
|
|
(3,245
|
)
|
|
(3,344
|
)
|
|
(2,019
|
)
|
|||
Net expense
|
|
$
|
5,250
|
|
|
$
|
5,437
|
|
|
$
|
3,295
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||||||||||||||
|
Number of
Shares Underlying Options |
|
Weighted-Average
Exercise Price Per Share |
|
Weighted- Average
Remaining Contractual Term (in years) |
|
Number of
Shares Underlying Options |
|
Weighted-Average
Exercise Price Per Share |
|
Number of
Shares Underlying Options |
|
Weighted-Average
Exercise Price Per Share |
||||||||||
Outstanding beginning of year, January 1,
|
6,973
|
|
|
$
|
41.09
|
|
|
—
|
|
|
10,306
|
|
|
$
|
41.90
|
|
|
10,306
|
|
|
$
|
41.90
|
|
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,333
|
)
|
|
43.60
|
|
|
—
|
|
|
—
|
|
|||
Outstanding end of year, December 31,
|
6,973
|
|
|
41.09
|
|
|
2.6
|
|
|
6,973
|
|
|
41.09
|
|
|
10,306
|
|
|
41.90
|
|
|||
Exercisable at December 31,
|
6,973
|
|
|
41.09
|
|
|
2.6
|
|
|
6,973
|
|
|
41.09
|
|
|
10,306
|
|
|
41.60
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
|
|
|
|
||||||
Expected term of award
|
6 years
|
|
|
6 years
|
|
|
5 years
|
|
|||
Risk-free interest rate
|
1.1
|
%
|
|
2.5
|
%
|
|
2.5
|
%
|
|||
Expected volatility
|
64.3
|
%
|
|
60.2
|
%
|
|
62.0
|
%
|
|||
Weighted-average grant date fair value per share
|
$
|
17.61
|
|
|
$
|
25.22
|
|
|
$
|
13.26
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||||||||||||||||||||||||||
|
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,
|
50,471
|
|
|
$
|
31.61
|
|
|
8.6
|
|
|
$
|
341
|
|
|
57,282
|
|
|
$
|
24.44
|
|
|
$
|
1,020
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Awarded
|
68,361
|
|
|
30.19
|
|
|
—
|
|
|
—
|
|
|
31,552
|
|
|
43.95
|
|
|
—
|
|
|
57,282
|
|
|
24.44
|
|
|
—
|
|
||||||
Exercised
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25,371
|
)
|
|
24.44
|
|
|
77
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12,992
|
)
|
|
43.95
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Outstanding end of year, December 31,
|
118,832
|
|
|
30.80
|
|
|
8.4
|
|
|
486
|
|
|
50,471
|
|
|
31.61
|
|
|
341
|
|
|
57,282
|
|
|
24.44
|
|
|
1,020
|
|
||||||
Exercisable at December 31,
|
27,458
|
|
|
28.84
|
|
|
7.5
|
|
|
187
|
|
|
10,636
|
|
|
24.44
|
|
|
114
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Shares
|
|
Weighted-Average
Grant-Date Fair Value |
|||
|
|
|
|
|||
Non-vested at December 31, 2011
|
527,801
|
|
|
$
|
29.29
|
|
Granted
|
341,338
|
|
|
26.59
|
|
|
Vested
|
(186,205
|
)
|
|
29.42
|
|
|
Forfeited
|
(36,444
|
)
|
|
28.20
|
|
|
Non-vested at December 31, 2012
|
646,490
|
|
|
27.93
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of time-based awards vested
|
$
|
5,950
|
|
|
$
|
9,030
|
|
|
$
|
3,219
|
|
Total intrinsic value of time-based awards non-vested
|
21,470
|
|
|
18,531
|
|
|
22,211
|
|
|||
Market price per common share as of December 31,
|
33.21
|
|
|
35.11
|
|
|
42.25
|
|
|||
Weighted-average grant date fair value per share
|
26.59
|
|
|
33.71
|
|
|
25.04
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
|
|
|
|
|
||||
Expected term of award
|
|
3 years
|
|
|
3 years
|
|
||
Risk-free interest rate
|
|
0.3
|
%
|
|
1.1
|
%
|
||
Expected volatility
|
|
65.3
|
%
|
|
74.2
|
%
|
||
Weighted-average grant date fair value per share
|
|
$
|
36.54
|
|
|
$
|
58.53
|
|
|
|
Shares
|
|
Weighted-Average
Grant-Date Fair Value per Share |
|||
|
|
|
|
|
|||
Non-vested at December 31, 2011
|
|
43,081
|
|
|
$
|
42.05
|
|
Granted
|
|
30,541
|
|
|
36.54
|
|
|
Forfeited
|
|
(32,926
|
)
|
|
45.15
|
|
|
Non-vested at December 31, 2012
|
|
40,696
|
|
|
39.22
|
|
|
|
|
|
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands, except per share data)
|
||||||||||
|
|
|
|
|
|
||||||
Total intrinsic value of market-based awards vested
|
$
|
—
|
|
|
$
|
366
|
|
|
$
|
—
|
|
Total intrinsic value of market-based awards non-vested
|
1,352
|
|
|
1,513
|
|
|
3,361
|
|
|||
Market price per common share as of December 31,
|
33.21
|
|
|
35.11
|
|
|
42.25
|
|
|||
Weighted-average grant date fair value per share
|
36.54
|
|
|
58.53
|
|
|
—
|
|
|
Year Ended December 31,
|
|||||||
|
2012
|
|
2011
|
|
2010
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common shares outstanding - basic
|
27,677
|
|
|
23,521
|
|
|
19,674
|
|
Dilutive effect of share-based compensation:
|
|
|
|
|
|
|||
Restricted stock
|
—
|
|
|
307
|
|
|
119
|
|
SARs
|
—
|
|
|
40
|
|
|
21
|
|
Non-employee director deferred compensation
|
—
|
|
|
3
|
|
|
7
|
|
Weighted-average common and common share equivalents outstanding - diluted
|
27,677
|
|
|
23,871
|
|
|
19,821
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
|
2012
|
|
2011
|
|
2010
|
|||
|
(in thousands)
|
|||||||
|
|
|
|
|
|
|||
Weighted-average common share equivalents excluded from diluted earnings
|
|
|
|
|
|
|||
per share due to their anti-dilutive effect:
