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•	changes in production volumes and worldwide demand, including economic conditions that might impact demand;

•	volatility of commodity prices for natural gas, NGLs and crude oil;

•	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;

•	potential declines in the values of our natural gas and crude oil properties resulting in impairments;

•	changes in estimates of proved reserves;

•	inaccuracy of reserve estimates and expected production rates;

•	potential for production decline rates from our wells to be greater than expected;

•	timing and extent of our success in discovering, acquiring, developing and producing reserves;

•	our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;

•	timing and receipt of necessary regulatory permits;

•	risks incidental to the drilling and operation of natural gas and crude oil wells;

•	our future cash flows, liquidity and financial condition;

•	competition in the oil and gas industry;

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•	availability and cost of capital to us;

•	reductions in the borrowing base under our revolving credit facility;

•	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;

•	our success in marketing natural gas, NGLs and crude oil;

•	effect of natural gas and crude oil derivatives activities;

•	impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events;

•	cost of pending or future litigation;

•	effect that acquisitions we may pursue have on our capital expenditures;

•	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;

•	our ability to retain or attract senior management and key technical employees; and

•	success of strategic plans, expectations and objectives for future operations of the Company.

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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.

•

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%.

•

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.

•

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.

•	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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•	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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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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•	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.

•	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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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.

•	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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•	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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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.

•

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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(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.

(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.

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(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.

(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.

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(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.

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•	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.

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•	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.

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•	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.

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•	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.

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•	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.

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•	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.

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•	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.

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•

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.

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•	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.

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(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.

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(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.

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*	Percentage change is not meaningful or equal to or greater than 300%.

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(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.

(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.

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(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.

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(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.

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•	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.

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(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.

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(1)	Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

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•	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.

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(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.

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•	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.

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(1)	Includes $2 million as of December 31, 2011 related to assets held for sale.

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(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

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(1)	Property acquisition costs - represent costs incurred to purchase, lease or otherwise acquire a property.

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(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.

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(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.

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(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.