Exhibit 99.1








ITEM 6. SELECTED FINANCIAL DATA





Year Ended December 31,20122011201020092008(in millions, except per share data and as noted)Statement of Operations:Natural gas, NGLs and crude oil sales$238.4$223.3$146.0$115.8$200.8Commodity price risk management gain (loss), net32.346.159.9(10.1)127.8Total revenues320.6337.3276.6169.6455.7Income (loss) from continuing operations(21.7)22.618.1(62.8)91.2Earnings per share from continuing operationsBasic$(0.78)$0.96$0.94$(3.71)$6.20Diluted(0.78)0.950.92(3.71)6.15Statement of Cash Flows:Net cash from:Operating activities$174.7$166.8$151.8$143.9$139.1Investing activities(451.9)(456.4)(300.9)(142.3)(323.0)Financing activities271.4243.4171.5(20.6)150.1Capital expenditures347.7334.5162.7143.0323.2Acquisitions of natural gas and crude oil properties312.2145.9158.1——Balance Sheet:Total assets$1,826.8$1,698.0$1,389.0$1,250.3$1,402.7Working capital (deficit)(31.4)(22.0)16.232.931.3Long-term debt676.6532.2295.7280.7394.9Total equity703.2664.1642.2538.6512.3Pricing and Lifting Costs Relating to Continuing Operations (per Mcfe):Average sales price (excluding gains/losses on derivatives)$7.24$8.06$7.35$5.69$10.56Average lifting cost (1)0.830.830.690.711.13Production (Bcfe):Production from continuing operations32.927.720.320.419.4Production from discontinued operations17.119.818.322.919.3Total production50.047.538.643.338.7Total proved reserves (Bcfe) (2) (3)1,156.91,015.5860.6717.3753.1


______________


|    |                                                                                                   
|--- | --------------------------------------------------------------------------------------------------
|(1) | Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Includes total proved reserves related to our Piceance and NECO assets of84.5Bcfe as of December 31, 2012. Our Piceance and NECO assets were divested pursuant to a purchase and sale agreement entered into on February 4, 2013. The divestiture closed onJune 18, 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details related to the divestiture of our Piceance and NECO assets.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | 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 Exhibit 99.1 for additional details related to the divestiture of our Permian assets.




1


---







ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS





The following discussion and analysis, as well as other sections in this Exhibit 99.1, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included elsewhere in this Exhibit 99.1. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of the 2012 Form 10-K.





EXECUTIVE SUMMARY





2012 Financial Overview





In 2012, our natural gas, NGLs and crude oil production from continuing operations averaged 90.0 MMcfe per day, an increase of approximately 18.6% compared to the prior year. The increase in production is primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field and the Merit Acquisition. Crude oil production from continuing operations increased 18.6% in 2012, while NGL production from continuing operations increased 17.6% . Our liquids percentage of total production from continuing operations was 51.5% in 2012. Natural gas production increased 19.6% in 2012 compared to 2011. As discussed under "Operational Overview-Production" below, production growth in 2012 was adversely affected by high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure, primarily experienced during the second and third quarters, was the result of two primary factors: a series of operational issues experienced by the third-party midstream service provider facilities and abnormally warm weather. While natural gas production increased when compared to prior year, significant declines in the average price of natural gas during 2012 resulted in a decrease in natural gas sales, excluding hedges, of 14.8% year-over-year. The price of natural gas, however, rebounded significantly during the fourth quarter of 2012. While the significant decrease in natural gas prices from prior years has impacted our results of operations, we believe our derivative program was effective in providing a degree of price stability.





Available liquidity as of December 31, 2012 was $398.6 million , including $14.1 million through our joint venture PDCM, compared to $196.4 million, including $16.6 million related to PDCM, as of December 31, 2011. Available liquidity is comprised of cash, cash equivalents and funds available under our revolving credit facility. In May 2012, we completed a public offering of 6.5 million shares of our common stock for net proceeds of approximately $164.5 million, after deducting underwriting discounts and offering expenses. These funds were used to complete the Merit Acquisition noted below. In October 2012, we issued $500 million aggregate principal amount of our 2022 Senior Notes in a private placement. The net proceeds from the issuance of the notes of approximately $489 million were used to fund the redemption of our 2018 Senior Notes for a total redemption price of approximately $222 million, repay a portion of the amount outstanding under our revolving credit facility and for general corporate purposes. The early redemption of the 2018 Senior Notes resulted in a pre-tax loss on debt extinguishment of approximately $23.3 million. On October 31, 2012, we completed the semi-annual redetermination of our revolving credit facility's borrowing base. Our available borrowing base was reduced from $525 million to $450 million as a result of issuance of our 2022 Senior Notes.





Operational Overview





Acquisitions. We continued to make strides in 2012 toward our strategic goal of growing production while increasing our mix of crude oil and natural gas liquids. In June, we completed the Merit Acquisition for cash consideration of approximately $304.6 million , after certain post-closing adjustments. The acquired assets comprise approximately 29,800 net acres, after post-closing adjustments, located almost entirely in the core Wattenberg Field and with significant overlay with our existing acreage position. Ryder Scott prepared a reserve report with respect to the Merit Acquisition properties and estimated net proved reserves of 29.2 MMBoe (175 Bcfe) based on our development plan, using year-end 2011 SEC pricing and an effective date of April 1, 2012. Following the closing of the Merit Acquisition, our total position in the core Wattenberg Field was approximately 98,600 net acres.





Drilling Activities. During 2012, we continued to focus our operations primarily in the oil- and liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in Ohio. We currently have two drilling rigs operating in the Wattenberg Field. We drilled 37 horizontal wells and one vertical well in the Wattenberg Field in 2012, of which 30 were completed and turned-in-line as of December 31, 2012 , and we participated in 19 non-operated drilling projects. We also executed 160 refracture and/or recompletion projects on 83 wells in the Wattenberg Field. The shift in the Wattenberg Field from drilling both vertical and horizontal wells to our current program of drilling horizontal wells has resulted in significantly fewer wells being drilled at a considerably higher cost per well and higher production and reserves per well. The remaining activity in our Western Operating Region in 2012 was the first quarter completion of our final three Piceance wells drilled in 2011.





In our Eastern Operating Region, we drilled and completed two horizontal Utica wells during the year. At December 31, 2012 , these wells are currently shut-in awaiting pipeline connections. We also drilled and completed one vertical Utica stratigraphic test well and completed one vertical Utica stratigraphic test well drilled in late 2011. In 2012, the costs related to the two vertical stratigraphic test wells were expensed at a cost of $12.2 million. We currently plan to continue to de-risk and develop our approximate 45,000 net acres without materially adding to our leasehold position. We estimate our total gross horizontal Utica Shale drilling inventory to be approximately 200 locations. In addition, PDCM drilled three horizontal Marcellus wells in 2012, all of which were completed and turned-in-line during the year.





Natural Gas and Crude Oil Properties Divestitures. In October 2011, we announced our intent to divest our Permian Basin assets to focus our efforts on our horizontal drilling programs. During the fourth quarter of 2011, we sold certain non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement with another unrelated third-party for the sale of our core Permian assets for a total price of $173.9 million, subject to customary post-closing adjustments. On February 28, 2012, the divestiture of the core Permian assets closed. Upon final post-closing adjustments on June 29, 2012, total proceeds received for the core


2


---




Permian assets was $189.2 million, resulting in a pre-tax gain on sale of $19.9 million. The proceeds from these sales were used to pay down amounts outstanding under our revolving credit facility and to provide partial funding for our 2012 capital budget. The results of operations related to our Permian Basin assets are reported as discontinued operations for all applicable periods presented in the accompanying statements of operations included elsewhere in this Exhibit 99.1.





Piceance Basin and NECO Divestiture. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including certain derivatives. On June 18, 2013 , this divestiture was completed with total proceeds received of approximately $185.2 million , subject to customary post-closing adjustme nts and net of our non-affiliated investor partners' share of $17.0 million . We intend to use the proceeds from the sale to repay a portion of amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. The assets sold do not include any of our core Wattenberg Field acreage. As of December 31, 2012, total estimated proved reserves related to these assets were 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 84,544 Mmcfe of natural gas equivalent. See Note 14 , Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details related to the divestiture of our Piceance and NECO assets.





Production. Production from continuing operations increased significantly in 2012 as compared to 2011. Primarily as a result of our Wattenberg Field drilling activities, oil production from continuing operations increased 18.6% and NGL production from continuing operations increased 17.6% . This production growth was achieved despite high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure was the result of a series of operational issues experienced by third-party midstream service provider, primarily during the second and third quarter of 2012. The operational issues included downtime on third-party NGL transportation and fractionation facilities and abnormally warm weather, which limited the gathering system compression capacity. We are working closely with this primary midstream provider who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, we do not expect the impact of this increased capacity to substantially benefit us until late 2013.





Our NGL pricing has also decreased significantly relative to the same period in 2011. Our NGLs are priced at Conway, Kansas, where ethane and propane are valued at a significant discount to Mt. Belvieu gulf coast NGL pricing. The planned 2013 infrastructure projects include a new NGL pipeline that will provide direct access for our NGLs to Mt. Belvieu where we anticipate improved pricing.





Non-U.S. GAAP Financial Measures





We use "adjusted cash flows from operations," "adjusted net income (loss) attributable to shareholders," "adjusted EBITDA" and "PV-10%," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing or financing activities, and should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure.





3


---




Results of Operations





Summary Operating Results





The following table presents selected information regarding our operating results from continuing operations:


Year Ended December 31,Change2012201120102012-20112011-2010(dollars in millions, except per unit data)Production (1)Natural gas (MMcf)15,988.613,370.19,755.619.6%37.1%NGLs (MBbls)837.3712.1561.117.6%26.9%Crude oil (MBbls)1,987.81,675.71,196.218.6%40.1%Natural gas equivalent (per Mcfe) (2)32,939.727,697.320,299.818.9%36.4%Average MMcfe per day90.075.955.618.6%36.5%Natural Gas, NGLs and Crude Oil SalesNatural gas$42.0$49.3$37.9(14.8)%30.1%NGLs22.926.822.2(15.4)%20.4%Crude oil173.5147.289.217.9%65.0%Provision for underpayment of natural gas sales——(3.3)—%(100.0)%Total natural gas, NGLs and crude oil sales$238.4$223.3$146.06.8%52.9%Realized Gain (Losses) on Derivatives, net (3)Natural gas$49.9$29.1$40.071.5%(27.3)%Crude oil(0.5)(11.9)7.1(95.8)%(267.6)%Total realized gain on derivatives, net$49.4$17.2$47.1187.2%(63.5)%Average Sales Price (excluding gain/loss on derivatives)Natural gas (per Mcf)$2.63$3.74$3.89(29.7)%(3.9)%NGLs (per Bbl)27.3337.5039.56(27.1)%(5.2)%Crude oil (per Bbl)87.2787.4474.54(0.2)%17.3%Natural gas equivalent (per Mcfe)7.248.067.35(10.2)%9.7%Average Lifting Cost (per Mcfe) (4)Western operating region$0.71$0.73$0.56(2.7)%30.4%Eastern operating region1.381.331.553.8%(14.2)%Weighted-average0.830.830.69—%20.3%Natural Gas Marketing Contribution Margin (5)$0.4$0.7$0.5(42.9)%40.0%Other Costs and ExpensesExploration expense$20.9$5.7$9.2264.4%(37.7)%Impairment of natural gas and crude oil properties5.92.34.4156.2%(47.3)%General and administrative expense58.861.542.2(4.3)%45.7%Depreciation, depletion, and amortization98.887.666.112.7%32.5%Loss on extinguishment of debt$23.3$—$—100.0%—%Interest Expense$48.3$37.0$33.330.6%11.2%


Amounts may not recalculate due to rounding.


______________


|    |                                                                                                                                                                                                                                                                                       
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 Item 6, Selected Financial Data included in this Exhibit 99.1.

|    |                                                           
|--- | ----------------------------------------------------------
|(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.




4


---




Natural Gas, NGLs and Crude Oil Sales





The following tables present natural gas, NGLs and crude oil production and weighted-average sales price for continuing operations:


Year Ended December 31,ChangeProduction by Operating Region2012201120102012-20112011-2010Natural gas (MMcf)Western - Wattenberg Field9,844.78,980.27,229.69.6%24.2%Eastern - Appalachian Basin6,143.94,389.92,526.040.0%73.8%Total15,988.613,370.19,755.619.6%37.1%Crude oil (MBbls)Western - Wattenberg Field1,979.11,670.91,190.318.4%40.4%Eastern - Appalachian Basin8.74.85.981.3%(18.6)%Total1,987.81,675.71,196.218.6%40.1%NGLs (MBbls)Western - Wattenberg Field837.3712.1561.117.6%26.9%Natural gas equivalent (MMcfe)Western - Wattenberg Field26,743.623,278.417,738.414.9%31.2%Eastern - Appalachian Basin6,196.14,418.92,561.440.2%72.5%Total32,939.727,697.320,299.818.9%36.4%





Amounts may not recalculate due to rounding.





Year Ended December 31,Average Sales Price by Operating RegionChange(excluding gain/loss on derivatives)2012201120102012-20112011-2010Natural gas (per Mcf)Western - Wattenberg Field$2.61$3.55$3.70(26.5)%(4.1)%Eastern - Appalachian Basin2.664.154.44(35.9)%(6.5)%Weighted-average price2.633.743.89(29.7)%(3.9)%Crude oil (per Bbl)Western - Wattenberg Field87.2787.4274.53(0.2)%17.3%Eastern - Appalachian Basin87.1795.8677.10(9.1)%24.3%Weighted-average price87.2787.4474.54(0.2)%17.3%NGLs (per Bbl)Western - Wattenberg Field27.3337.6239.56(27.4)%(4.9)%Natural gas equivalent (per Mcfe)Western - Wattenberg Field8.278.797.76(5.9)%13.3%Eastern - Appalachian Basin2.764.234.55(34.8)%(7.0)%Weighted-average price7.248.067.35(10.2)%9.7%





Amounts may not recalculate due to rounding.





5


---




The year-over-year change in natural gas, NGLs and crude oil sales revenue were primarily due to the following:


Year Ended December 31,20122011(in millions)Increase in production$41.8$55.7Decrease in average natural gas price(17.9)(1.9)Decrease in average NGL price(8.5)(1.5)Increase (decrease) in average crude oil price(0.3)21.6Decrease in provision for underpayment of natural gas sales—3.3Total increase in natural gas, NGLs and crude oil sales revenue$15.1$77.2





Natural gas, NGLs and crude oil sales revenue in 2012 increased 6.8% compared to 2011. The increase was primarily attributable to significantly higher volumes sold, in particular liquids, which resulted in a liquids percentage of total production of approximately 51.5% in 2012 . The increase was offset in part by the 29.7% and 27.1% declines in the average price of natural gas and NGLs, respectively, during 2012. Our average daily sales volumes increased to 90.0 MMcfe per day in 2012 compared to 75.9 MMcfe per day in 2011, primarily due to the success of the horizontal Niobrara and Codell drilling program in the Wattenberg Field and the Merit Acquisition. For December 2012, our average production exit rate from continuing operations was 83 MMcfe per day compared to 92 MMcfe per day in December 2011.