|
|
|
|
|
|
|||
Restricted stock
|
694
|
|
|
220
|
|
|
204
|
|
SARs
|
116
|
|
|
22
|
|
|
—
|
|
Stock options
|
7
|
|
|
9
|
|
|
10
|
|
Non-employee director deferred compensation
|
3
|
|
|
—
|
|
|
—
|
|
Total anti-dilutive common share equivalents
|
820
|
|
|
251
|
|
|
214
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
||||||
|
|
2011
|
||||||
Balance Sheet
|
|
Net Assets Held for Sale
|
|
Net Assets
Related to Discontinued Operations |
||||
|
|
(in thousands)
|
||||||
Assets
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Accounts receivable, net
|
|
$
|
—
|
|
|
$
|
3,198
|
|
Oil inventory
|
|
—
|
|
|
89
|
|
||
Total current assets
|
|
—
|
|
|
3,287
|
|
||
Properties and equipment
|
|
168,218
|
|
|
168,218
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
|
(19,969
|
)
|
|
(19,969
|
)
|
||
Total assets
|
|
$
|
148,249
|
|
|
$
|
151,536
|
|
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable
|
|
—
|
|
|
1,907
|
|
||
Production tax liability
|
|
—
|
|
|
262
|
|
||
Total current liabilities
|
|
—
|
|
|
2,169
|
|
||
Asset retirement obligation
|
|
2,022
|
|
|
2,022
|
|
||
Total liabilities
|
|
$
|
2,022
|
|
|
$
|
4,191
|
|
|
|
|
|
|
||||
Net assets
|
|
$
|
146,227
|
|
|
$
|
147,345
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
Statements of Operations - Discontinued Operations
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(in thousands)
|
||||||||||
Revenues
|
|
|
|
|
|
|
||||||
Natural gas, NGLs and crude oil sales
|
|
$
|
4,456
|
|
|
$
|
27,552
|
|
|
$
|
11,130
|
|
Sales from natural gas marketing
|
|
—
|
|
|
—
|
|
|
3,328
|
|
|||
Well operations, pipeline income and other
|
|
34
|
|
|
128
|
|
|
560
|
|
|||
Total revenues
|
|
4,490
|
|
|
27,680
|
|
|
15,018
|
|
|||
|
|
|
|
|
|
|
||||||
Costs, expenses and other
|
|
|
|
|
|
|
||||||
Production costs
|
|
1,668
|
|
|
8,365
|
|
|
4,215
|
|
|||
Cost of natural gas marketing
|
|
—
|
|
|
—
|
|
|
3,265
|
|
|||
Impairment of natural gas and crude oil properties
|
|
—
|
|
|
—
|
|
|
4,666
|
|
|||
Depreciation, depletion and amortization
|
|
—
|
|
|
6,247
|
|
|
2,967
|
|
|||
Accretion of asset retirement obligations and other
|
|
—
|
|
|
200
|
|
|
223
|
|
|||
Gain on sale of properties and equipment
|
|
(19,920
|
)
|
|
(3,854
|
)
|
|
—
|
|
|||
Total costs, expenses and other
|
|
(18,252
|
)
|
|
10,958
|
|
|
15,336
|
|
|||
|
|
|
|
|
|
|
||||||
Income (loss) from discontinued operations
|
|
22,742
|
|
|
16,722
|
|
|
(318
|
)
|
|||
Provision for income taxes
|
|
(8,668
|
)
|
|
(6,363
|
)
|
|
214
|
|
|||
Income (loss) from discontinued operations, net of tax
|
|
$
|
14,074
|
|
|
$
|
10,359
|
|
|
$
|
(104
|
)
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||||||||
|
|
Merit (1)
|
|
Seneca-Upshur
|
|
2003/2002-D Partnerships
|
|
2005 Partnerships
|
|
Permian
|
|
2004
Partnerships |
||||||||||||
|
|
(in thousands)
|
||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total acquisition cost
|
|
$
|
304,643
|
|
|
$
|
69,618
|
|
|
$
|
29,960
|
|
|
$
|
43,015
|
|
|
$
|
114,273
|
|
|
$
|
34,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets acquired:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas and crude oil properties - proved
|
|
$
|
180,259
|
|
|
$
|
20,175
|
|
|
$
|
27,940
|
|
|
$
|
39,825
|
|
|
$
|
45,592
|
|
|
$
|
32,730
|
|
Natural gas and crude oil properties - unproved
|
|
151,428
|
|
|
49,100
|
|
|
—
|
|
|
—
|
|
|
71,647
|
|
|
—
|
|
||||||
Other assets
|
|
3,631
|
|
|
10,196
|
|
|
3,455
|
|
|
3,848
|
|
|
—
|
|
|
3,396
|
|
||||||
Total assets acquired
|
|
335,318
|
|
|
79,471
|
|
|
31,395
|
|
|
43,673
|
|
|
117,239
|
|
|
36,126
|
|
||||||
Liabilities assumed:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Asset retirement obligation
|
|
13,870
|
|
|
8,157
|
|
|
497
|
|
|
300
|
|
|
2,351
|
|
|
912
|
|
||||||
Other accrued expenses
|
|
10,100
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
615
|
|
|
126
|
|
||||||
Other liabilities
|
|
6,705
|
|
|
1,696
|
|
|
938
|
|
|
358
|
|
|
—
|
|
|
320
|
|
||||||
Total liabilities assumed
|
|
30,675
|
|
|
9,853
|
|
|
1,435
|
|
|
658
|
|
|
2,966
|
|
|
1,358
|
|
||||||
Total identifiable net assets acquired
|
|
$
|
304,643
|
|
|
$
|
69,618
|
|
|
$
|
29,960
|
|
|
$
|
43,015
|
|
|
$
|
114,273
|
|
|
$
|
34,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in thousands, except per share amounts)
|
||||||
|
|
|
|
||||
Total revenues
|
$
|
370,488
|
|
|
$
|
438,204
|
|
Total costs, expenses and other
|
521,178
|
|
|
366,120
|
|
||
Net income (loss)
|
$
|
(119,343
|
)
|
|
$
|
45,688
|
|
|
|
|
|
||||
Earnings per share:
|
|
|
|
||||
Basic
|
$
|
(4.31
|
)
|
|
$
|
1.94
|
|
Diluted
|
$
|
(4.31
|
)
|
|
$
|
1.91
|
|
|
As of/Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
PDCM:
|
|
|
|
|
|
||||||
Sales from natural gas marketing
|
$
|
11,105
|
|
|
$
|
9,735
|
|
|
$
|
4,298
|
|
Cost of natural gas marketing
|
10,888
|
|
|
9,544
|
|
|
4,214
|
|
|||
Affiliated Partnerships:
|
|
|
|
|
|
||||||
Sales from natural gas marketing
|
535
|
|
|
1,276
|
|
|
651
|
|
|||
Cost of natural gas marketing
|
524
|
|
|
1,251
|
|
|
638
|
|
|||
Receivable from affiliates
|
2,140
|
|
|
6,163
|
|
|
14,616
|
|
|||
Payable to affiliates
|
4,707
|
|
|
14,152
|
|
|
20,342
|
|
|||
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
Statement of Operations Line Item
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
|
||||||
Production Costs
|
|
$
|
3,945
|
|
|
$
|
3,441
|
|
|
$
|
3,862
|
|
Exploration Expense
|
|
492
|
|
|
430
|
|
|
883
|
|
|||
General and Administrative Expense
|
|
1,630
|
|
|
1,543
|
|
|
1,899
|
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
Year Ended December 31,
|
|
|
|
|
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Oil and Gas Exploration and Production
|
$
|
309,054
|
|
|
$
|
329,541
|
|
|
$
|
273,950
|
|
Gas Marketing
|
47,079
|
|
|
66,419
|
|
|
69,071
|
|
|||
Total Revenues
|
$
|
356,133
|
|
|
$
|
395,960
|
|
|
$
|
343,021
|
|
|
|
|
|
|
|
||||||
Segment income (loss) from continuing operations before income taxes:
|
|
|
|
|
|
||||||
Oil and Gas Exploration and Production
|
$
|
(96,293
|
)
|
|
$
|
106,832
|
|
|
$
|
84,387
|
|
Gas Marketing
|
528
|
|
|
954
|
|
|
1,063
|
|
|||
Unallocated
|
(137,856
|
)
|
|
(104,891
|
)
|
|
(78,760
|
)
|
|||
Total
|
$
|
(233,621
|
)
|
|
$
|
2,895
|
|
|
$
|
6,690
|
|
|
|
|
|
|
|
||||||
Expenditures for segment long-lived assets:
|
|
|
|
|
|
||||||
Oil and Gas Exploration and Production
|
$
|
656,443
|
|
|
$
|
479,027
|
|
|
$
|
319,268
|
|
Unallocated
|
3,509
|
|
|
1,363
|
|
|
1,506
|
|
|||
Total
|
$
|
659,952
|
|
|
$
|
480,390
|
|
|
$
|
320,774
|
|
|
|
|
|
|
|
||||||
As of December 31,
|
|
|
|
|
|
||||||
Segment assets:
|
|
|
|
|
|
||||||
Oil and Gas Exploration and Production
|
$
|
1,723,011
|
|
|
$
|
1,461,130
|
|
|
|
||
Gas Marketing
|
11,090
|
|
|
14,713
|
|
|
|
||||
Unallocated
|
92,747
|
|
|
73,913
|
|
|
|
||||
Assets held for sale
|
—
|
|
|
148,249
|
|
|
|
||||
Total Assets
|
$
|
1,826,848
|
|
|
$
|
1,698,005
|
|
|
|
||
|
|
|
|
|
|
|
|
Price Used to Estimate Reserves
|
||||||||||
As of December 31,
|
|
Natural Gas
(per Mcf)
|
|
NGLs
(per Bbl)
|
|
Crude Oil
(per Bbl)
|
||||||
|
|
|
|
|
|
|
||||||
2012
|
|
$
|
2.35
|
|
|
$
|
28.02
|
|
|
$
|
87.51
|
|
2011
|
|
3.41
|
|
|
39.59
|
|
|
88.94
|
|
|||
2010
|
|
3.54
|
|
|
34.12
|
|
|
71.95
|
|
|
Natural Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Crude Oil, Condensate (MBbls)
|
|
Total
(MMcfe)
|
||||
Proved Reserves:
|
|
|
|
|
|
|
|
||||
Proved reserves, January 1, 2010
|
608,925
|
|
|
—
|
|
|
18,070
|
|
|
717,345
|
|
Revisions of previous estimates
|
6,504
|
|
|
8,908
|
|
|
(85
|
)
|
|
59,442
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
||||
Western Operating Region
|
56,524
|
|
|
811
|
|
|
2,247
|
|
|
74,872
|
|
Eastern Operating Region
|
35,092
|
|
|
—
|
|
|
—
|
|
|
35,092
|
|
Purchases of reserves
|
|
|
|
|
|
|
|
||||
Western Operating Region
|
20,920
|
|
|
1,531
|
|
|
4,367
|
|
|
56,308
|
|
Eastern Operating Region
|
220
|
|
|
—
|
|
|
—
|
|
|
220
|
|
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dispositions
|
(43,690
|
)
|
|
—
|
|
|
(55
|
)
|
|
(44,020
|
)
|
Production
|
(27,189
|
)
|
|
(601
|
)
|
|
(1,308
|
)
|
|
(38,643
|
)
|
Proved reserves, December 31, 2010
|
657,306
|
|
|
10,649
|
|
|
23,236
|
|
|
860,616
|
|
Revisions of previous estimates
|
(161,654
|
)
|
|
3,163
|
|
|
(1,904
|
)
|
|
(154,100
|
)
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
||||
Western Operating Region
|
125,374
|
|
|
5,633
|
|
|
17,092
|
|
|
261,724
|
|
Eastern Operating Region
|
51,315
|
|
|
—
|
|
|
—
|
|
|
51,315
|
|
Purchases of reserves
|
|
|
|
|
|
|
|
||||
Western Operating Region
|
24,776
|
|
|
1,052
|
|
|
1,581
|
|
|
40,574
|
|
Eastern Operating Region
|
7,985
|
|
|
—
|
|
|
24
|
|
|
8,129
|
|
Dispositions
|
(2,070
|
)
|
|
(94
|
)
|
|
(435
|
)
|
|
(5,244
|
)
|
Production
|
(30,887
|
)
|
|
(815
|
)
|
|
(1,958
|
)
|
|
(47,525
|
)
|
Proved reserves, December 31, 2011 (1)
|
672,145
|
|
|
19,588
|
|
|
37,636
|
|
|
1,015,489
|
|
Revisions of previous estimates
|
(289,436
|
)
|
|
(3,671
|
)
|
|
(6,729
|
)
|
|
(351,836
|
)
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
Western Operating Region
|
116,205
|
|
|
11,637
|
|
|
27,482
|
|
|
350,919
|
|
Eastern Operating Region
|
56,728
|
|
|
—
|
|
|
—
|
|
|
56,728
|
|
Purchases of reserves
|
|
|
|
|
|
|
|
|
|
|
|
Western Operating Region
|
87,189
|
|
|
8,084
|
|
|
10,801
|
|
|
200,499
|
|
Eastern Operating Region
|
23
|
|
|
—
|
|
|
—
|
|
|
23
|
|
Dispositions
|
(6,406
|
)
|
|
(1,970
|
)
|
|
(7,854
|
)
|
|
(65,350
|
)
|
Production
|
(32,410
|
)
|
|
(841
|
)
|
|
(2,026
|
)
|
|
(49,612
|
)