The increase in 2011 production compared to 2010 was directly attributable to an increase in production in our Western Operating Region of 15.2 MMcfe per day as a result of increased drilling in the Wattenberg field, as well as a 5.1 MMcfe per day increase in production in our Eastern Operating Region associated with our Marcellus wells. The 2011 increase in production was directly attributable to our decision to increase our capital expenditures for new wells drilled in 2010 and 2011 and switching a majority of our drilling program from vertical to horizontal wells in the Niobrara formation and Marcellus Shale.





Natural Gas, NGLs and Crude Oil Pricing. Our results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and our ability to market our production effectively. Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on our financial results and capital expenditures.





Natural gas prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. The combination of increased drilling activity and curtailments due to limited capacity on local gathering and processing infrastructure resulted in capacity constraints during the second and third quarters of 2012, primarily in our Wattenberg Field. Like most producers, we rely on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond our control. The price we receive for our natural gas is impacted by our transportation, gathering and processing agreements. We currently use the "net-back" method of accounting for these arrangements related to our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.





The price we receive for our natural gas produced in our Western Operating Region is based on a market basket of prices, which generally includes natural gas sold at, near or below Colorado Interstate Gas ("CIG") prices, as well as other nearby regional prices. In September 2012, we renegotiated our marketing agreement for our natural gas in the Piceance Basin, which added approximately $0.40 per MMbtu to our Piceance natural gas price realization, effective with November 1 production. We have experienced a decline in the price of NGLs, mainly at Conway hub in Kansas where our Wattenberg production is marketed. This is primarily due to the increase in ethane and propane volumes flowing to Conway with a limited market for these products out of the area. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of our crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing.





6


---




Production Costs





Production costs include lease operating expenses, production taxes and certain production and engineering staff-related overhead costs, as well as other costs to operate wells and pipelines as follows:





Year Ended December 31,201220112010(in millions)Lease operating expenses (1)$27.4$23.0$14.0Production taxes15.214.98.1Cost of well operations, overhead and other production expenses12.16.97.8Total production costs$54.7$44.8$29.9Total production costs per Mcfe$1.66$1.62$1.47


______________


|    |                                                                                                                                                                                                                                                                                                                                                       
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 $1.4 million and $1.0 million, respectively.




Lease operating expenses. Lifting costs per Mcfe were $0.83 , $0.83 and $0.69 for 2012, 2011 and 2010, respectively. The 20.3% increase in lifting costs per Mcfe in 2011 from 2010 was primarily due to an increase in lease operating expenses, mainly attributable to the Seneca-Upshur acquisition, which exceeded the increased production on a percentage basis. The increase in lease operating expenses in 2012 compared to 2011 was primarily related to the 18.9% increase in production, including an increase in production-related expenses in the amount of $7.4 million mostly related to the Merit Acquisition and the Seneca-Upshur acquisition, offset by a decrease in environmental compliance costs of $2.6 million due to the completion of many environmental projects during 2011. The increase in lease operating expenses in 2011 compared to 2010 was primarily related to the 36.4% increase in production, including an increase in production-related expenses of $8.0 million mostly related to the Seneca-Upshur acquisition and other production-related expenses.





Production taxes. Production taxes fluctuate with natural gas, NGLs and crude oil sales. The $0.3 million , or 2% , increase in production taxes for 2012 compared to 2011 is primarily related to a combination of increased total natural gas and NGL sales and, to a lesser extent, a change in the production tax rate due to a change in the mix of production locations. The $6.8 million , or 84.0% , increase in production taxes for 2011 compared to 2010 was primarily related to the 49.6% increase in natural gas, NGLs and crude oil sales and, to a lesser extent, higher ad valorem rates in certain Colorado counties.





Overhead and other production expenses. Overhead and other production expenses increased $5.2 million in 2012 compared to 2011. The increase consisted of a $3.2 million oil inventory expense in 2012 associated with the Merit Acquisition and an increase of $2.0 million of prepaid well costs charged to expense in 2012 as a result of changes in our capital spending plan. Overhead and other production expenses decreased $0.9 million in 2011 compared to 2010. The decrease related to reductions in costs incurred for the wells and pipeline systems we operate on behalf of our affiliated partnerships and other third parties as a result of our acquisition of 12 affiliated partnerships.





Commodity Price Risk Management, Net





Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our natural gas and crude oil production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details of our derivative financial instruments.


7


---







The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net:





Year Ended December 31,201220112010(in millions)Commodity price risk management gain (loss), net:Realized gains (losses):Natural gas$49.9$29.1$40.0Crude oil(0.5)(11.9)7.1Total realized gains, net49.417.247.1Unrealized gains (losses):Reclassification of realized gains included in prior periods unrealized(28.8)(10.3)(20.1)Unrealized gains for the period11.739.232.9Total unrealized gains (losses), net(17.1)28.912.8Total commodity price risk management gain, net$32.3$46.1$59.9





Realized gains recognized in 2012 are primarily the result of lower natural gas prices at settlement compared to the respective strike price of our natural gas derivative positions. Realized gains on natural gas, exclusive of basis swaps, were $66.5 million reflective of a weighted-average strike price of $5.36 compared to a weighted-average settlement price of $2.86. These gains were offset in part by realized losses of $16.6 million on our basis swap positions as the negative basis differential between NYMEX and CIG was a weighted-average of $0.21 compared to a weighted-average strike price of $1.82. The realized gains on natural gas derivative positions in 2012 were offset in part by realized losses on our crude oil positions as a result of higher prices at settlement compared to the respective strike price of our derivative positions. For 2012, the realized losses were reflective of a weighted-average strike price of $93.33 compared to a weighted-average settlement price of $93.72.





Unrealized gains in 2012 were primarily related to the downward shift in the crude oil and natural gas forward curve and its impact on the fair value of our open positions, offset in part by the narrowing of the CIG basis forward curve. During 2012, unrealized gains on our crude oil and natural gas positions were $9.4 million and $2.9 million, respectively, offset slightly by unrealized losses on our CIG basis swaps of $0.6 million.





Realized gains recognized in 2011 were mainly the result of lower natural gas prices at settlement compared to the respective strike price, resulting in a $44 million realized gain on our natural gas derivatives. These realized gains were offset in part by realized losses of $14.9 million on our basis swap positions and realized losses on our crude oil positions. During 2011, we recorded unrealized gains of $46.1 million on our natural gas positions offset in part by unrealized losses of $3.9 million on our crude oil positions and $3 million on our CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow.





During 2010, realized gains recognized were the result of lower natural gas and crude oil prices at settlement compared to the respective strike price, offset in part by a $12.1 million realized loss due to the negative basis differential between NYMEX and CIG being narrower than the strike price of our derivative position. During 2010, we recorded unrealized gains of $47.3 million on our natural gas positions offset in part by unrealized losses of $10.6 million on our crude oil positions and $3.8 million on our CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow.





We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our physical natural gas and crude oil at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this Exhibit 99.1 and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2012.





Natural Gas Marketing





Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices and realized and unrealized, mark-to-market adjustments, gains and losses on open derivative positions, and, to a lesser extent, volumes sold and purchased.





8


---




The following table presents the components of sales from and costs of natural gas marketing:





Year Ended December 31,201220112010(in millions)Natural gas sales revenue$44.9$60.7$59.4Realized derivative gains, net2.23.06.4Unrealized derivative losses, net(1.7)(0.2)(0.6)Total sales from natural gas marketing45.463.565.2Costs of natural gas purchases43.359.058.1Realized derivative losses, net2.02.65.9Unrealized derivative losses (gains), net(1.6)0.1(0.5)Other1.31.11.2Total costs of natural gas marketing45.062.864.7Natural gas marketing contribution margin$0.4$0.7$0.5





The decrease in natural gas sales revenue and costs of natural gas purchases in 2012 compared to 2011 is primarily attributable to a 34% decrease in the average natural gas price, offset in part by a 11% increase in volumes. The increase in natural gas sales revenue and costs of natural gas purchases in 2011 compared to 2010 is primarily attributable to a 10% increase in volumes, offset in part by an 8% decrease in the average natural gas price.





Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this Exhibit 99.1 and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and detailed presentation of our derivative positions as of December 31, 2012 .





Exploration Expense





The following table presents the major components of exploration expense:





Year Ended December 31,201220112010(in millions)Exploratory dry hole costs$14.5$0.1$0.3Geological and geophysical costs1.91.82.2Operating, personnel and other4.53.86.7Total exploration expense$20.9$5.7$9.2





Exploratory dry hole costs. In 2012, two vertical stratigraphic test wells in eastern Ohio were expensed at a cost of $12.2 million.  Additionally, three wells in south central Ohio were determined to have found noncommercial quantities of hydrocarbons and were expensed at a cost of $1.2 million.





Operating, personnel and other . The $0.7 million increase in 2012 compared to 2011 is mainly attributable to a $2 million increase in payroll and employee benefits in the exploration division as a result of increased employee headcount in the Utica Shale, offset in part by a $0.7 million decrease in PDCM's lease prospecting costs. The decrease in operating, personnel and other in 2011 compared to 2010 was primarily related to a $3.9 million reduction in personnel costs resulting from the reassignment of former exploration department personnel during the first quarter of 2011 to development drilling or administrative activities, offset in part by a $1.1 million increase in PDCM's lease prospecting costs.





9


---




Impairment of Natural Gas and Crude Oil Properties





The following table sets forth the major components of our impairments of natural gas and crude oil properties expense:


Year Ended December 31,201220112010(in millions)Impairment of individually significant unproved properties$1.6$1.1$1.5Amortization of individually insignificant unproved properties4.31.22.9Total impairment of natural gas and crude oil properties$5.9$2.3$4.4





The increase in amortization of individually insignificant unproved properties in 2012 compared to 2011 was mostly attributable to $2.4 million in lease amortization expense related to increased insignificant leases acquired in the Merit Acquisition and $1.6 million in insignificant leases written off in Ohio related to non-Utica leases in 2012.  The decrease in amortization of individually insignificant unproved properties in 2011 compared to 2010 was mostly attributable to $2.5 million in lease amortization expense related to non-Marcellus acreage in the Appalachian basin in 2010.





General and Administrative Expense





General and administrative expense for 2012 decreased by $2.6 million , or 4.3% , compared to 2011. The decrease is mainly attributable to a $6.7 million charge recognized in 2011 related to the separation agreement with our former chief executive officer, a $1.6 million charge to legal fees recorded in 2011 related to the settlement agreement reached with regard to our West Virginia royalty lawsuit and a $1.6 million decrease in professional and consulting fees during 2012. These decreases were offset in part by an increase in payroll and employee benefits of $7.5 million in 2012.





General and administrative expense for 2011 increased by $19.3 million, or 45.7%, compared to 2010. The increase was primarily due to an increase in payroll and payroll-related expense of $13.8 million, of which $6.7 million was related to a separation agreement with a former chief executive officer. The increase in payroll and payroll-related expenses was also impacted by the reassignment of former exploration department personnel contributing $3.7 million to the increase, with the remaining increase in payroll and payroll-related expenses being attributable to new hires and an overall increase in employee benefits. Also contributing to the increase was a $1.6 million charge related to the settlement reached with regard to our West Virginia royalty lawsuit.





Depreciation, Depletion and Amortization





Natural gas and crude oil properties. Depreciation, Depletion and Amortization ("DD&A") expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A related to natural gas and crude oil properties was $94.1 million in 2012 compared to $83.6 million in 2011. The increase in 2012 compared to 2011 was comprised of $15.8 million due to higher production offset in part by $5.3 million due to a lower weighted-average depreciation, depletion and amortization rate.





The following table presents our DD&A rates for natural gas and crude oil properties:





Year Ended December 31,Operating Region/Area201220112010(per Mcfe)WesternWattenberg Field$3.07$3.21$3.08EasternMarcellus Shale and other1.932.002.57Total weighted-average2.863.023.02





Non-natural gas and crude oil properties. Depreciation expense for non-natural gas and crude oil properties was $4.7 million for 2012 compared to $4.0 million for 2011 and $4.9 million for 2010.





Accretion of Asset Retirement Obligations





Accretion of asset retirement obligations ("ARO") for 2012 increased by $2.3 million , or 163.7% , compared to 2011 . The increase in 2012 is primarily attributable to the increase in ARO liability associated with the properties acquired in the Merit Acquisition in 2012 and the Seneca-Upshur acquisition in 2011. Accretion of ARO for 2011 increased by $0.4 million , or 33.9% , compared to 2010. The increase in 2011 is primarily attributable to the increase in ARO liability associated with the Seneca-Upshur acquisition in the fourth quarter of 2011.





10


---




Gain on Sale of Properties and Equipment





The 2012 increase in the gain on sale of properties and equipment of $4.2 million as compared to 2011 mainly relates to our proportionate share of the gain realized from PDCM's sale of certain leases in our Eastern Operating Region. The gain on sale of properties and equipment in 2011 and 2010 was not material.





Interest Expense





Interest expense increased by approximately $11.3 million in 2012 compared to 2011 . Approximately $6 million of the increase is related to the issuance of the 2022 Senior Notes and the result of incurring interest on both the 2022 Senior Notes and 2018 Senior Notes during the month of October. Additionally, approximately $3.6 million of the increase was the result of higher average borrowings on our revolving credit facility during 2012 as compared to 2011 and $1.1 million due to higher debt issuance amortization expense. The increase in interest expense in 2011 compared to 2010 was attributable to $6 million of interest and amortization of debt discount related to our convertible notes issued in November 2010. The increase was offset in part by a decrease in debt issuance costs of $1.5 million and an increase in capitalized interest of $1.4 million. Interest costs capitalized in 2012, 2011 and 2010 were $1.2 million , $1.7 million and $0.3 million , respectively.





Loss on Extinguishment of Debt





The $23.3 million pre-tax loss on extinguishment of debt relates to the redemption of the 2018 Senior Notes during the fourth quarter of 2012. The pre-tax loss consists of an $18.9 million make-whole premium and the write-off of both unamortized debt discount of $1.5 million and unamortized debt issuance costs of $2.9 million .





Provision for Income Taxes





The effective tax rate ("rate") on loss from continuing operations in 2012 was a 36.9% benefit, which reflects a small benefit for the percentage depletion deduction. The 2011 provision on income rate of 34.3% was also favorably impacted by our deduction for percentage depletion, as well as a $0.6 million tax benefit related to a reduction of the accrual for uncertain tax positions, offset by the adjustment to the estimated state deferred rate. The 2010 rate of 30.7% was also favorably impacted by our deduction for percentage depletion, as well as a $1.7 million discrete tax benefit related to our state deferred rate change. Excluding the effect of discrete items, our 2012, 2011 and 2010 rates were 38.0%, 34.9% and 37.0%, respectively. See Note 7, Income Taxes , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for our rate reconciliation for each of the three years in the three-year period ended December 31, 2012 .





Beginning with our 2010 tax year, we were accepted into and have agreed to participate in the IRS Compliance Assurance Process ("CAP") program. As part of this program, we agreed to an accelerated timeline for the IRS examination of our 2007, 2008 and 2009 tax years. This examination was completed during the second quarter of 2011 without any significant increase or decrease in tax expense. See Note 7, Income Taxes , to the accompanying consolidated financial statements included elsewhere in this Exhibit 99.1 for a discussion regarding the reduction of our uncertain tax liability due to the conclusion of this examination. Our 2011 CAP reviewed return was filed in September 2012. The IRS subsequently accepted our return without change. We are currently participating in the CAP program review of our 2012 tax year and have accepted an offer for continued participation in the IRS CAP program for our 2013 tax year.





Discontinued Operations





Piceance Basin and NECO. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including certain derivatives. On June 18, 2013 , this divestiture was completed with total proceeds received of approximately $185.2 million , subject to customary post-closing adjustme nts and net of our non-affiliated investor partners' share of $17.0 million . Following the sale, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been reported as discontinued operations for all periods presented in the accompanying consolidated statements of operations included in this Exhibit 99.1. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for further discussion of the Piceance Basin and NECO divestiture.





Permian Basin. During the fourth quarter of 2011, we closed on the sale of our non-core Permian Basin assets to unrelated third parties for a sales price of $13.2 million. We then developed a plan to divest 100% of our core Permian Basin assets, consisting of producing wells and undeveloped leaseholds. Following the sale of our core Permian assets to the unrelated party on February 28, 2012, we do not have significant continuing involvement in the operations of or cash flows from these assets. Accordingly, the Permian Basin assets were reclassified as held for sale as of December 31, 2011 and the results of operations related to the core and non-core Permian Basin assets have been reported as discontinued operations for all periods presented in the accompanying consolidated statements of operations included in this Exhibit 99.1. Proceeds from the sale of our core Permian Basin assets were $189.2 million after closing adjustments and were received in the first quarter of 2012. The sale of our Permian Basin assets resulted in a pre-tax gain of $19.9 million . See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for further discussion of the Permian divestiture.





North Dakota. In February 2011, we executed a purchase and sale agreement for the sale of our North Dakota assets and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pre-tax gain on sale of $3.9 million. Following the sale to the unrelated party, we do not have significant continuing involvement


11


---




in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in 2010 and 2011 in our consolidated statements of operations included elsewhere in this Exhibit 99.1.





Michigan. In July 2010, we completed the sale of our Michigan assets for net proceeds of $22 million. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets. Accordingly, the results of operations related to the Michigan assets have been reported as discontinued operations in 2010 in our consolidated statements of operations included elsewhere in this Exhibit 99.1. Operating results related to these assets were immaterial to the financial statements with the following exception. In June 2010, in conjunction with our decision to divest our Michigan assets, we recorded a related pre-tax impairment charge of $4.7 million. See Note 6, Properties and Equipment , and Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional information regarding the divestiture of our Michigan assets.





For production data and operating results related to our discontinued operations, see Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this Exhibit 99.1.





Net Income (Loss) Attributable to Shareholders/Adjusted Net Income (Loss) Attributable to Shareholders





The year-over-year changes in net income (loss) attributable to shareholders are discussed above. These same reasons similarly impacted adjusted net income (loss) attributable to shareholders, a non-U.S. GAAP financial measure, with the exception of the unrealized derivative gains and losses on derivatives and provision for underpayment of natural gas sales, adjusted for taxes. Adjusted net income (loss) attributable to shareholders excludes the impact of a tax adjusted unrealized derivative gain, net, and provision for underpayment of natural gas sales of $10.6 million , $17.7 million and $5.8 million in 2012 , 2011 and 2010 , respectively. Adjusted net loss attributable to shareholders, a non-U.S. GAAP financial measure, was $120.1 million and $4.3 million in 2012 and 2011 , respectively. Adjusted net income attributable to shareholders was $0.4 million in 2010 . See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure.





Financial Condition, Liquidity and Capital Resources





Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in the debt and equity markets and asset monetization transactions. In 2012, our primary sources of liquidity were proceeds from the divestiture of our Permian assets in February 2012 for $189.2 million , $164.5 million in proceeds from the issuance of our common stock in May 2012, $489 million from the issuance of our 2022 Senior Notes in October 2012 and net cash flows from operating activities of $174.7 million .





Our primary source of cash flows from operating activities is the sale of natural gas, NGLs and crude oil. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives, which has also historically been a source of cash. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in two years or less, our debt covenants limit our holdings to 80% of our expected future production on total proved reserves (proved developed producing, proved developed not producing and proved undeveloped). For instruments that mature later than two years, but no more than our designated maximum maturity, our debt covenants limit our holdings to 80% of our expected future production from proved developed producing properties. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.





Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2012 , we had a working capital deficit of $31.4 million compared to a deficit of $22 million at December 31, 2011 .





We ended 2012 with cash and cash equivalents of $2.5 million and availability under our revolving credit facility and our proportionate share of PDCM's credit facility of $396.1 million , for a total liquidity position of $398.6 million , compared to $196.4 million at the end of 2011. The increase in liquidity of $202.2 million , or 102.9% , was primarily due to $189.2 million received from the divestiture of our Permian assets in February 2012, proceeds from issuance of common stock of $164.5 million in May 2012, proceeds from the issuance of our $500 million 2022 Senior Notes in October 2012 and cash flows from operating activities of $174.7 million , offset by $304.6 million in expenditures related to the Merit Acquisition in June 2012, capital expenditures of $347.7 million and the redemption of our $203 million 2018 Senior Notes in November 2012. Assuming that the divestiture of our Piceance and NECO assets for proceeds of approximately $185.2 million had closed as of December 31, 2012, our pro-forma liquidity, excluding any effect related to our borrowing base redetermination, would have been approximately $583.8 million .





With our current liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund operations. However, an acceleration of development activities or other changes to our business plans could increase our need for capital. We may also sell select assets from time to time in order to fund development projects, acquisitions or other capital needs.





12


---




Capital Expenditures





We establish a capital budget annually based upon our development and exploration opportunities, liquidity position and expected cash flows from operating activities. We may revise our capital budget during the year as a result of, among other things, acquisitions or dispositions of assets, drilling results, commodity prices, changes in our borrowing capacity and/or significant changes in cash flows. In December 2012, our Board of Directors approved our 2013 capital budget of $324 million , excluding our share of PDCM's capital budget. Based on our current forecast, we expect to allocate $254 million to be invested in the Wattenberg Field, of which $207 million is for developmental drilling in the horizontal Niobrara and Codell. We expect to allocate approximately $53 million to drilling, leasing and completion activity in the Utica Shale. We expect to allocate $17 million to acquisitions of properties and leased acreage, exploration and other capital needs. PDCM's 2013 capital budget is currently set at $95 million , of which $48 million represents our share, and is expected to be funded by PDCM's operating activities, its credit facility and funds received related to title defects discovered from its acquisition of Seneca-Upshur. PDCM's capital budget for 2013 includes funding for the drilling of 14 gross horizontal wells. We believe, based on the current commodity price environment, cash flows provided by operating activities, asset sales and proceeds from borrowings on our revolving credit facility will fund our 2013 capital budget.





Because natural gas and crude oil production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of natural gas, NGLs and crude oil production and cash flows from operating activities if capital markets and commodity prices were to become depressed and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future.





Financing Activities





In recent periods, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of debt and equity securities. See Note 8, Long-Term Debt , and Note 12, Common Stock , to our consolidated financial statements in this Exhibit 99.1 for a detailed discussion of our May 2012 sale of common stock and October 2012 debt issuance, respectively. We cannot, however, assure this will continue to be the case in the future. We continue to monitor market conditions and circumstances and their potential impact on each of our revolving credit facility lenders. Our revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. Our November semi-annual redetermination was completed on October 31, 2012 and resulted in the reduction of our borrowing base from $525 million to $450 million. The $75 million borrowing base reduction was principally the result of the incurrence of additional term debt in the form of the 2022 Senior Notes. Our next scheduled redetermination is in May 2013. While we expect to continue to add producing reserves through our drilling operations, these reserve additions will be offset by the sale of our Piceance and NECO assets and could be offset by other factors including, among other things, a significant decrease in commodity prices. These events could result in a negative impact on our future borrowing base redeterminations.





On January 23, 2012, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold 6.5 million shares of our common stock in May 2012 in an underwritten public offering at a price to the public of $26.50 per share. We used the net proceeds of $164.5 million to pay off the outstanding balance on our revolving credit facility and for general corporate purposes.





Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.0 times earnings before interest, taxes, depreciation, depletion and amortization, unrealized derivative gains (losses), exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of natural gas and crude oil derivative instruments. Additionally, available borrowings under our revolving credit facility are added back to the current asset calculation. The current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2012 , we were in compliance with all debt covenants with a 2.53 times debt to EBITDAX ratio and a 2.79 to 1.0 current ratio. We expect to remain in compliance throughout the next year.





The indenture governing our senior notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At December 31, 2012 , we were in compliance with all covenants and expect to remain in compliance throughout the next year.





See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk.





13


---




Cash Flows





Operating Activities. Our net cash flows from operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased in 2012 and 2011 compared to the respective prior years. In 2012 , the $7.9 million increase was mainly attributable to an increase in realized derivative gains of $31.9 million and an increase in natural gas, NGLs and crude oil sales of $15.1 million , offset by a $37.7 million loss of operating margins related to the divested Permian Basin, Piceance and NECO assets. In 2011, the $15 million increase was primarily due to an increase in natural gas, NGLs and crude oil sales of $77.2 million , offset by a decrease in realized derivative gains related to natural gas and crude oil sales of $29.9 million , an increase in production costs of $14.4 million and an increase in general and administrative expense of $19.3 million. The remaining changes in cash flows provided by operating activities were primarily due to changes in our assets and liabilities related to the timing of cash payments and receipts. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above.





Adjusted cash flows from operations, a non-U.S. GAAP financial measure, decreased in 2012 and increased in 2011 when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of our assets and liabilities.





Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $6.7 million in 2012 from 2011, primarily due to a $31.9 million increase in realized derivative gains and a $15.1 million increase in natural gas, NGLs and crude oil sales, offset in part by a $21.9 million decrease in operating margins related to the divested Permian Basin, Piceance and NECO assets and a $15.2 million increase in exploration expense. Adjusted EBITDA increased by $39.4 million in 2011 from 2010, primarily due to a $77.2 million increase in natural gas, NGLs and crude oil sales and a $23.7 million increase in operating margins related to the divested Permian Basin, Piceance and NECO assets, offset in part by a $29.9 million decrease in realized gains on derivatives, a $19.3 million increase in general and administrative expense and a $15 million increase in production costs.





See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of non-U.S. GAAP financial measures.





Investing Activities. Cash flows from investing activities primarily consist of the acquisition, exploration and development of natural gas and crude oil properties, net of dispositions of natural gas and crude oil properties. In 2012, our drilling program consisted of two rigs operating in the oil- and liquid-rich horizontal Niobrara and Codell play in our Wattenberg Field. See Part I, Operations - Drilling Activities , for additional details on our drilling activities. Our capital investment in natural gas and crude oil properties has increased significantly year-over-year as a result of our commitment to growth. Net cash used in investing activities of $451.9 million during 2012 was primarily related to the $304.6 million expended in June 2012 for the Merit Acquisition and drilling activity of $347.7 million , offset in part by $189.2 million received from the divestiture of our Permian assets in February 2012 and $28.9 million received related to title defects discovered from PDCM's Seneca-Upshur acquisition in October 2011, of which $14.5 million represents our share. In 2011, we increased our capital spending by $159.6 million, including acquisitions, over that in 2010, and sold our North Dakota assets and our non-core Permian Basin assets, receiving cash of $23.1 million. Approximately 70% of our investment spending was directed toward organic development and the remaining 30% going toward the acquisition of natural gas and crude oil properties. In 2010, as the economic condition showed signs of recovery and the differential between natural gas and liquids grew, we increased our capital spending to $320.8 million . Approximately 51% of our investment spending was directed toward organic development in our liquid-rich plays and the remaining 49% going toward the acquisition of natural gas and crude oil properties. In 2010, we sold our Michigan assets, which provided cash of $22 million.





Financing Activities. Net cash from financing activities in 2012 includes gross proceeds of $500 million from our October 2012 issuance of the 2022 Senior Notes and $164.5 million from our May 2012 sale of common stock. The net proceeds from the issuance of the 2022 Senior Notes were used to fund the redemption of our 2018 Senior Notes for a total redemption price of approximately $222 million and to repay a portion of amounts outstanding under our revolving credit facility. The proceeds from the sale of common stock were used to finance a portion of the Merit Acquisition. Cash flows provided by financing activities in 2011 were primarily comprised of net borrowings under our bank credit facility of $233.5 million to execute our capital budget. Additionally, financing cash flows include $12.5 million, representing our proportionate share of capital contributed to PDCM by our investing partner. Cash flows provided by financing activities in 2010 included gross proceeds of $132.5 million and $115 million from our November 2010 sale of common stock and issuance of convertible debt, respectively. During 2010, our investing partner in PDCM contributed $35 million, of which our proportionate share was $20.1 million. This capital raise was offset in part by the net repayment of borrowings under our bank credit facility of $80 million. See Note 8, Long-Term Debt , and Note 12, Common Stock , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for further discussion on our debt and equity offerings and the formation of our joint venture.








14


---




Contractual Obligations and Contingent Commitments





The table below presents our contractual obligations and contingent commitments, including both continuing and discontinued operations, as of December 31, 2012 .





Payments due by periodLess than1-33-5More thanContractual Obligations and Contingent CommitmentsTotal1 yearyearsyears5 years(in millions)Long-term liabilities reflected on the consolidated balance sheets (1)Long-term debt (2)$690.3$—$75.3$115.0$500.0Derivative contracts (3)28.618.56.23.9—Derivative contracts - affiliated partnerships (4)4.74.7———Production tax liability44.625.918.7——Asset retirement obligations62.61.02.52.556.6Other liabilities (5)4.90.30.90.63.1835.750.4103.6122.0559.7Commitments, contingencies and other arrangements (6)Interest on long-term debt (7)403.147.091.578.9185.7Operating leases8.52.64.30.70.9Drilling commitment0.9——0.9—Firm transportation and processing agreements (8) (9)199.325.855.444.973.2Other0.40.10.3——612.275.5151.5125.4259.8Total$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 millionin unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this Exhibit 99.1.

|    |                                                                                                                                                                                                                                                                                                
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 Exhibit 99.1. 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 Exhibit 99.1.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 millionand $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 Exhibit 99.1.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(9) | Approximately $58.8 million of our firm gathering commitments was assumed by certain affiliates of Caerus Oil and Gas LLC in accordance with the purchase and sale agreement of the Piceance and NECO assets. This divestiture closed onJune 18, 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details related to the divestiture of our Piceance and NECO assets.