|
Proved reserves, December 31, 2012 (2)
|
604,038
|
|
|
32,827
|
|
|
59,310
|
|
|
1,156,860
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves, as of:
|
|
|
|
|
|
|
|
||||
January 1, 2010
|
258,375
|
|
|
—
|
|
|
6,244
|
|
|
295,839
|
|
December 31, 2010
|
227,341
|
|
|
4,013
|
|
|
8,287
|
|
|
301,141
|
|
December 31, 2011 (1)
|
299,369
|
|
|
11,753
|
|
|
16,910
|
|
|
471,347
|
|
December 31, 2012 (2)
|
281,925
|
|
|
14,353
|
|
|
20,412
|
|
|
490,515
|
|
Proved Undeveloped Reserves, as of:
|
|
|
|
|
|
|
|
||||
January 1, 2010
|
350,550
|
|
|
—
|
|
|
11,826
|
|
|
421,506
|
|
December 31, 2010
|
429,965
|
|
|
6,636
|
|
|
14,949
|
|
|
559,475
|
|
December 31, 2011 (1)
|
372,776
|
|
|
7,835
|
|
|
20,726
|
|
|
544,142
|
|
December 31, 2012 (2)
|
322,113
|
|
|
18,474
|
|
|
38,898
|
|
|
666,345
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes estimated reserve data related to our Permian asset group, which was held for sale and under a purchase and sale agreement. The divestiture of our Permian assets closed on February 28, 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian asset group. Total proved reserves included
6,242
MMcf of natural gas,
7,825
MBbls of crude oil and
1,970
MBbls of NGLs, for an aggregate of
65,018
MMcfe of natural gas equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included
1,750
MMcf,
1,815
MBbls,
550
MBbls and
15,940
MMcfe, respectively, and proved undeveloped reserves included
4,492
MMcf,
6,010
MBbls,
1,420
MBbls and
49,078
MMcfe, respectively.
|
(2)
|
Includes estimated reserve data related to our Piceance and NECO assets, which are expected to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. Total proved reserves
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|||
|
(MMcfe)
|
|||||||
|
|
|
|
|
|
|||
Beginning proved reserves, January 1, 2011
|
301,141
|
|
|
559,475
|
|
|
860,616
|
|
Undeveloped reserves converted to developed
|
43,597
|
|
|
(43,597
|
)
|
|
—
|
|
Revisions of previous estimates
|
73,643
|
|
|
(227,743
|
)
|
|
(154,100
|
)
|
Extensions, discoveries and other additions
|
58,979
|
|
|
254,060
|
|
|
313,039
|
|
Purchases of reserves
|
46,756
|
|
|
1,947
|
|
|
48,703
|
|
Dispositions
|
(5,244
|
)
|
|
—
|
|
|
(5,244
|
)
|
Production
|
(47,525
|
)
|
|
—
|
|
|
(47,525
|
)
|
Ending proved reserves, December 31, 2011
|
471,347
|
|
|
544,142
|
|
|
1,015,489
|
|
Undeveloped reserves converted to developed
|
45,929
|
|
|
(45,929
|
)
|
|
—
|
|
Revisions of previous estimates
|
(109,909
|
)
|
|
(241,927
|
)
|
|
(351,836
|
)
|
Extensions, discoveries and other additions
|
67,787
|
|
|
339,860
|
|
|
407,647
|
|
Purchases of reserves
|
81,253
|
|
|
119,269
|
|
|
200,522
|
|
Dispositions
|
(16,280
|
)
|
|
(49,070
|
)
|
|
(65,350
|
)
|
Production
|
(49,612
|
)
|
|
—
|
|
|
(49,612
|
)
|
Ending proved reserves, December 31, 2012
|
490,515
|
|
|
666,345
|
|
|
1,156,860
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
Revenue:
|
|
|
|
|
|
||||||
Natural gas, NGLs and crude oil sales
|
$
|
274,783
|
|
|
$
|
304,157
|
|
|
$
|
216,159
|
|
Commodity price risk management gain, net
|
32,339
|
|
|
46,090
|
|
|
59,891
|
|
|||
|
307,122
|
|
|
350,247
|
|
|
276,050
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Production costs
|
77,537
|
|
|
75,717
|
|
|
60,121
|
|
|||
Exploration expense
|
22,605
|
|
|
6,289
|
|
|
20,291
|
|
|||
Impairment of proved natural gas and oil properties
|
162,287
|
|
|
25,159
|
|
|
4,666
|
|
|||
Depreciation, depletion, and amortization
|
146,879
|
|
|
128,458
|
|
|
103,303
|
|
|||
Accretion of asset retirement obligations
|
4,060
|
|
|
1,897
|
|
|
1,423
|
|
|||
Gain on sale of properties and equipment
|
(24,273
|
)
|
|
(4,050
|
)
|
|
(174
|
)
|
|||
|
389,095
|
|
|
233,470
|
|
|
189,630
|
|
|||
Results of operations for natural gas and crude oil producing
activities before provision for income taxes |
(81,973
|
)
|
|
116,777
|
|
|
86,420
|
|
|||
|
|
|
|
|
|
||||||
Provision for income taxes
|
31,163
|
|
|
(36,785
|
)
|
|
(5,937
|
)
|
|||
|
|
|
|
|
|
||||||
Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs
|
$
|
(50,810
|
)
|
|
$
|
79,992
|
|
|
$
|
80,483
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
Acquisition of properties: (1)
|
|
|
|
|
|
||||||
Proved properties
|
$
|
105,303
|
|
|
$
|
79,554
|
|
|
$
|
87,241
|
|
Unproved properties
|
276,225
|
|
|
95,081
|
|
|
84,636
|
|
|||
Development costs (2)
|
233,144
|
|
|
301,008
|
|
|
138,018
|
|
|||
Exploration costs: (3)
|
|
|
|
|
|
||||||
Exploratory drilling
|
18,803
|
|
|
3,626
|
|
|
21,223
|
|
|||
Geological and geophysical
|
1,925
|
|
|
1,846
|
|
|
2,367
|
|
|||
Total costs incurred
|
$
|
635,400
|
|
|
$
|
481,115
|
|
|
$
|
333,485
|
|
|
|
|
|
|
|
(1)
|
Property acquisition costs
- represent costs incurred to purchase, lease or otherwise acquire a property.