As the managing general partner of 21 partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability.





For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this Exhibit 99.1. From time to time, we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity.








15


---




Critical Accounting Policies and Estimates





We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included elsewhere in this Exhibit 99.1. Our critical accounting policies and estimates are as follows:





Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves . Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves.





Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our natural gas and crude oil reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating natural gas and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income.





Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied.





The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of natural gas and crude oil properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of natural gas and crude oil properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.





We assess our natural gas and crude oil properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of natural gas and crude oil properties. The estimates of future prices may differ from current market prices of natural gas and crude oil. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our natural gas and crude oil properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.





Natural Gas, NGLs and Crude Oil Sales Revenue Recognition . Natural gas, NGLs and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our natural gas, NGLs and crude oil sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to three months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded up to two months later. Historically, differences have been immaterial.





16


---




Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:





Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.





Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.





Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.





Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.





We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.





We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant.





Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods.





The judgments used in applying the above policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates.





Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of natural gas and crude oil properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.





In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing , proved undeveloped, unproved natural gas and crude oil properties and other non-natural gas and crude oil properties. To estimate the fair values of these properties, we prepare estimates of natural gas and crude oil reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors.





17


---




We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.





Recent Accounting Standards





See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included elsewhere in this Exhibit 99.1.





Reconciliation of Non-U.S. GAAP Financial Measures





Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the Consolidated Statements of Cash Flows in this Exhibit 99.1.





Adjusted net income (loss) attributable to shareholders. We define adjusted net income (loss) attributable to shareholders as net income (loss) attributable to shareholders, plus unrealized derivative losses and provisions for underpayment of natural gas sales, less unrealized derivative gains, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss) attributable to shareholders, as well as net income (loss) attributable to shareholders. We believe it often provides more transparency into our operating trends, such as production, prices, operating costs, realized gains and losses from derivatives and related factors, without regard to changes in our net income (loss) attributable to shareholders from our mark-to-market adjustments resulting from unrealized gains and losses from derivatives. Additionally, other items, such as the provision for underpayment of natural gas sales, which are not indicative of future results, may be excluded to clearly identify operational trends.





Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus unrealized derivative loss, interest expense, net of interest income, income taxes, impairment of natural gas and crude oil properties, depreciation, depletion and amortization, accretion of asset retirement obligations and loss on debt extinguishment, less unrealized derivative gain. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by the Company and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as:





|  |                                                                          
|- | -------------------------------------------------------------------------
|• | 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.




PV-10% . We define PV-10% as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10% discount rate. We believe that PV-10% provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10% is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating the Company and our reserves. PV-10% is not intended to represent the current market value of our estimated reserves.





18


---




The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:





Year Ended December 31,201220112010(in millions)Adjusted cash flows from operations:Adjusted cash flows from operations$163.9$167.7$132.2Changes in assets and liabilities10.8(0.9)19.6Net cash from operating activities$174.7$166.8$151.8Adjusted net income (loss) attributable to shareholders:Adjusted net income (loss) attributable to shareholders$(120.1)$(4.3)$0.4Unrealized gain (loss) on derivatives, net(17.1)28.612.6Provision for underpayment of natural gas sales——(3.3)Tax effect of above adjustments6.5(10.9)(3.5)Net income (loss) attributable to shareholders$(130.7)$13.4$6.2Adjusted EBITDA to net income (loss) attributable to shareholders:Adjusted EBITDA$196.9$190.2$150.8Unrealized gain (loss) on derivatives, net(17.1)28.612.6Interest expense, net(48.3)(36.9)(33.2)Income tax provision80.2(6.2)(0.4)Impairment of natural gas and crude oil properties(168.2)(25.2)(11.1)Depreciation, depletion and amortization(146.9)(135.2)(111.1)Accretion of asset retirement obligations(4.0)(1.9)(1.4)Loss on extinguishment of debt(23.3)——Net income (loss) attributable to shareholders$(130.7)$13.4$6.2Adjusted EBITDA to net cash from operating activities:Adjusted EBITDA$196.9$190.2$150.8Interest expense, net(48.3)(36.9)(33.2)Exploratory dry hole costs15.30.24.2Stock-based compensation8.57.45.0Amortization of debt discount and issuance costs7.96.34.6(Gain) loss from sale of properties and equipment(24.3)(4.3)0.3Other7.94.80.5Changes in assets and liabilities10.8(0.9)19.6Net cash from operating activities$174.7$166.8$151.8PV-10%:PV-10%$1,708.9$1,350.3$693.1Present 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





ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK





Market-Sensitive Instruments and Risk Management





We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks.





Interest Rate Risk





Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our senior notes and convertible notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.


19


---







As of December 31, 2012 , our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of December 31, 2012 was $6.4 million with an average interest rate of 0.1%. The $6.4 million represents our aggregate bank balances, which includes checks issued and outstanding. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2012 , it was estimated that if market interest rates would have increased or decreased by 1% in 2012, the impact on our annual interest income would have been immaterial.





As of December 31, 2012 , excluding the $18.7 million irrevocable standby letters of credit, we had outstanding borrowings on our corporate bank credit facility of $49 million and, representing our proportionate share, $26.3 million on PDCM's bank credit facility. We estimate that if market interest rates would have increased or decreased by 1%, our 2012 interest expense would have changed by approximately $0.8 million .





Commodity Price Risk





We are exposed to the potential risk of loss from adverse changes in the market price of natural gas, NGLs and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and crude oil prices to be received for our hedged production as it is produced. We believe that our established derivative policies and procedures are effective in achieving our risk management objectives.





The following table presents our derivative positions (excluding the derivative positions designated to our affiliated partnerships) related to natural gas and crude oil sales in effect as of December 31, 2012 :


FloorsCollarsFixed-Price SwapsCIGBasis Protection SwapsCommodity/ Index/Maturity PeriodQuantity(BBtu)(1)Weighted-AverageContractPriceQuantity(Gas -BBtu(1)Oil - MBbls)Weighted-AverageContract PriceQuantity(Gas -BBtu(1)Oil - MBbls)Weighted-AverageContractPriceQuantity(BBtu)(1)Weighted-AverageContractPriceFair ValueDecember 31,2012 (2)(in millions)FloorsCeilingsNatural GasNYMEX20134,910.0$6.20—$—$—22,574.5$4.6223,320.7$(0.83)$23.32014—————13,390.04.038,830.0(0.22)(0.1)2015720.04.00———9,120.03.91——(2.6)2016—————7,200.03.84——(3.9)CIG2013——235.04.005.45————0.22014——1,115.04.505.674,828.04.00——1.82015———1,040.04.505.672,730.04.01——0.6PEPL2013—————990.46.18——2.8Total Natural Gas (3)5,630.02,390.060,832.932,150.722.1Crude OilNYMEX2013——1,105.680.46103.581,220.996.26——4.72014——1,032.082.83102.55360.097.36——0.62015——36.090.00106.15————0.2Total Crude Oil—2,173.61,580.9—5.5Total Natural Gas and Crude Oil$27.6


_____________


|    |                                                                          
|--- | -------------------------------------------------------------------------
|(1) | A standard unit of measurement for natural gas (one BBtuequals 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 Exhibit 99.1.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Approximately 36,546 BBtu of natural gas hedging positions were assumed by certain affiliates of Caerus Oil and Gas LLC in accordance with the purchase and sale agreement of the Piceance and NECO assets. This divestiture closed onJune 18, 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details related to the divestiture of our Piceance and NECO assets.

20


---




The following table presents annual average NYMEX and CIG closing prices for natural gas and crude oil for the years ended December 31, 2012 and 2011 , as well as average sales prices we realized for the respective commodities:





Year Ended December 31,20122011Average Index Closing Price:Natural Gas (per MMBtu)CIG$2.58$3.79NYMEX2.794.04Crude Oil (per Bbl)NYMEX$94.92$94.01Average Sales Price Realized:Excluding realized derivative gains/(losses)Natural Gas (per Mcf)$2.63$3.74Crude Oil (per Bbl)87.2787.44





Based on a sensitivity analysis as of December 31, 2012 , it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, including those designated to our affiliated partnerships, would have resulted in a decrease in fair value of $52.6 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $51.9 million. Excluding the derivatives designated to our affiliated partnerships, the same 10% increase or decrease in natural gas and crude oil prices would have resulted in a decrease in fair value of $52.1 million and an increase in fair value of $51.5 million, respectively.





See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this Exhibit 99.1 for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.





Credit Risk





Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis.





Our Oil and Gas Exploration and Production segment's natural gas, NGLs and crude oil sales are concentrated with a few predominately large customers. This concentrates the significance of our credit risk exposure to a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. We monitor their creditworthiness through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses in either of our Oil and Gas Exploration and Production or Gas Marketing segments. See Note 5, Concentration of Risk , to our consolidated financial statements included elsewhere in this Exhibit 99.1.





Our derivative financial instruments may expose us to the credit risk of nonperformance by the instrument's contract counterparty. We use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. We monitor their creditworthiness through our credit committee which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this Exhibit 99.1 for more detail on our derivative financial instruments.





Disruption in the credit market may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings. While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can assure performance by a financial institution.





Disclosure of Limitations





Because the information above included only those exposures that existed at December 31, 2012 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time.





21


---




ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA





The response to this Item is set forth herein in a separate section of this Exhibit 99.1, beginning on Page F-1.





22


---










Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental InformationManagement's Report on Internal Control Over Financial ReportingF- 2Financial Statements:Report of Independent Registered Public Accounting FirmF- 3Consolidated Balance Sheets - December 31, 2012 and 2011F- 4Consolidated Statements of Operations - Years Ended December 31, 2012, 2011 and 2010F- 5Consolidated Statements of Cash Flows - Years Ended December 31, 2012, 2011 and 2010F- 6Consolidated Statements of Equity - Years Ended December 31, 2012, 2011, and 2010F- 7Notes to Consolidated Financial StatementsF- 8Supplemental Information - Unaudited:Natural Gas and Crude Oil InformationF- 38Quarterly Financial InformationF- 45Financial Statement Schedule:Schedule II - Valuation and Qualifying AccountsF- 47





F- 1


---




Management's Report on Internal Control Over Financial Reporting





Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed 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. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.





Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 , based upon the criteria established in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2012 .





The effectiveness of the Company's internal control over financial reporting as of December 31, 2012 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.








PDC ENERGY, INC.


/s/ James M. TrimbleJames M. TrimblePresident and Chief Executive Officer/s/ Gysle R. ShellumGysle R. ShellumChief Financial Officer/s/ R. Scott MeyersR. Scott MeyersChief Accounting Officer





F- 2


---




Report of Independent Registered Public Accounting Firm








To the Board of Directors and Shareholders of PDC Energy, Inc.:





In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity, and cash flows present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.





A company's internal control over financial reporting is a process designed 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. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.





Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.











/s/ PricewaterhouseCoopers LLP





Pittsburgh, Pennsylvania


February 26, 2013 except for the effects of discontinued operations discussed in Notes 14 and 19, as to which the date is  June 27, 2013





F- 3


---







PDC ENERGY, INC.


Consolidated Balance Sheets


(in thousands, except share and per share data)


As of December 31,20122011AssetsCurrent assets:Cash and cash equivalents$2,457$8,238Restricted cash3,94211,070Accounts receivable, net64,88059,923Accounts receivable affiliates4,8428,518Fair value of derivatives52,04260,809Deferred income taxes36,15116,127Prepaid expenses and other current assets7,6358,365Total current assets171,949173,050Properties and equipment, net1,616,7061,301,716Assets held for sale—148,249Fair value of derivatives6,88341,175Accounts receivable affiliates—2,836Other assets31,31030,979Total Assets$1,826,848$1,698,005Liabilities and Shareholders' EquityLiabilitiesCurrent liabilities:Accounts payable$82,716$76,027Accounts payable affiliates5,29610,176Production tax liability25,89918,949Fair value of derivatives18,43927,974Funds held for distribution34,22828,594Accrued interest payable11,05611,243Other accrued expenses25,71522,083Total current liabilities203,349195,046Long-term debt676,579532,157Deferred income taxes148,427207,573Asset retirement obligation61,56346,316Fair value of derivatives10,13721,106Accounts payable affiliates—6,134Other liabilities23,61225,561Total liabilities1,123,6671,033,893Commitments and contingent liabilitiesShareholders' equityPreferred 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, respectively303236Additional paid-in capital387,494217,707Retained earnings315,568446,280Treasury shares - at cost, 5,059 and 2,938 as of December 31, 2012 and 2011, respectively(184)(111)Total shareholders' equity703,181664,112Total Liabilities and Shareholders' Equity$1,826,848$1,698,005





See accompanying Notes to Consolidated Financial Statements
 F- 4


---




PDC ENERGY, INC.


Consolidated Statements of Operations


(in thousands, except per share data)


Year Ended December 31,201220112010Revenues:Natural gas, NGLs and crude oil sales$238,361$223,297$146,048Sales from natural gas marketing45,37163,47065,235Commodity price risk management gain, net32,33946,09059,891Well operations, pipeline income and other4,5344,4325,441Total revenues320,605337,289276,615Costs, expenses and other:Production costs54,70044,83229,867Cost of natural gas marketing45,02362,83164,733Exploration expense20,8945,7349,207Impairment of natural gas and crude oil properties5,8952,3014,370General and administrative expense58,81561,45442,188Depreciation, depletion, and amortization98,77887,63366,118Accretion of asset retirement obligations3,6871,3981,044Gain on sale of properties and equipment(4,353)(196)(174)Total cost, expenses and other283,439265,987217,353Income (loss) from operations37,16671,30259,262Loss on extinguishment of debt(23,283)——Interest expense(48,287)(36,985)(33,250)Interest income84771Income (loss) from continuing operations before income taxes(34,396)34,36426,083Provision for income taxes12,701(11,800)(8,019)Income (loss) from continuing operations(21,695)22,56418,064Income (loss) from discontinued operations, net of tax(109,017)(9,127)(12,130)Net income (loss)(130,712)13,4375,934Net loss attributable to noncontrolling interests——280Net income (loss) attributable to shareholders$(130,712)$13,437$6,214Amounts attributable to PDC Energy, Inc. shareholders:Income (loss) from continuing operations$(21,695)$22,564$18,344Income (loss) from discontinued operations, net of tax(109,017)(9,127)(12,130)Net income (loss) attributable to shareholders$(130,712)$13,437$6,214Earnings per share:BasicIncome (loss) from continuing operations$(0.78)$0.96$0.94Income (loss) from discontinued operations(3.94)(0.39)(0.62)Net income (loss) attributable to shareholders$(4.72)$0.57$0.32DilutedIncome (loss) from continuing operations$(0.78)$0.95$0.92Income (loss) from discontinued operations(3.94)(0.39)(0.61)Net income (loss) attributable to shareholders$(4.72)$0.56$0.31Weighted-average common shares outstanding:Basic27,67723,52119,674Diluted27,67723,87119,821





See accompanying Notes to Consolidated Financial Statements
 F- 5


---




PDC ENERGY, INC.


Consolidated Statements of Cash Flows


(in thousands)


Year Ended December 31,201220112010Cash flows from operating activities:Net income (loss)$(130,712)$13,437$5,934Adjustments to net income (loss) to reconcile to net cash from operating activities:Unrealized (gain) loss on derivatives, net17,134(28,601)(12,625)Depreciation, depletion and amortization146,879135,154111,062Impairment of natural gas and crude oil properties168,14925,15911,147Prepaid well costs write-offs3,9161,359668Loss on extinguishment of debt23,283——Exploratory dry hole costs15,3471774,199Accretion of asset retirement obligation4,0601,8971,423Stock-based compensation8,4958,7815,314Excess tax benefits from stock-based compensation—(1,311)(293)(Gain) loss from sale of properties and equipment(24,273)(4,263)299Amortization of debt discount and issuance costs7,8646,2654,618Deferred income taxes(80,379)9,5301,179Inventory adjustment and other4,123135307Total adjustments to net income (loss) to reconcile to net cash from operating activities:294,598154,282127,298Changes in assets and liabilities:Accounts receivable6,843(3,451)2,122Other assets(2,908)(3,893)22,616Restricted cash8,859(8,603)219Production tax liability2,4995,436(6,818)Accounts payable and accrued expenses(5,050)12,4221,172Other liabilities592(2,796)(730)Total changes in assets and liabilities10,835(885)18,581Net cash from operating activities174,721166,834151,813Cash 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 adjustments14,469——Proceeds from sale of properties and equipment193,54423,14023,369Other—849(3,527)Net cash from investing activities(451,939)(456,401)(300,932)Cash flows from financing activities:Proceeds from revolving credit facility682,000417,194414,500Payment of revolving credit facility(839,750)(183,713)(494,500)Proceeds from senior notes offering500,000—115,000Redemption of senior notes(221,840)——Payment of debt issuance costs(11,969)(680)(8,541)Proceeds from sale of common stock, net of issuance costs164,496—125,506Excess tax benefits from stock-based compensation—1,311293Contribution from noncontrolling interest—12,46420,077Purchase of treasury shares(1,500)(3,143)(788)Net cash from financing activities271,437243,433171,547Net change in cash and cash equivalents(5,781)(46,134)22,428Cash and cash equivalents, beginning of year8,23854,37231,944Cash and cash equivalents, end of year$2,457$8,238$54,372Supplemental cash flow information:Cash payments (receipts) for:Interest, net of capitalized interest$41,768$29,429$28,335Income taxes1,845(1,498)(27,322)Non-cash investing activities:Change in accounts payable related to purchases of properties and equipment28823,83715,787Change in asset retirement obligation, with a corresponding change to natural gas and crude oil properties, net of disposals11,96717,5383,624Non-cash financing activities:Change in paid-in capital related to convertible debt, net of tax——12,850See Note 15,Acquisitions, for non-cash transactions related to our acquisitions


See accompanying Notes to Consolidated Financial Statements
 F- 6


---




PDC ENERGY, INC.


Consolidated Statements of Equity


(in thousands, except share and per share data)


Year Ended December 31,201220112010Common shares, issued:Shares beginning of year23,634,95823,462,32619,242,219Shares issued pursuant to sale of equity6,500,000—4,140,000Exercise of stock options—2,814—Issuance of stock awards, net of forfeitures173,737242,334110,680Retirement of treasury shares(14,471)(72,516)(30,573)Shares end of year30,294,22423,634,95823,462,326Treasury shares:Shares beginning of year2,9382,9388,273Purchase of treasury shares44,57687,58830,573Issuance of treasury shares(28,587)(15,072)—Retirement of treasury shares(14,471)(72,516)(30,573)Non-employee directors' deferred compensation plan603—(5,335)Shares end of year5,0592,9382,938Common shares outstanding30,289,16523,632,02023,459,388Equity:Shareholders' equityPreferred shares, par value $0.01 per share:Balance beginning and end of year$—$—$—Common shares, par value $0.01 per share:Balance beginning of year236235192Shares issued pursuant to sale of equity65—41Issuance of stock awards, net of forfeitures212Balance end of year303236235Additional paid-in capital:Balance beginning of year217,707209,19864,406Proceeds from sale of equity, net of issuance costs164,431—125,465Convertible debt discount, net of issuance costs and tax——12,165Stock-based compensation expense8,4958,7815,314Issuance 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—12,46420,077Effect of PDCM deconsolidation/change in ownership interest—(10,378)(17,275)Balance end of year387,494217,707209,198Retained earnings:Balance beginning of year446,280432,843426,629Net income (loss) attributable to shareholders(130,712)13,4376,214Balance end of year315,568446,280432,843Treasury shares, at cost:Balance beginning of year(111)(111)(312)Purchase of treasury shares(1,500)(3,143)(788)Issuance of treasury shares955472—Retirement of treasury shares4912,671788Non-employee directors' deferred compensation plan(19)—201Balance end of year(184)(111)(111)Total shareholders' equity703,181664,112642,165Noncontrolling interests in subsidiaryBalance beginning of year—7647,678Noncontrolling interest in PDC Mountaineer, LLC——(47,322)Net loss attributed to noncontrolling interest in subsidiary—(76)(280)Balance end of year——76Total noncontrolling interests in subsidiary——76Total Equity$703,181$664,112$642,241


See accompanying Notes to Consolidated Financial Statements
 F- 7


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION





PDC Energy, Inc. ("PDC," "PDC Energy," "we," "us" or "the Company") is a domestic independent natural gas and crude oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas, NGLs and crude oil. As of December 31, 2012 , we owned an interest in approximately 7,200 gross wells located primarily in the Wattenberg Field, Utica Shale, Appalachian Basin, northeast Colorado and Piceance Basin. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing.





The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries, an entity in which we have a controlling financial interest (2010 only) and our proportionate share of PDC Mountaineer, LLC ("PDCM") and our 21 affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.





The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of natural gas, NGLs and crude oil sales revenue, natural gas, NGLs and crude oil reserves, future cash flows from natural gas and crude oil properties, valuation of derivative instruments and valuation of deferred income tax assets.





Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are mainly attributable to reporting as discontinued operations the results of operations related to the sale of our Piceance Basin and NECO oil and gas properties. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , for additional information regarding the divestiture. In addition, accretion of asset retirement obligations have been reclassified out of the statement of operations line item production cost and into accretion of asset retirement obligations. Deferred income taxes have been reclassified out of the balance sheet line item prepaid expenses and other current assets and into deferred income taxes. Prepaid well costs write-offs have been reclassified out of the statement of cash flows line item changes in other assets and into prepaid well costs write-offs. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity.





NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.


Restricted Cash. Pursuant to an oral litigation settlement agreement, in July 2011, we funded an escrow account in the amount of $8.7 million . During 2012, approval and settlement occurred and the $8.7 million was released from the escrow account thereby reducing our restricted cash balance. In conjunction with our acquisition of certain Wattenberg assets in 2012, we funded an escrow account with $1.7 million .


We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities.  As of December 31, 2012 , we had collateral in the form of certificates of deposit and cash totaling $5.3 million which consisted of $3.9 million and $1.4 million included in restricted cash and other assets, respectively. As of December 31, 2011 , we had collateral in the form of certificates of deposit and cash totaling $3.8 million which consisted of $2.3 million and $1.5 million included in restricted cash and other assets, respectively.


Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our natural gas and crude oil operations. As of December 31, 2012 and 2011 , inventory of $1.2 million and $1.1 million , respectively, is included in prepaid expenses and other current assets on the balance sheets.





Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of natural gas and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.





All derivative assets and liabilities are recorded on our balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk.





The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.


F- 8


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


See Notes 3, Fair Value of Financial Instruments , and 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2012 and 2011 , respectively.





Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below.





Natural Gas and Crude Oil Properties.  We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A.





Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment , for disclosure related to changes in our capitalized exploratory well costs.





Proved Property Impairment. We assess our producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the statement of operations line item impairment of natural gas and crude oil properties, with a corresponding impact on accumulated depreciation, depletion and amortization on the balance sheet.





Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed for impairment. Unproved natural gas and crude oil properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved natural gas and crude oil properties are charged to the statement of operations line item impairment of natural gas and crude oil properties.





Other Property and Equipment.  The following table presents the estimated useful lives of our other property and equipment:





Pipelines and related facilities10 - 17 yearsTransportation and other equipment3 - 20 yearsBuildings30 - 40 years





Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment to other property and equipment was recognized in 2012 or 2011. Impairment recognized in 2010 was immaterial.





Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $4.7 million , $4 million and $4.9 million in 2012 , 2011 and 2010 , respectively.





F- 9


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


Capitalized Interest.  Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved natural gas and crude oil properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $1.2 million , $1.7 million and $0.3 million in 2012 , 2011 and 2010 , respectively.





Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair values that are ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. Depreciation, depletion, and amortization expense is not recorded on assets to be divested once they are classified as held for sale.     Assets to be divested are classified in the consolidated financial statements as held for sale, and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the consolidated balance sheets and to discontinued operations on the consolidated statements of operations, respectively, for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. Businesses classified as held for sale are expected to be disposed of within one year. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the balance sheet amounts are reclassified from their historical presentation to assets and liabilities held for sale for all periods presented. The results of operations continue to be reported in continuing operations.





Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce natural gas, NGLs and crude oil, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the balance sheets. The long-term portion of the production tax liability is included in other liabilities on the balance sheets and was $18.7 million and $19.4 million in December 31, 2012 and 2011 , respectively.





Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and future credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2012 and 2011 , we had no valuation allowance.





Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2012 and 2011 , included in other assets was $17.4 million and $12.3 million , respectively, related to debt issuance costs. The December 31, 2012 , amount included $1.9 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $10.9 million related to our 7.75% senior notes due 2022 and $4.6 million related to our revolving credit facility and the PDCM credit facility. The December 31, 2011, amount included $2.4 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $3.4 million related to our 12% senior notes due 2022 and $6.5 million related to our revolving credit facility and the PDCM credit facility.





Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9, Asset Retirement Obligations , for a reconciliation of the changes in our asset retirement obligation.





Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.





Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below.





Natural gas, NGLs and crude oil sales. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a


F- 10


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in Colorado are sold on a long-term basis ranging from 15 years to the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas.





Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the limited partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured.





Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, Riley Natural Gas ("RNG"), our suppliers and our customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable.





Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of natural gas and crude oil properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.





In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved natural gas and crude oil properties and other non-natural gas and crude oil properties. To estimate the fair values of these properties, we prepare estimates of natural gas and crude oil reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors.





We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.





Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the statement of operations. No amounts for stock-based compensation were capitalized in 2012 , 2011 and 2010 .





Recent Accounting Standards.





The following standards were recently adopted:





Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and were effective for public entities during interim and annual periods beginning after December 15, 2011. Early application was not permitted. With the exception of the disclosure requirements, adoption of these changes did not have a significant impact on our financial statements.





Presentation of Comprehensive Income. On June 16, 2011, the FASB issued changes related to the presentation of comprehensive income. These changes eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. These changes are intended to enhance comparability between entities that report under U.S. GAAP and those that report under IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity's equity. An entity may elect to present items


F- 11


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements. Each component of net income and each component of other comprehensive income, together with totals for comprehensive income and its two parts, net income and other comprehensive income, need to be displayed under either alternative. The statement(s) need to be presented with equal prominence as the other primary financial statements. These changes were effective for our financial statements issued for annual reporting periods beginning after December 15, 2011. Adoption of this change did not have a material impact on our financial statements.





NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS





Derivative Financial Instruments





Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:





Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.





Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.





Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.





Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.





We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.





We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant.





Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our natural gas and crude oil collars, natural gas calls and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:


F- 12


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


As of December 31,20122011Significant OtherObservableInputs(Level 2)SignificantUnobservableInputs(Level 3)TotalSignificant OtherObservableInputs(Level 2)SignificantUnobservableInputs(Level 3)Total(in thousands)Assets:Commodity-based derivative contracts$42,788$15,734$58,522$76,104$25,837$101,941Basis protection derivative contracts3871640353843Total assets43,17515,75058,92576,10925,875101,984Liabilities:Commodity-based derivative contracts9,8392,08111,9209,8883,76813,656Basis protection derivative contracts16,656—16,65635,424—35,424Total liabilities26,4952,08128,57645,3123,76849,080Net asset$16,680$13,669$30,349$30,797$22,107$52,904





The following table presents a reconciliation of our Level 3 assets measured at fair value:





201220112010(in thousands)Fair value, net asset, beginning of year$22,107$10,762$15,048Changes in fair value included in statement of operations line item:Commodity price risk management gain, net7,57613,48711,591Sales from natural gas marketing63114580Cost of natural gas marketing——23Changes in fair value included in balance sheet line item (1):Accounts receivable affiliates—49231Accounts 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$10,762Changes in unrealized gains (losses) relating to assets (liabilities) still heldas of year-end, included in statement of operations line item:Commodity price risk management gain, net$3,665$11,669$9,594Sales from natural gas marketing1(3)54Total$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.




The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts.





Non-Derivative Financial Assets and Liabilities





The carrying values of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.





The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input.





F- 13


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The portion of our long-term debt related to our revolving credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of December 31, 2012 , we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $125.3 million , or 109% of par value, and the portion related to our 7.75% senior notes due 2022 to be $512.8 million , or 102.6% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs.





See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Natural Gas and Crude Oil Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities.





NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS





Our results of operations and operating cash flows are affected by changes in market prices for natural gas, NGLs and crude oil. To manage a portion of our exposure to price volatility from producing natural gas and crude oil, we utilize the following economic hedging strategies for each of our business segments.





|  |                                                                                                                                                                                                                                                                                                                                                                     
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | 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.




We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2012 , we had derivative instruments in place for a portion of our anticipated production through 2016 for a total of 68,853 BBtu of natural gas and 3,754 MBbls of crude oil.





As of December 31, 2012 , our derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases.





|  |                                                                                                                                                                                                                                                                                                                                                                 
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | 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.







F- 14


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of December 31, 2012 and 2011 :





Derivatives instruments:Balance sheet line item20122011(in thousands)Derivative assets:CurrentCommodity contractsRelated to natural gas and crude oil salesFair value of derivatives$47,016$51,220Related to affiliated partnerships (1)Fair value of derivatives4,7078,018Related to natural gas marketingFair value of derivatives3021,528Basis protection contractsRelated to natural gas marketingFair value of derivatives174352,04260,809Non CurrentCommodity contractsRelated to natural gas and crude oil salesFair value of derivatives6,67134,938Related to affiliated partnerships (1)Fair value of derivatives—6,134Related to natural gas marketingFair value of derivatives203103Basis protection contractsRelated to natural gas marketingFair value of derivatives9—6,88341,175Total derivative assets$58,925$101,984Derivative liabilities:CurrentCommodity contractsRelated to natural gas and crude oil salesFair value of derivatives$1,744$7,498Related to affiliated partnerships (2)Fair value of derivatives—211Related to natural gas marketingFair value of derivatives2261,384Basis protection contractsRelated to natural gas and crude oil salesFair value of derivatives14,32915,762Related to affiliated partnerships (2)Fair value of derivatives2,1403,116Related to natural gas marketingFair value of derivatives—318,43927,974Non CurrentCommodity contractsRelated to natural gas and crude oil salesFair value of derivatives9,9694,357Related to affiliated partnerships (2)Fair value of derivatives—113Related to natural gas marketingFair value of derivatives16893Basis protection contractsRelated to natural gas and crude oil salesFair value of derivatives—13,820Related to affiliated partnerships (2)Fair value of derivatives—2,72310,13721,106Total 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.