|
(2)
|
Development costs
- represents 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 natural gas, NGLs and crude oil. Of these costs incurred for the years ended
December 31, 2012
,
2011
and
2010
,
$62.0 million
,
$80.6 million
and
$37.4 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 natural gas, NGLs and crude oil.
|
|
As of December 31,
|
||||||
|
2012
|
|
2011
|
||||
|
(in thousands)
|
||||||
|
|
|
|
||||
Proved natural gas and crude oil properties
|
$
|
2,075,924
|
|
|
$
|
1,694,847
|
|
Unproved natural gas and crude oil properties
|
319,327
|
|
|
102,466
|
|
||
Capitalized costs
|
2,395,251
|
|
|
1,797,313
|
|
||
Less accumulated DD&A
|
(905,458
|
)
|
|
(621,074
|
)
|
||
Capitalized costs, net
|
$
|
1,489,793
|
|
|
$
|
1,176,239
|
|
|
|
|
|
|
As of December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Future estimated cash flows
|
$
|
7,529,292
|
|
|
$
|
6,415,255
|
|
|
$
|
4,361,095
|
|
Future estimated production costs
|
(1,690,453
|
)
|
|
(1,704,645
|
)
|
|
(1,418,044
|
)
|
|||
Future estimated development costs
|
(1,852,177
|
)
|
|
(1,474,137
|
)
|
|
(1,119,604
|
)
|
|||
Future estimated income tax expense
|
(1,230,294
|
)
|
|
(946,849
|
)
|
|
(508,805
|
)
|
|||
Future net cash flows
|
2,756,368
|
|
|
2,289,624
|
|
|
1,314,642
|
|
|||
10% annual discount for estimated timing of cash flows
|
(1,587,871
|
)
|
|
(1,348,415
|
)
|
|
(826,224
|
)
|
|||
Standardized measure of discounted future estimated net cash flows
|
$
|
1,168,497
|
|
|
$
|
941,209
|
|
|
$
|
488,418
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
|
(in thousands)
|
||||||||||
|
|
|
|
|
|
||||||
Sales of natural gas, NGLs and crude oil production, net of production costs
|
$
|
(194,346
|
)
|
|
$
|
(226,227
|
)
|
|
$
|
(163,104
|
)
|
Net changes in prices and production costs (1)
|
95,501
|
|
|
383,293
|
|
|
180,124
|
|
|||
Extensions, discoveries, and improved recovery, less related costs (2)
|
632,781
|
|
|
467,347
|
|
|
88,637
|
|
|||
Sales of reserves (3)
|
(86,902
|
)
|
|
(4,224
|
)
|
|
(24,174
|
)
|
|||
Purchases of reserves (4)
|
296,208
|
|
|
64,761
|
|
|
45,538
|
|
|||
Development costs incurred during the period
|
69,198
|
|
|
94,941
|
|
|
44,491
|
|
|||
Revisions of previous quantity estimates (5)
|
(452,775
|
)
|
|
(112,468
|
)
|
|
47,884
|
|
|||
Changes in estimated income taxes (6)
|
(131,256
|
)
|
|
(204,377
|
)
|
|
(105,557
|
)
|
|||
Net changes in future development costs
|
(3,979
|
)
|
|
(29,827
|
)
|
|
(41,595
|
)
|
|||
Accretion of discount
|
124,105
|
|
|
65,284
|
|
|
35,951
|
|
|||
Timing and other
|
(121,247
|
)
|
|
(45,712
|
)
|
|
32,587
|
|
|||
Total
|
$
|
227,288
|
|
|
$
|
452,791
|
|
|
$
|
140,782
|
|
|
|
|
|
|
|
(1)
|
Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Mcfe, in our 2012 reserve report increased to
$3.45
from
$3.19
resulting from our increase in liquids as a percentage of total proved reserves. Our weighted-average price, net of production costs per Mcfe, in our 2010 reserve report was
$2.12
.
|
(2)
|
The
35%
increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 407,647 MMcfe, a
30%
increase,
52.2%
of which was gas and
47.8%
was liquids. Approximately
86%
of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program. The changes in extensions, discoveries and improved recovery, less related costs, were
427%
higher in 2011 as compared to 2010. At December 31, 2010, extensions, discoveries and other additions were 109,964 MMcfe,
83.3%
of which was gas and
16.7%
of which was liquids. At December 31, 2011, extensions, discoveries and other additions had increased to 313,039 MMcfe, a
185%
increase,
56.4%
of which was gas and
43.6%
was liquids. This change was a result of our shifting of focus from gas-rich projects to liquid-rich projects. In 2011, we focused primarily on the liquids-rich Wattenberg Field in northern Colorado, where we drilled
17
horizontal Niobrara wells and
80
vertical wells, completed
190
zones and participated in
48
non-operated drilling projects. 2011 was the first year that horizontal Niobrara PUDs were included in our year-end reserves. All of these projects are liquid-rich and, with the exception of the vertical wells and refractures, these reserves were not recognized at December 31, 2010. As a result, approximately two-thirds of the 427% increase is related to additional volumes included in our reserve report in 2011 over those included in 2010 and one-third of the increase is related to the per Mcfe value increase of those additional volume of reserves.
|
(3)
|
The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012.
|
(4)
|
The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field in northern Colorado.
|
(5)
|
The decrease in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule. The decrease in 2011 as compared to 2010 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments for geological reasons, offset in part by improvements in asset performance.