F- 15


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents the impact of our derivative instruments on our statements of operations:





Year Ended December 31,201220112010Statement of operations line itemReclassificationof RealizedGains (Losses)Included in Prior PeriodsUnrealizedRealized and UnrealizedGains(Losses) FortheCurrentPeriodTotalReclassificationof RealizedGains (Losses)Included in Prior PeriodsUnrealizedRealized and UnrealizedGains(Losses) FortheCurrentPeriodTotalReclassificationof RealizedGains (Losses)Included in Prior PeriodsUnrealizedRealized and UnrealizedGains(Losses) FortheCurrentPeriodTotal(in thousands)Commodity price risk management gain (loss), netRealized gains$28,819$20,597$49,416$10,329$6,914$17,243$20,148$26,947$47,095Unrealized gains (losses)(28,819)11,742(17,077)(10,329)39,17628,847(20,148)32,94412,796Total commodity price risk management gain, net$—$32,339$32,339$—$46,090$46,090$—$59,891$59,891Sales from natural gas marketingRealized gains$1,571$599$2,170$1,827$1,143$2,970$2,390$3,991$6,381Unrealized gains (losses)(1,571)(87)(1,658)(1,827)1,666(161)(2,390)1,745(645)Total sales from natural gas marketing$—$512$512$—$2,809$2,809$—$5,736$5,736Cost of natural gas marketingRealized losses$(1,387)$(642)$(2,029)$(1,441)$(1,130)$(2,571)$(1,905)$(3,996)$(5,901)Unrealized gains (losses)1,3872141,6011,441(1,526)(85)1,905(1,431)474Total cost of natural gas marketing$—$(428)$(428)$—$(2,656)$(2,656)$—$(5,427)$(5,427)





NOTE 5 - CONCENTRATION OF RISK





Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts:





As of December 31,20122011(in thousands)Natural gas, NGLs and crude oil sales$39,837$42,388Natural gas marketing8,2096,225Reimbursements for title defects7,579—Joint interest billings6,8967,465Other3,3854,766Allowance for doubtful accounts(1,026)(921)Accounts receivable, net$64,880$59,923





Our accounts receivable primarily relates to sales of our natural gas, NGLs and crude oil production, derivative counterparties and other third parties that own working interests in the properties we operate. Inherent to our industry is the concentration of natural gas, NGLs and crude oil sales to a limited number of customers. This industry concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. Our estimate of uncollectible amounts changes periodically. For the each of the years in the three-year period ended December 31, 2012 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2012 , we had two customers representing 10% or greater of our accounts receivable balance: Suncor Energy Marketing and Merit Energy, representing 26.4% and 11.7% , respectively, of our accounts receivable balance. The $7.6 million of accounts receivable at December 31, 2012 due from Merit Energy related to reimbursements for title defects discovered subsequent to our acquisition of certain Wattenberg assets from affiliates of Merit Energy (the "Merit Acquisition").  The reimbursement for certain title defects was received in January 2013.


F- 16


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued





Major Customers. The following table presents the individual customers constituting 10% or more of total revenues:





Year Ended December 31,Customer201220112010Suncor Energy Marketing, Inc.29.8%25.7%19.6%DCP Midstream, LP12.2%11.5%9.6%WPX Energy Rocky Mountain, LLC5.6%9.9%12.5%





Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and crude oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments was not significant.





The following table presents the counterparties that expose us to credit risk as of December 31, 2012 , with regard to our derivative assets:





Fair Value ofDerivative AssetsCounterparty NameAs of December 31, 2012(in thousands)JPMorgan Chase Bank, N.A. (1)$41,323Wells Fargo Bank, N.A. (1)4,782Bank of Nova Scotia (1)4,315Other lenders in our revolving credit facility8,146Various (2)359Total$58,925


____________


(1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt.


(2) Represents a total of 28 counterparties.





NOTE 6 - PROPERTIES AND EQUIPMENT





The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization:





As of December 31,20122011(in thousands)Properties and equipment, net:Natural gas and crude oil propertiesProved$2,075,924$1,694,694Unproved319,327102,466Total natural gas and crude oil properties2,395,2511,797,160Pipelines and related facilities47,78640,721Transportation and other equipment34,85832,475Land and buildings14,93514,572Construction in progress67,21769,633Gross properties and equipment2,560,0471,954,561Accumulated depreciation, depletion and amortization(943,341)(652,845)Properties and equipment, net$1,616,706$1,301,716





F- 17


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents impairment charges recorded for natural gas and crude oil properties:





Year Ended December 31,201220112010(in thousands)Continuing operations:Impairment of proved properties$—$—$—Impairment of individually significant unproved properties1,6291,1081,477Amortization of individually insignificant unproved properties4,2661,1932,893Total continuing operations5,8952,3014,370Discontinued operations:Impairment of proved properties161,18522,4604,666Impairment of individually significant unproved properties313——Amortization of individually insignificant unproved properties7563982,111Total discontinued operations162,25422,8586,777Total impairment of natural gas and crude oil properties$168,149$25,159$11,147





In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from an unrelated third-party bid, a Level 3 input, as we changed our development plans in the basin and decided to sell the related assets. The impairment charge was included in discontinued operations on the statement of operations. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations , for additional information regarding the sale of our Piceance Basin oil and natural gas properties.





In 2011, we recognized an impairment charge of $22.5 million to write-down our NECO assets to fair value. The fair value was based on unrelated third-party bids, a level 3 input. The impairment charge was included in discontinued operations on the statement of operations. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations , for additional information regarding the sale of our NECO oil and natural gas properties.





In May 2010, pursuant to our entry into an agreement to sell our Michigan assets, we reclassified our Michigan assets as held for sale. We compared the transactional sales price, considered a Level 3 input, less costs to sell to the carrying value of our Michigan net assets. The net carrying value exceeded the net sales price and, therefore, during the second quarter of 2010, we recognized a pre-tax impairment charge of $4.7 million to reduce the carrying value of the net assets to reflect the net sales price. The impairment charge was included in discontinued operations on the statement of operations. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations.





Suspended Well Costs





The following table presents the capitalized exploratory well costs pending determination of proved reserves, and included in properties and equipment on the balance sheets:





201220112010(in thousands, except for number of wells)Balance beginning of year, January 1,$4,432$2,297$1,174Additions to capitalized exploratory well costs pending the determination of proved reserves30,4823,6924,353Reclassifications 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$2,297Number of wells pending determination at December 31,263





Additions to capitalized exploratory well costs pending determination of proved reserves increased in 2012 as compared to prior years as we increased our exploratory drilling activities in the liquid-rich emerging Utica Shale play.





F- 18


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


In 2012, capitalized well costs related to two vertical stratigraphic test wells in eastern Ohio were expensed at a cost of $12.2 million.  Additionally, three wells in south central Ohio and a well in southeast Colorado were determined to have noncommercial quantities of hydrocarbons and were expensed at a cost of $1.2 million and $0.9 million, respectively.





The following table presents an aging of capitalized exploratory well costs based on the date that drilling commenced and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the commencement of drilling:


As of December 31,201220112010(in thousands)Exploratory well costs capitalized for a period of one year or less$19,567$3,587$2,297Exploratory 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$2,297Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling—2—





NOTE 7 - INCOME TAXES





The table below presents the components of our provision for income taxes from continuing operations for the years presented:





Year Ended December 31,201220112010(in thousands)Current:Federal$—$2,594$(4,982)State(199)750(1,536)Total current income taxes(199)3,344(6,518)Deferred:Federal12,133(13,309)(4,288)State767(1,835)2,787Total deferred income taxes12,900(15,144)(1,501)Provision for income taxes from continuing operations$12,701$(11,800)$(8,019)





We continue to utilize tax deferral strategies such as bonus and accelerated depreciation, IRC Section 1031 like-kind exchange strategies and intangible drilling cost expense elections to minimize our current taxes.  As a result of these elections and deferral strategies, we have generated federal and state net operating losses (“NOLs”) in 2012, 2011 and 2010.  Substantially, all the 2010 federal NOL was carried back to 2008, generating a refund of $4.6 million which was received in the fourth quarter of 2011.  The remaining federal NOLs and substantially all the state NOLs are being carried forward to 2013 and/or future periods.  We expect to utilize our federal NOL and a substantial portion of our state NOLs to offset the projected 2013 taxable gain on the sale of our non-core Colorado assets. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations , for additional information regarding the sale of our non-core Colorado assets.


F- 19


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations:





Year Ended December, 31,201220112010Statutory tax rate35.0%35.0%35.0%State income tax, net1.02.03.1Percentage depletion1.9(2.5)(2.9)Non-deductible compensation(0.5)—1.1Non-deductible meals and entertainment(0.5)0.30.3State deferred rate change—1.3(6.7)Unrecognized tax benefits—(2.6)0.2State tax credits——(1.6)Federal return examination adjustments—0.40.6Return to provision adjustments—0.3(0.3)Other—0.11.9Effective tax rate36.9%34.3%30.7%





The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2012 and 2011 are presented below:





As of December 31,20122011(in thousands)Deferred tax assets:Provision for underpayment of natural gas sales$—$3,334Deferred compensation7,2164,319Asset retirement obligations10,3259,438State NOL and tax credit carryforwards, net6,1175,240Percentage depletion - carryforward4,7023,733Alternative minimum tax - credit carryforward2,3512,351Federal NOL carryforward21,28112,210Other2,2762,621Deferred tax assets54,26843,246Deferred tax liabilities:Properties and equipment122,742184,657Investment in PDCM31,44530,919Unrealized gains - derivatives7,16312,612Convertible debt5,1946,504Total gross deferred tax liabilities166,544234,692Net deferred tax liability$112,276$191,446Classification in the balance sheets:Deferred income tax assets$36,151$16,127Deferred income tax liability148,427207,573Net deferred tax liability$112,276$191,446





Deferred tax liabilities for properties and equipment decreased in 2012 primarily as a result of our impairment of certain oil and gas properties, which is an expense not currently deductible from taxable income, partially offset by our continued use of statutory provisions for bonus and accelerated tax depreciation. In addition, a tax gain, previously deferred through the use of IRC Section 1031 LKE strategies, was recognized upon the sale of our Permian Basin assets.





As of December 31, 2012 , we have state NOL carryforwards of $142.4 million that begin to expire in 2029 , state credit carryforwards of $1.8 million that begin to expire in 2022 and federal NOL carryforwards of $60.8 million that will expire in 2030 . Approximately $0.9 million


F- 20


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


of excess tax benefits relating to stock-based compensation that are a component of our NOL carryforwards, when realized, will be credited to APIC.





The following table presents a reconciliation of the total amounts of unrecognized tax benefits:





201220112010(in thousands)Balance beginning of year, January 1$179$1,093$566Additions for tax positions of prior years——253Additions for tax positions of current year——274Reductions due to settlements—(782)—Reductions due to lapse of statute of limitations—(132)—Balance end of year, December 31$179$179$1,093





Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2012 . The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, was $0.2 million as of December 31, 2012 and December 31, 2011 , respectively. As of December 31, 2012 , we expect a decrease in the unrecognized tax benefit in the next twelve months due to statute of limitation expiration. During 2012, we did not reduce our liability for any uncertain tax benefits, of which the remaining balance is related to our state tax filings, as no prior tax positions were resolved, nor did we have any new uncertain tax benefits arise during the year. The statute of limitation for most of our state tax jurisdictions is open from 2008 forward.





In accordance with the Compliance Assurance Process ("CAP"), the IRS completed its “post filing review” of our 2010 tax return in January 2012 and completed their “post filing review” of our 2011 tax return in January 2013. We have been issued a “no change” letter for both of the reviewed tax years. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the IRS CAP program for the review of our 2012 tax year and we have been invited and have accepted continued participation in the program for our 2013 tax year. Participation in the IRS CAP program has enabled us to currently have no uncertain tax benefits associated with our federal tax return filings. During 2011, we were able to reduce our liability for uncertain tax benefits upon accelerated examination and settlement of our 2007-2009 tax years upon entering the IRS program.








F- 21


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 8 - LONG-TERM DEBT





Long-term debt consists of the following:





As of December 31,20122011(in thousands)Senior notes3.25% Convertible senior notes due 2016:Principal amount$115,000$115,000Unamortized discount(13,671)(17,079)3.25% Convertible senior notes due 2016, net of discount101,32997,9217.75% Senior notes due 2022:Principal amount500,000—12% Senior notes due 2018:Principal amount—203,000Unamortized discount—(1,764)12% Senior notes due 2018, net of discount—201,236Total senior notes601,329299,157Credit facilitiesCorporate49,000209,000PDCM26,25024,000Total credit facilities75,250233,000Total long-term debt$676,579$532,157





Senior Notes





3.25% Convertible Senior Notes Due 2016. In November 2010 , we issued $115 million of 3.25% convertible senior notes due 2016 (the "2016 Convertible Senior Notes") in a private placement to qualified institutional buyers. The convertible notes and the common stock issuable upon conversion of the convertible notes, if any, have not been registered under the Securities Act of 1933 ("Securities Act") or any state securities laws, nor are we required to register such convertible notes or common shares. The convertible notes are governed by an indenture dated November 23, 2010, between the Company and the Bank of New York Mellon, as trustee. The maturity for the payment of principal is May 15, 2016 . Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15 , commencing on May 15, 2011 . The convertible notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the convertible notes; equal in right of payment to our existing and future unsecured indebtedness that is not so subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our senior secured credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the convertible notes does not contain any restrictive financial covenants.





We may not redeem the convertible notes prior to the maturity date of the convertible notes. However, prior to November 15, 2015 , holders of the convertible notes may convert upon specified events and periods as defined in the governing indenture. The notes are convertible at any time thereafter at an initial conversion rate of 23.5849 per $1,000 principal amount of the convertible notes, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the convertible notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares.





We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our convertible notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the convertible notes. As of December 31, 2012 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the convertible notes of 3.4 years using an effective interest rate of 7.4% . For 2012 , interest expense related to the indebtedness and the amortization of the discount were $3.7 million and $3.4 million , respectively, compared to $3.7 million and $3.2 million , respectively, in 2011 . As of December 31, 2012 and 2011 , notwithstanding the inability to convert, assuming conversion, the value of the convertible notes did not exceed the principal amount.





F- 22


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


7.75% Senior Notes Due 2022. On October 3, 2012 , we issued $500 million aggregate principal amount of 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement. The proceeds from the issuance of the notes, after the initial purchasers' commissions and estimated offering expenses, were used to fund the redemption of our 2018 Senior Notes, repay a portion of the amount outstanding under our revolving credit facility and for general corporate purposes. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 , commencing on April 15, 2013 . Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness (including our 2016 Convertible Senior Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility.





In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2022 Senior Notes for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2022 Senior Notes by holders.





At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption.





At any time prior to October 15, 2015 , we may redeem up to 35% of the outstanding 2022 Senior Notes with proceeds from certain equity offerings at a redemption price of 107.75% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as:





|  |                                                                                                                                          
|- | -----------------------------------------------------------------------------------------------------------------------------------------
|• | 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.




Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase.





The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company.





12% Senior Notes Due 2018. On October 3, 2012 , we issued a notice to redeem on November 2, 2012 the entire $203 million principal amount of the 12% senior notes due 2018 (the "2018 Senior Notes") for a total redemption price of approximately $222 million , including an $18.9 million make-whole premium. The make-whole provision was based upon terms set forth in the related indenture. On November 2, upon the redemption of the 2018 Senior Notes, the $18.9 million make-whole premium, remaining unamortized debt discount of $1.5 million and unamortized debt issuance costs of $2.9 million were recognized as a $23.3 million pre-tax loss on debt extinguishment in the consolidated statement of operations. The amount paid to bond holders for the make-whole premium has been included as a financing activity in our statement of cash flows.





Credit Facilities





Revolving Credit Facility. In November 2010 , we obtained a revolving credit facility pursuant to a Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The maximum facility amount is $600 million . As of December 31, 2012 , we had $49 million outstanding on our revolving credit facility, compared to $209 million as of December 31, 2011 . The borrowing base of the revolving credit facility will be the loan value assigned to the proved reserves attributable to our and our subsidiaries' natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 21 affiliated partnerships. Our revolving credit facility borrowing base is subject to a semiannual size redetermination based on quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our and such subsidiaries' other assets. Neither PDCM nor the various limited partnerships that we have sponsored, and continue to serve as the managing general partner, are guarantors of the revolving credit facility.





On October 31, 2012, the semi-annual redetermination of our revolving credit facility's borrowing base was completed with our available borrowing base being reduced from $525 million to $450 million as a result of the 2022 Senior Notes issuance. On September 21, 2012 , we entered into a Sixth Amendment to the revolving credit facility. The Sixth Amendment increased the amount of senior note


F- 23


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


indebtedness and refinancing indebtedness permitted under the revolving credit agreement. On June 29, 2012, concurrent with the Merit Acquisition, we entered into a Fifth Amendment to our revolving credit facility. The Fifth Amendment increased our available borrowing base to $525 million from $425 million based on our natural gas and crude oil reserves as of December 31, 2011 and the estimated reserves as of April 1, 2012 for the acquired assets from the Merit Acquisition. On June 25, 2012, we entered into the Fourth Amendment to our revolving credit facility. The Fourth Amendment amended certain provisions of the revolving credit facility to allow us greater flexibility in entering into hedging transactions in connection with future potential asset acquisitions. On May 4, 2012, we entered into the Third Amendment to our revolving credit facility and, as a result of the semi-annual redetermination by our bank group, our borrowing base was increased by $25 million to $425 million .





Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015 , or in the event that the borrowing base would fall below the outstanding balance.





The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and maintaining certain financial ratios on a quarterly basis. The financial tests and ratios, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.00 to 1.00.





The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the 2016 Convertible Senior Notes. Among other things, the restriction on redemption of  the 2016 Convertible Senior Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million.





We have outstanding an $18.7 million irrevocable standby letter of credit in favor of a third-party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market production in West Virginia and Southwestern Pennsylvania. The letter of credit reduces the amount of available funds under our revolving credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans ( 2.75% per annum as of December 31, 2012 ) for the period in which the letter of credit remains outstanding. The letter of credit expires on July 20, 2013. We expect to renew the letter of credit prior to its expiration.





We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our revolving credit facility. As of December 31, 2012 , the available funds under our revolving credit facility, including a reduction for the $18.7 million irrevocable standby letter of credit in effect, was $382.3 million . The weighted-average borrowing rate on our revolving credit facility, exclusive of the letter of credit, was 4.5% per annum as of December 31, 2012 compared to 3.8% as of December 31, 2011 .





PDCM Credit Facility. PDCM has a credit facility dated April 30, 2010 , as amended, with an aggregate revolving commitment or borrowing base of $80 million , of which our proportionate share is $40 million . The maximum allowable facility amount is $400 million . Based upon PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of BNP Paribas' prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.25% to 2.0%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.25% to 3.0%. No principal payments are required until the credit agreement expires on April 30, 2014 , or in the event that the borrowing base falls below the outstanding balance. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The credit facility borrowing base is subject to size redetermination semiannually based upon a valuation of PDCM's reserves at June 30 and December 31. Either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Marcellus assets.





The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and financial ratios that must be met on a quarterly basis. The financial tests and ratios, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 5.0 to 1.0 (declining to 4.5 to 1.0 on March 31, 2013 and 4.0 to 1.0 on September 30, 2013) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of December 31, 2012 , our proportionate share of PDCM's outstanding credit facility balance was $26.3 million compared to $24 million as of December 31, 2011 . PDCM is required to pay a commitment fee of 0.5% per annum on the unutilized portion of the activated credit facility. The weighted-average borrowing rate on PDCM's credit facility was 3.5% per annum in 2012 , compared to 5.0% in 2011 .





As of December 31, 2012 , we were in compliance with all credit facility covenants and expect to remain in compliance throughout the next twelve-month period.





F- 24


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 9 - ASSET RETIREMENT OBLIGATIONS





The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties:


20122011(in thousands)Balance beginning of year, January 1$46,566$28,047Obligations incurred with development activities and assumed with acquisitions14,1699,625Accretion expense4,0601,897Obligations 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—8,903Balance end of year, December 31 (1)62,56346,566Less current portion(1,000)(250)Long-term portion$61,563$46,316


__________


|    |                                                                           
|--- | --------------------------------------------------------------------------
|(1) | Includes$2 millionas of December 31, 2011 related to assets held for sale.




The revisions in estimated cash flows during 2011 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells in the two fields where we currently conduct the majority of our operations. These cost increases related mostly to the costs of cement and construction materials and third-party and internal support services on a per well basis. The revision in the asset retirement obligation did not have an immediate effect in the 2011 statement of operations as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells.





NOTE 10 - EMPLOYEE BENEFIT PLANS





We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $3.4 million for 2012 and $2.6 million for 2011 and 2010 , respectively.





We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2012 , 2011 and 2010 . As of December 31, 2012 and 2011 , the liability related to this benefit was $2 million and $2.2 million , respectively, which was included in other liabilities on the balance sheets, with the exception of $0.3 million  included in other accrued expenses as of December 31, 2012 and 2011 .





We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2012 , 2011 and 2010 related to this plan were immaterial. As of December 31, 2012 and 2011 , the related liability of $0.7 million is included in other liabilities on the balance sheets.





We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the balance sheets, was immaterial as of December 31, 2012 and 2011 .





NOTE 11 - COMMITMENTS AND CONTINGENCIES





Firm Transportation Agreements. We enter into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell natural gas. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by PDCM, our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. With the exception of contracts entered into by PDCM, the costs of any volume shortfalls are borne by PDC.





F- 25


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm transportation, sales and processing agreements for pipeline capacity:


Year Ending December 31,Area20132014201520162017ThroughExpirationTotalExpirationDateVolume (MMcf)Piceance Basin30,71036,16830,60326,05385,895209,429May 31, 2021Appalachian Basin20,31624,35323,36124,862168,296261,188September 20, 2025NECO2,1901,8251,8251,825—7,665December 31, 2016Total53,21662,34655,78952,740254,191478,282Dollar commitment (in thousands)$25,756$29,283$26,163$24,075$94,033$199,310





Effective January 1, 2013, we entered into a new gas gathering and processing agreement with Williams Field Services Company related to our Piceance Basin production. The new agreement included additional terms and conditions which, among other things, reduced our Piceance Basin total committed volumes for gathering to 116,260 MMcf over the term of the agreement. On June 18, 2013 , we closed on a transaction pursuant to which our Piceance Basin and NECO firm gathering commitments were assumed by the buyer of certain of our oil and natural gas properties. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations , for additional information regarding the sale of our non-core Colorado assets.





Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.





Alleged Class Action Filed Regarding 2010 and 2011 Partnership Purchases





On December 21, 2011 the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to its partnership repurchases completed by mergers in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp . The complaint primarily alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, the Company filed a motion to dismiss or in the alternative to stay. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014. We have not recorded a liability for claims pending because we believe we have good legal defenses to the asserted claims and because the plaintiffs have not specified damages and it is not possible for management to estimate what, if any, monetary damages could result from this claim.





Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2012 and December 31, 2011 , we had accrued environmental liabilities in the amount of $8.4 million and $2.5 million , respectively, included in other accrued expenses on the balance sheet. The increase in accrued liabilities at December 31, 2012 primarily relates to the assumption of environmental liabilities related to the Merit Acquisition. We are not aware of any environmental claims existing as of December 31, 2012 which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties.





Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of December 31, 2012 , the maximum annual repurchase obligation for 2013, based upon the minimum price described above, was approximately $2.9 million . We believe we have adequate liquidity to meet this potential obligation. During 2012 , 2011 and 2010 , we paid $0.5 million , $0.2 million and $0.6 million , respectively, under this provision for the repurchase of partnership units.





Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment.





F- 26


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2012 :





Year Ending December 31,20132014201520162017ThereafterTotal(in thousands)Minimum Lease Payments$2,607$2,386$1,929$461$255$887$8,525





Operating lease expense for the years ended 2012 , 2011 and 2010 was $6.1 million , $5.9 million and $4.9 million , respectively.





Employment Agreements with Executive Officers . Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company.





See Note 17, Transactions With Affiliates , for a discussion related to the separation agreement entered into with our former chief executive officer in 2011.





NOTE 12 - COMMON STOCK





Sale of Equity Securities





In May 2012 , we completed a public offering of 6,500,000 shares of our common stock, par value $0.01 per share, at an offering price of $26.50 per share. Net proceeds of the offering were approximately $164.5 million , after deducting underwriting discounts and commissions and offering expenses, of which $65,000 is included in common shares-par value and $164.4 million is included in APIC on the balance sheet as of December 31, 2012 . We used the net proceeds from the offering to finance a portion of the Merit Acquisition and for general corporate purposes. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on January 23, 2012.





In November 2010 , we sold 4,140,000 shares of our common stock in an underwritten public offering at a price of $32.00 per share. The net proceeds of $125.5 million were used, together with other proceeds, to fund an acquisition of additional assets in the Wolfberry Trend in the Permian Basin of West Texas, which closed in November 2010 , our acquisition of the 2004 and 2005 partnerships and other acquisitions and for general corporate purposes. Pending such uses, we applied the net proceeds from this offering and other proceeds to temporarily repay the entire outstanding amount under our revolving credit facility, with the remaining balance being deposited in an interest bearing account and held as cash and cash equivalents until utilized as contemplated above. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on November 26, 2008.





Stock-Based Compensation Plans





2010 Long-Term Equity Compensation Plan. In June 2010 , our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, up to 1,400,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event, may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2012 , 490,412 shares remain available for issuance pursuant to the 2010 Plan.





2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004 , we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We no longer issue awards pursuant to the 2004 Plan. All outstanding and non-vested awards pursuant to the 2004 Plan will continue to be outstanding and vest pursuant to their original terms on or before April 19, 2020.





F- 27


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:





Year Ended December 31,20122011 (1)2010(in thousands)Stock-based compensation expense$8,495$8,781$5,314Income tax benefit(3,245)(3,344)(2,019)Net expense$5,250$5,437$3,295


__________


(1) Includes a $2.5 million pre-tax charge related to a separation agreement with our former chief executive officer. See Note 17, Transactions with Affiliates, for additional information regarding the related separation agreement.





Stock Option Awards





We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock options awards since 2006. As of December 31, 2012 , all compensation cost related to stock options has been fully recognized in our statements of operations.





The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial:





Year Ended December 31,201220112010Number ofSharesUnderlyingOptionsWeighted-AverageExercisePricePer ShareWeighted- AverageRemainingContractualTerm(in years)Number ofSharesUnderlyingOptionsWeighted-AverageExercisePricePer ShareNumber ofSharesUnderlyingOptionsWeighted-AverageExercisePricePer ShareOutstanding beginning of year, January 1,6,973$41.09—10,306$41.9010,306$41.90Forfeited———(3,333)43.60——Outstanding end of year, December 31,6,97341.092.66,97341.0910,30641.90Exercisable at December 31,6,97341.092.66,97341.0910,30641.60





SARs





The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.





In January 2012, the Compensation Committee awarded 68,361 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:


Year Ended December 31,201220112010Expected term of award6 years6 years5 yearsRisk-free interest rate1.1%2.5%2.5%Expected volatility64.3%60.2%62.0%Weighted-average grant date fair value per share$17.61$25.22$13.26





The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.





F- 28


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents the changes in our SARs:





Year Ended December 31,201220112010Number ofSARsWeighted-AverageExercisePriceAverage Remaining ContractualTerm(in years)Aggregate IntrinsicValue(in thousands)Number ofSARsWeighted-AverageExercisePriceAggregate IntrinsicValue(in thousands)Number ofSARsWeighted-AverageExercisePriceAggregate IntrinsicValue(in thousands)Outstanding beginning of year, January 1,50,471$31.618.6$34157,282$24.44$1,020—$—$—Awarded68,36130.19——31,55243.95—57,28224.44—Exercised————(25,371)24.4477———Forfeited————(12,992)43.95————Outstanding end of year, December 31,118,83230.808.448650,47131.6134157,28224.441,020Exercisable at December 31,27,45828.847.518710,63624.44114———





Total compensation cost related to SARs granted and not yet recognized in our statement of operations as of December 31, 2012 , was $1.0 million . The cost is expected to be recognized over a weighted-average period of 1.8 years.





Restricted Stock Awards





Time-Based Awards.  The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed.





In January 2012, the Compensation Committee awarded a total of 79,889 time-based restricted shares to our executive officers that vest ratably over three year period ending on January 16, 2015.





The following table presents the changes in non-vested time-based awards during 2012 :


SharesWeighted-AverageGrant-DateFair ValueNon-vested at December 31, 2011527,801$29.29Granted341,33826.59Vested(186,205)29.42Forfeited(36,444)28.20Non-vested at December 31, 2012646,49027.93





As of/Year Ended December 31,201220112010(in thousands, except per share data)Total intrinsic value of time-based awards vested$5,950$9,030$3,219Total intrinsic value of time-based awards non-vested21,47018,53122,211Market price per common share as of December 31,33.2135.1142.25Weighted-average grant date fair value per share26.5933.7125.04





Total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of December 31, 2012 was  $11.5 million . This cost is expected to be recognized over a weighted-average period of 2.2 years.