|
(6)
|
The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately
38.2%
,
38.1%
and
38%
for the year ended December 31, 2012, 2011 and 2010, respectively. In addition, the company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital,additional current year capital or future development capital.
|
|
2012
|
||||||||||||||||||
|
Quarter Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Year Ended
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas, NGLs and crude oil sales
|
$
|
75,310
|
|
|
$
|
56,879
|
|
|
$
|
59,915
|
|
|
$
|
78,223
|
|
|
$
|
270,327
|
|
Sales from natural gas marketing
|
11,834
|
|
|
8,917
|
|
|
11,570
|
|
|
14,758
|
|
|
47,079
|
|
|||||
Commodity price risk management gain (loss), net
|
11,501
|
|
|
38,729
|
|
|
(31,943
|
)
|
|
14,052
|
|
|
32,339
|
|
|||||
Well operations, pipeline income and other
|
1,701
|
|
|
1,520
|
|
|
1,639
|
|
|
1,528
|
|
|
6,388
|
|
|||||
Total revenues
|
100,346
|
|
|
106,045
|
|
|
41,181
|
|
|
108,561
|
|
|
356,133
|
|
|||||
Costs, expenses and other:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production costs
|
18,370
|
|
|
18,055
|
|
|
20,756
|
|
|
18,304
|
|
|
75,485
|
|
|||||
Cost of natural gas marketing
|
11,492
|
|
|
8,761
|
|
|
11,598
|
|
|
14,701
|
|
|
46,552
|
|
|||||
Exploration expense
|
2,063
|
|
|
2,570
|
|
|
1,969
|
|
|
16,003
|
|
|
22,605
|
|
|||||
Impairment of natural gas and crude oil properties
|
653
|
|
|
370
|
|
|
395
|
|
|
166,731
|
|
|
168,149
|
|
|||||
General and administrative expense
|
14,708
|
|
|
14,378
|
|
|
13,710
|
|
|
16,019
|
|
|
58,815
|
|
|||||
Depreciation, depletion and amortization
|
39,814
|
|
|
34,448
|
|
|
32,483
|
|
|
40,134
|
|
|
146,879
|
|
|||||
Accretion of asset retirement obligations
|
819
|
|
|
825
|
|
|
1,195
|
|
|
1,221
|
|
|
4,060
|
|
|||||
Gain on sale of properties and equipment
|
(154
|
)
|
|
(2,246
|
)
|
|
(1,508
|
)
|
|
(445
|
)
|
|
(4,353
|
)
|
|||||
Total costs, expenses and other
|
87,765
|
|
|
77,161
|
|
|
80,598
|
|
|
272,668
|
|
|
518,192
|
|
|||||
Income (loss) from operations
|
12,581
|
|
|
28,884
|
|
|
(39,417
|
)
|
|
(164,107
|
)
|
|
(162,059
|
)
|
|||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(23,283
|
)
|
|
(23,283
|
)
|
|||||
Interest expense
|
(10,444
|
)
|
|
(10,053
|
)
|
|
(11,360
|
)
|
|
(16,430
|
)
|
|
(48,287
|
)
|
|||||
Interest income
|
2
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
8
|
|
|||||
Income (loss) from continuing operations before income taxes
|
2,139
|
|
|
18,831
|
|
|
(50,774
|
)
|
|
(203,817
|
)
|
|
(233,621
|
)
|
|||||
Provision for income taxes
|
(759
|
)
|
|
(6,179
|
)
|
|
18,131
|
|
|
77,642
|
|
|
88,835
|
|
|||||
Income (loss) from continuing operations
|
1,380
|
|
|
12,652
|
|
|
(32,643
|
)
|
|
(126,175
|
)
|
|
(144,786
|
)
|
|||||
Income (loss) from discontinued operations, net of tax
|
14,455
|
|
|
(381
|
)
|
|
—
|
|
|
—
|
|
|
14,074
|
|
|||||
Net income (loss)
|
$
|
15,835
|
|
|
$
|
12,271
|
|
|
$
|
(32,643
|
)
|
|
$
|
(126,175
|
)
|
|
$
|
(130,712
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
0.06
|
|
|
$
|
0.48
|
|
|
$
|
(1.08
|
)
|
|
$
|
(4.17
|
)
|
|
$
|
(5.23
|
)
|
Income (loss) from discontinued operations
|
0.61
|
|
|
(0.02
|
)
|
|
—
|
|
|
—
|
|
|
0.51
|
|
|||||
Net income (loss)
|
$
|
0.67
|
|
|
$
|
0.46
|
|
|
$
|
(1.08
|
)
|
|
$
|
(4.17
|
)
|
|
$
|
(4.72
|
)
|
Diluted
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
0.06
|
|
|
$
|
0.47
|
|
|
$
|
(1.08
|
)
|
|
$
|
(4.17
|
)
|
|
$
|
(5.23
|
)
|
Income (loss) from discontinued operations
|
0.60
|
|
|
(0.01
|
)
|
|
—
|
|
|
—
|
|
|
0.51
|
|
|||||
Net income (loss)
|
$
|
0.66
|
|
|
$
|
0.46
|
|
|
$
|
(1.08
|
)
|
|
$
|
(4.17
|
)
|
|
$
|
(4.72
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
23,609
|
|
|
26,597
|
|
|
30,214
|
|
|
30,233
|
|
|
27,677
|
|
|||||
Diluted
|
23,889
|
|
|
26,728
|
|
|
30,214
|
|
|
30,233
|
|
|
27,677
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
2011
|
||||||||||||||||||
|
Quarter Ended
|
|
|
||||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Year Ended
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas, NGLs and crude oil sales
|
$
|
58,810
|
|
|
$
|
65,762
|
|
|
$
|
72,044
|
|
|
$
|
79,989
|
|
|
$
|
276,605
|
|
Sales from natural gas marketing
|
15,202
|
|
|
18,897
|
|
|
17,209
|
|
|
15,111
|
|
|
66,419
|
|
|||||
Commodity price risk management gain (loss), net
|
(23,882
|
)
|
|
20,537
|
|
|
46,706
|
|
|
2,729
|
|
|
46,090
|
|
|||||
Well operations, pipeline income and other
|
1,843
|
|
|
1,755
|
|
|
1,670
|
|
|
1,578
|
|
|
6,846
|
|
|||||
Total revenues
|
51,973
|
|
|
106,951
|
|
|
137,629
|
|
|
99,407
|
|
|
395,960
|
|
|||||
Costs, expenses and other:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production costs
|
18,117
|
|
|
16,537
|
|
|
13,644
|
|
|
19,054
|
|
|
67,352
|
|
|||||
Cost of natural gas marketing
|
14,993
|
|
|
18,207
|
|
|
17,227
|
|
|
15,038
|
|
|
65,465
|
|
|||||
Exploration expense
|
1,669
|
|
|
1,215
|
|
|
1,135
|
|
|
2,234
|
|
|
6,253
|
|
|||||
Impairment of natural gas and crude oil properties
|
453
|
|
|
499
|
|
|
531
|
|
|
23,676
|
|
|
25,159
|
|
|||||
General and administrative expense
|
13,873
|
|
|
19,509
|
|
|
13,683
|
|
|
14,389
|
|
|
61,454
|
|
|||||
Depreciation, depletion and amortization
|
30,985
|
|
|
30,592
|
|
|
31,523
|
|
|
35,807
|
|
|
128,907
|
|
|||||
Accretion of asset retirement obligations
|
355
|
|
|
358
|
|
|
372
|
|
|
648
|
|
|
1,733
|
|
|||||
Gain on sale of properties and equipment
|
—
|
|
|
—
|
|
|
(32
|
)
|
|
(164
|
)
|
|
(196
|
)
|
|||||
Total costs, expenses and other
|
80,445
|
|
|
86,917
|
|
|
78,083
|
|
|
110,682
|
|
|
356,127
|
|
|||||
Income (loss) from operations
|
(28,472
|
)
|
|
20,034
|
|
|
59,546
|
|
|
(11,275
|
)
|
|
39,833
|
|
|||||
Interest expense
|
(9,062
|
)
|
|
(9,067
|
)
|
|
(9,496
|
)
|
|
(9,360
|
)
|
|
(36,985
|
)
|
|||||
Interest income
|
9
|
|
|
2
|
|
|
36
|
|
|
—
|
|
|
47
|
|
|||||
Income (loss) from continuing operations before income taxes
|
(37,525
|
)
|
|
10,969
|
|
|
50,086
|
|
|
(20,635
|
)
|
|
2,895
|
|
|||||
Provision for income taxes
|
14,278
|
|
|
(2,804
|
)
|
|
(19,218
|
)
|
|
7,927
|
|
|
183
|
|
|||||
Income (loss) from continuing operations
|
(23,247
|
)
|
|
8,165
|
|
|
30,868
|
|
|
(12,708
|
)
|
|
3,078
|
|
|||||
Income from discontinued operations, net of tax
|
3,323
|
|
|
1,000
|
|
|
1,692
|
|
|
4,344
|
|
|
10,359
|
|
|||||
Net income (loss)
|
(19,924
|
)
|
|
9,165
|
|
|
32,560
|
|
|
(8,364
|
)
|
|
13,437
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings per share:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(0.99
|
)
|
|
$
|
0.35
|
|
|
$
|
1.31
|
|
|
$
|
(0.54
|
)
|
|
$
|
0.13
|
|
Income from discontinued operations
|
0.14
|
|
|
0.04
|
|
|
0.07
|
|
|
0.19
|
|
|
0.44
|
|
|||||
Net income (loss) attributable to shareholders
|
$
|
(0.85
|
)
|
|
$
|
0.39
|
|
|
$
|
1.38
|
|
|
$
|
(0.35
|
)
|
|
$
|
0.57
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(0.99
|
)
|
|
$
|
0.34
|
|
|
$
|
1.30
|
|
|
$
|
(0.54
|
)
|
|
$
|
0.13
|
|
Income from discontinued operations
|
0.14
|
|
|
0.04
|
|
|
0.07
|
|
|
0.19
|
|
|
0.43
|
|
|||||
Net income (loss) attributable to shareholders
|
$
|
(0.85
|
)
|
|
$
|
0.38
|
|
|
$
|
1.37
|
|
|
$
|
(0.35
|
)
|
|
$
|
0.56
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
23,428
|
|
|
23,491
|
|
|
23,569
|
|
|
23,592
|
|
|
23,521
|
|
|||||
Diluted
|
23,428
|
|
|
23,723
|
|
|
23,783
|
|
|
23,592
|
|
|
23,871
|
|
|||||
|
|
|
|
|
|
|
|
|
|
Description
|
|
Beginning
Balance January 1 |
|
Deconsolidation/Purchase Price Adjustment for PDCM
|
|
Charged to
Costs and Expenses |
|
Deductions (1)
|
|
Ending
Balance December 31 |
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2012:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
|
$
|
921
|
|
|
$
|
—
|
|
|
$
|
258
|
|
|
$
|
153
|
|
|
$
|
1,026
|
|
Valuation allowance for unproved natural gas and crude oil properties
|
|
12,204
|
|
|
—
|
|
|
4,207
|
|
|
8,375
|
|
|
8,036
|
|
|||||
2011:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
|
686
|
|
|
121
|
|
|
135
|
|
|
21
|
|
|
921
|
|
|||||
Valuation allowance for unproved natural gas and crude oil properties
|
|
16,996
|
|
|
260
|
|
|
2,611
|
|
|
7,143
|
|
|
12,204
|
|
|||||
2010:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful accounts
|
|
548
|
|
|
135
|
|
|
307
|
|
|
34
|
|
|
686
|
|
|||||
Valuation allowance for state tax benefits
|
|
747
|
|
|
—
|
|
|
—
|
|
|
747
|
|
|
—
|
|
|||||
Valuation allowance for unproved natural gas and crude oil properties
|
|
15,001
|
|
|
19
|
|
|
6,120
|
|
|
4,106
|
|
|
16,996
|
|
(1)
|
For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved natural gas and crude oil properties, deductions represent accumulated amortization of expired or abandoned unproved natural gas and crude oil properties. For valuation allowance for state tax benefits, deductions represent expired or unutilized state tax benefits.
|
•
|
If the Company is ranked number 1, 200% of the Target Award
|
•
|
If the Company is ranked at the 75
th
percentile of the Peer Companies, including the Company, 150% of the Target Award
|
•
|
If the Company is ranked at the 50
th
percentile or median of the Peer Companies, including the Company, 100% of the Target Award
|
•
|
If the Company is ranked at the 25
th
percentile of the Peer Companies, including the Company, 50% of the Target Award
|
•
|
If the Company is ranked below the 25
th
percentile of the Peer Companies, including the Company, no award will be paid
|
•
|
Berry Petroleum Company
|
•
|
Bill Barrett Corporation
|
•
|
Carrizo Oil & Gas, Inc.
|
•
|
Comstock Resources, Inc.
|
•
|
EXCO Resources, Inc.
|
•
|
Forest Oil Corporation
|
•
|
Goodrich Petroleum Corporation
|
•
|
Laredo Petroleum Holdings, Inc.
|
•
|
Magnum Hunter Resources Corp.
|
•
|
Penn Virginia Corp.
|
•
|
PetroQuest Energy, Inc.
|
•
|
Quicksilver Resources, Inc.
|
•
|
Resolute Energy Corporation
|
•
|
Rosetta Resources Inc.
|
•
|
Stone Energy Corporation
|
•
|
Swift Energy Company
|
•
|
______ Shares of Restricted Stock of the Company; and
|
•
|
______ Stock Appreciation Rights (“SARs”) of the Company.
|
Number of Shares
|
Vesting Date
|
|
1/16/2014
|
|
1/16/2015
|
|
1/16/2016
|
Number of SARs Vested
|
Vesting Date
|
|
1/16/2014
|
|
1/16/2015
|
|
1/16/2016
|
|
|
|
|
|
|
|
|
|
|
Exhibit 12.1
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
PDC ENERGY, INC.
|
||||||||||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
|
|
(dollars in thousands)
|
||||||||||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
(233,621
|
)
|
|
$
|
2,895
|
|
|
$
|
6,690
|
|
|
$
|
(125,172
|
)
|
|
$
|
163,168
|
|
Fixed charges (see below)
|
|
51,542
|
|
|
40,511
|
|
|
35,197
|
|
|
39,403
|
|
|
31,629
|
|
|||||
Amortization of capitalized interest
|
|
906
|
|
|
676
|
|
|
788
|
|
|
991
|
|
|
744
|
|
|||||
Interest capitalized
|
|
(1,238
|
)
|
|
(1,544
|
)
|
|
(301
|
)
|
|
(751
|
)
|
|
(2,618
|
)
|
|||||
Total adjusted earnings (loss) available for fixed charges
|
|
$
|
(182,411
|
)
|
|
$
|
42,538
|
|
|
$
|
42,374
|
|
|
$
|
(85,529
|
)
|
|
$
|
192,923
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest and debt expense (a)
|
|
$
|
48,287
|
|
|
$
|
36,985
|
|
|
$
|
33,250
|
|
|
$
|
37,208
|
|
|
$
|
28,132
|
|
Interest capitalized
|
|
1,238
|
|
|
1,544
|
|
|
301
|
|
|
751
|
|
|
2,618
|
|
|||||
Interest component of rental expense (b)
|
|
2,017
|
|
|
1,982
|
|
|
1,646
|
|
|
1,444
|
|
|
879
|
|
|||||
Total fixed charges
|
|
$
|
51,542
|
|
|
$
|
40,511
|
|
|
$
|
35,197
|
|
|
$
|
39,403
|
|
|
$
|
31,629
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
(c)
|
1.1x
|
|
|
1.2x
|
|
|
—
|
|
(c)
|
6.1x
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
(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, 2012 and December 2009, earnings were insufficient to cover total fixed charges by
$234 million
and
$124.9 million
.
|
|
\s\Ryder Scott Company, L.P.
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
TBPE Firm Registration No. F-1580
|
|
|
Denver, CO
|
|
February 27, 2013
|
|
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 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 and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor 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 27, 2013
|
|
/s/ James M. Trimble
|
|
|
|
James M. Trimble
|
|
|
|
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 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 and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditor 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 27, 2013
|
|
/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/ James M. Trimble
|
|
February 27, 2013
|
James M. Trimble
|
|
|
President and Chief Executive Officer
|
|
|
|
|
|
|
|
|
/s/ Gysle R. Shellum
|
|
February 27, 2013
|
Gysle R. Shellum
|
|
|
Chief Financial Officer
|
|
|
As of December 31, 2012
|
||||||||||||||||
|
|
Proved
|
||||||||||||||
|
|
Developed
|
|
|
|
Total
|
||||||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
||||||||
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate - Barrels
|
|
13,361,504
|
|
|
7,050,769
|
|
|
38,897,922
|
|
|
59,310,195
|
|
||||
Plant Products - Barrels
|
|
7,750,560
|
|
|
6,602,600
|
|
|
18,474,035
|
|
|
32,827,195
|
|
||||
Gas - MMCF
|
|
211,842
|
|
|
70,082
|
|
|
322,113
|
|
|
604,037
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data M$
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
$
|
1,827,569
|
|
|
$
|
955,275
|
|
|
$
|
4,640,201
|
|
|
$
|
7,423,045
|
|
Deductions
|
|
709,145
|
|
|
392,712
|
|
|
2,334,526
|
|
|
3,436,383
|
|
||||
Future Net Income (FNI)
|
|
$
|
1,118,424
|
|
|
$
|
562,563
|
|
|
$
|
2,305,675
|
|
|
$
|
3,986,662
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
$
|
715,607
|
|
|
$
|
241,572
|
|
|
$
|
751,677
|
|
|
$
|
1,708,856
|
|
|
|
Discounted Future Net Income - M$
|
||||
|
|
As of December 31, 2012
|
||||
Discount Rate Percent
|
|
|
Total Proved
|
|
||
|
|
|
|
|
||
5
|
|
|
$
|
2,494,351
|
|
|
15
|
|
|
$
|
1,243,369
|
|
|
20
|
|
|
$
|
944,147
|
|
|
25
|
|
|
$
|
740,276
|
|
|
Geographic
Area
|
Product
|
Price
Reference
|
Avg Benchmark
Prices
|
Avg Realized
Prices
|
North America
|
|
|
|
|
United States
|
Oil/Condensate
|
WTI Cushing
|
$94.71/Bbl
|
$87.51/Bbl
|
|
NGLs
|
WTI Cushing
|
$94.71/Bbl
|
$28.02/Bbl
|
|
Gas
|
Henry Hub
|
$2.76/MMBTU
|
$2.35/MCF
|