Market-Based Awards.  The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.


F- 29


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


In January 2012, the Compensation Committee awarded a total of 30,541 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 14 peer companies. The shares are measured over a three-year period ending on December 31, 2014 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions:


Year Ended December 31,20122011Expected term of award3 years3 yearsRisk-free interest rate0.3%1.1%Expected volatility65.3%74.2%Weighted-average grant date fair value per share$36.54$58.53





The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future





The following table presents the change in non-vested market-based awards during 2012 :


SharesWeighted-AverageGrant-DateFair Value per ShareNon-vested at December 31, 201143,081$42.05Granted30,54136.54Forfeited(32,926)45.15Non-vested at December 31, 201240,69639.22





As of/Year Ended December 31,201220112010(in thousands, except per share data)Total intrinsic value of market-based awards vested$—$366$—Total intrinsic value of market-based awards non-vested1,3521,5133,361Market price per common share as of December 31,33.2135.1142.25Weighted-average grant date fair value per share36.5458.53—





Total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of December 31, 2012 was $0.9 million . This cost is expected to be recognized over a weighted-average period of 1.8 years.





Treasury Share Purchases





In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2004 Plan are retired, while those issued pursuant to the 2010 Plan are reissued to service awards. For shares that are retired, we first charge any excess of cost over the par value to additional paid-in-capital ("APIC") to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2012 , we acquired 44,576 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 14,471 shares were retired, 28,587 and 1,518 shares were reissued and are available for reissuance, respectively, pursuant to our 2010 Plan.





F- 30


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


Shareholders’ Rights Agreement





In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record on September 14, 2007 . A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire on September 11, 2017 .





Preferred stock





We are authorized, pursuant to shareholder approval in 2008 , to issue 50,000,000 shares of Company preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2012 , no preferred shares had been issued.





NOTE 13 - EARNINGS PER SHARE





Basic earnings per common share ("EPS") is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly computed except that the denominator includes the effect, using the treasury stock method, of our unamortized portion of restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.





The following table presents a reconciliation of the weighted-average diluted shares outstanding:





Year Ended December 31,201220112010(in thousands)Weighted-average common shares outstanding - basic27,67723,52119,674Dilutive effect of share-based compensation:Restricted stock—307119SARs—4021Non-employee director deferred compensation—37Weighted-average common and common share equivalents outstanding - diluted27,67723,87119,821





The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect:





Year Ended December 31,201220112010(in thousands)Weighted-average common share equivalents excluded from diluted earningsper share due to their anti-dilutive effect:Restricted stock694220204SARs11622—Stock options7910Non-employee director deferred compensation3——Total anti-dilutive common share equivalents820251214





For 2012, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive.





In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount per note, that give the holders the right to convert the aggregate principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible notes could have a dilutive impact on our earnings per share if the average market share price exceeds the $42.40 conversion price. The average market share price did not exceed the conversion price during 2012 , 2011 or 2010 .


F- 31


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued





NOTE 14 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS





Selected financial information . The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold, net of liabilities, that were or are expected to be assumed by the purchaser. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations.





The following table presents balance sheet data related to assets held for sale:


As of December 31,2011Balance SheetNet Assets Held for Sale(in thousands)AssetsCurrent assetsAccounts receivable, net$—Oil inventory—Total current assets—Properties and equipment168,218Accumulated Depreciation, Depletion and Amortization(19,969)Total assets$148,249LiabilitiesCurrent liabilitiesAccounts payable—Production tax liability—Total current liabilities—Asset retirement obligation2,022Total liabilities$2,022Net assets$146,227





F- 32


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents statement of operations data related to our discontinued operations:





Year Ended December 31,Statements of Operations - Discontinued Operations201220112010(in thousands)RevenuesNatural gas, NGLs and crude oil sales$36,422$80,860$70,111Sales from natural gas marketing1,7082,9497,164Well operations, pipeline income and other1,8882,5424,149Total revenues40,01886,35181,424Costs, expenses and otherProduction costs22,45330,88537,891Cost of natural gas marketing1,5292,6346,547Impairment of natural gas and crude oil properties162,25422,8586,777Depreciation, depletion and amortization48,10147,52144,944Accretion of asset retirement obligations and other2,0841,0544,976Gain on sale of properties and equipment(19,920)(3,854)—Total costs, expenses and other216,501101,098101,135Income (loss) from discontinued operations(176,483)(14,747)(19,711)Provision for income taxes67,4665,6207,581Income (loss) from discontinued operations, net of tax$(109,017)$(9,127)$(12,130)





Piceance Basin and NECO. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. The cash consideration was subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. On June 18, 2013 , this divestiture was completed with total proceeds received of approximately $185.2 million , subject to customary post-closing adjustments and net of our non-affiliated investor partners' share of $17.0 million . The proceeds from the asset disposal will be used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale to Caerus, we  do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the consolidated statement of operations for all periods presented. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations.





Permian Basin. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million . Additionally, on December 20, 2011, we executed a purchase and sale agreement with COG Operating LLC (“COG”), a wholly owned subsidiary of Concho Resources Inc., an unrelated third-party, for the sale of our core Permian Basin assets for a sale price of $173.9 million , subject to customary terms and adjustments, including adjustments based on title and environmental due diligence to be conducted by COG. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of, or cash flows from, these assets; accordingly, the Permian assets were reclassified as held for sale as of December 31, 2011, and the results of operations related to those assets have been separately reported as discontinued operations in the consolidated statement of operations for all periods presented. On February 28, 2012, the divestiture closed. Upon final settlement, total proceeds received were $189.2 million after closing adjustments, resulting in a pre-tax gain on sale of $19.9 million .





North Dakota. In December 2010, we executed a letter of intent with an unrelated third-party for the sale of our North Dakota assets. In February 2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million , net of our non-affiliated investor partners' share of $3.8 million , resulting in a pre-tax gain on sale of $3.9 million . Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in the consolidated statements of operations for 2011 and 2010.





Michigan .  During the third quarter of 2010, we divested our Michigan asset group and related liabilities for net cash proceeds of $22 million and realized a loss on sale of $4.7 million in the form of an impairment charge recorded during 2010 (see Note 6, Properties and Equipment , regarding the impairment charge). We do not have significant continuing involvement in the operations of or cash flows from this asset group. Accordingly, the results of operations related to the Michigan assets have been reported as discontinued operations in the consolidated statement of operations for 2010.





F- 33


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 15 - ACQUISITIONS





The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of natural gas and crude oil properties during 2012 , 2011 and 2010 :





Year Ended December 31,201220112010Merit (1)Seneca-Upshur2003/2002-D Partnerships2005 PartnershipsPermian2004 Partnerships(in thousands)Total acquisition cost$304,643$69,618$29,960$43,015$114,273$34,768Recognized 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$32,730Natural gas and crude oil properties - unproved151,42849,100——71,647—Other assets3,63110,1963,4553,848—3,396Total assets acquired335,31879,47131,39543,673117,23936,126Liabilities assumed:Asset retirement obligation13,8708,1574973002,351912Other accrued expenses10,100———615126Other liabilities6,7051,696938358—320Total liabilities assumed30,6759,8531,4356582,9661,358Total identifiable net assets acquired$304,643$69,618$29,960$43,015$114,273$34,768


___________


(1)    Assets acquired and liabilities assumed in the Merit Acquisition are subject to post-closing adjustments as more detailed analyses are completed and additional information is obtained about the acquired natural gas and crude oil properties.





The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are the most sensitive and subject to change.





2012 Acquisitions





Merit Acquisition. On June 29, 2012 , we completed the acquisition of certain Wattenberg Field oil and natural gas properties, leasehold mineral interests and related assets located in Weld, Adams and Boulder Counties, Colorado from affiliates of Merit Energy, an unrelated third-party. The aggregate purchase price of these properties was approximately $304.6 million , after post-closing adjustments. We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit facility.





This acquisition was accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.





Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 29, 2012 closing date, including approximately $11.4 million of total revenue and $9.5 million of income from operations. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 and December 31, 2011 , assuming the Merit Acquisition had been completed as of January 1, 2011, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results.


F- 34


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


Year Ended December 31,20122011(in thousands, except per share amounts)Total revenues$370,488$438,204Total costs, expenses and other521,178366,120Net income (loss)$(119,343)$45,688Earnings per share:Basic$(4.31)$1.94Diluted$(4.31)$1.91





2011 Acquisitions





Seneca-Upshur . In October 2011, PDCM acquired from an unrelated third-party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur") for a purchase price of $139.2 million ( $69.6 million net to PDC), after post-closing adjustments, which was funded by capital contributions by PDCM's investing partners and a draw on PDCM's revolving credit facility. Substantially all of the acreage acquired is held by production, prospective for the Marcellus Shale and is in close proximity to PDCM's existing properties. Following the closing, several title defects were discovered that were not cured by the seller within the time specified by the purchase and sale agreement. Accordingly, PDCM received title defect payments during 2012 totaling $28.9 million , of which $14.5 million represents our share, the effect of which is reflected in the purchase price noted above.





2003/2002-D Partnerships . In October 2011, we acquired from non-affiliated investor partners the remaining working interest in five of our affiliated partnerships: PDC 2002-D Limited Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership and PDC 2003-C Limited Partnership and (the "2002/2003 Partnerships"). We purchased the 2002/2003 Partnerships for an aggregate amount of $30 million , which was funded from our revolving credit facility. These purchases included the non-affiliated investor partners' remaining working interests in wells located in the Wattenberg Field and Piceance Basin.





2005 Partnerships . In June 2011, we acquired from non-affiliated investor partners the remaining working interest in three of our affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership (the "2005 Partnerships"). We purchased the 2005 Partnerships for an aggregate amount of $43 million , which was funded from our revolving credit facility. These purchases included the non-affiliated investor partners' remaining working interests wells located in the Wattenberg Field and Piceance Basin.





Pro Forma Information . The results of operations for the Seneca-Upshur, 2002/2003 Partnerships and 2005 Partnerships acquisitions have been included in our consolidated financial statements from the respective dates of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying statements of operations.





2010 Acquisitions





2004 Partnerships . In December 2010, we acquired the remaining working interest in four of our affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (the “2004 Partnerships”). We purchased these partnerships for an aggregate amount of $36.5 million , which was funded from our revolving credit facility. These purchases included the remaining working interests in wells located in the Wattenberg Field and Piceance Basin.





Permian Basin . In July 2010, we acquired various producing assets located in the Wolfberry Trend in the Permian Basin in West Texas (the “Wolfberry Assets”). In conjunction with the divestiture of our Michigan asset group, we entered into a like-kind exchange agreement with a qualified intermediary. The Wolfberry Assets were identified as our replacement property in accordance with IRC Section 1031. Sales proceeds of $19.3 million from the Michigan divestiture were transferred directly to the qualified intermediary and, along with $55.7 million from our revolving credit facility, funded the purchase of the Wolfberry Assets. The sale of our Michigan assets resulted in a gain for income tax purposes of $19.2 million , which then resulted in a tax liability of $7.3 million . With the favorable deferral aspects of IRC Section 1031, we were able to defer $6.5 million of this tax liability. In November 2010, we acquired for $39.4 million in cash a second position in the Wolfberry oil trend, including 100% of the interest in producing assets and undeveloped acreage.





Pro Forma Information . The results of operations for the 2004 Partnerships and Wolfberry Assets acquisition have been included in our consolidated financial statements from the respective dates of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying statements of operations.





F- 35


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued





NOTE 16 - NONCONTROLLING INTEREST IN SUBSIDIARY





In 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (the "LLC"), a limited liability company for which we served as the managing member. The LLC's only asset was an aircraft and was formed for the purpose of owning and operating the aircraft. We consolidated the entity based on a controlling financial interest. In 2011, we divested the asset and dissolved the entity with no material impact on our financial statements.





NOTE 17 - TRANSACTIONS WITH AFFILIATES





Former Executive Officer. In June 2011, Richard W. McCullough resigned from his positions as our Chief Executive Officer and the Chairman of the Board, effective immediately. In connection with his resignation, in July 2011, Mr. McCullough and the Company executed a separation agreement, whereby Mr. McCullough will receive those benefits to which he was entitled under Section 7(d) of his employment agreement, dated as of April 19, 2010, including without limitation, separation compensation in the amount of $4.1 million , less required withholdings, his annual non-qualified deferred supplemental retirement benefit equal to $30,000 for each of the years 2012 through 2021 (not accelerated), less required withholdings, continued coverage under the Company’s group health plans at the Company’s cost for a period equal to the lesser of 18 months or such period ending as of the date Mr. McCullough is eligible to participate in another employer’s group health plan, immediate vesting of any unvested Company stock options, SARs and restricted stock and issuance of shares representing the vested portion of his 2009 performance share awards. Related to this separation agreement, the statement of operations for 2011 reflects a charge to general and administrative expense of $6.7 million .





PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the Eastern Operating Region.





Amounts due from/to the affiliated partnerships are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production.





The following table presents amounts included in our consolidated statement of operations related to the marketing of natural gas on behalf of PDCM and our affiliated partnerships and amounts included in our consolidated balance sheet related to the derivative instruments we entered into on behalf of our affiliated partnerships:





As of/Year Ended December 31,201220112010(in thousands)PDCM:Sales from natural gas marketing$11,105$9,735$4,298Cost of natural gas marketing10,8889,5444,214Affiliated Partnerships:Sales from natural gas marketing5351,276651Cost of natural gas marketing5241,251638Receivable from affiliates2,1406,16314,616Payable to affiliates4,70714,15220,342





We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $12.1 million , $10.4 million and $11.1 million in 2012 , 2011 and 2010 , respectively. Our statements of operations include only our proportionate share of these billings. The following table presents the statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented.


Year Ended December 31,Statement of Operations Line Item201220112010(in thousands)Production Costs$3,945$3,441$3,862Exploration Expense492430883General and Administrative Expense1,6301,5431,899





F- 36


---

PDC ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 18 - BUSINESS SEGMENTS





We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.





Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGLs and crude oil. Segment revenue includes natural gas, NGLs and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of natural gas and crude oil properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $139.4 million , $122.2 million and $105.9 million in 2012 , 2011 and 2010 , respectively.





Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense.





Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense.





The following tables present our segment information:





201220112010(in thousands)Year Ended December 31,Revenues:Oil and Gas Exploration and Production$275,234$273,819$211,380Gas Marketing45,37163,47065,235Total Revenues$320,605$337,289$276,615Segment income (loss) from continuing operations before income taxes:Oil and Gas Exploration and Production$103,111$138,616$104,334Gas Marketing349639509Unallocated(137,856)(104,891)(78,760)Total$(34,396)$34,364$26,083Expenditures for segment long-lived assets:Oil and Gas Exploration and Production$656,443$479,027$319,268Unallocated3,5091,3631,506Total$659,952$480,390$320,774As of December 31,Segment assets:Oil and Gas Exploration and Production$1,723,011$1,461,130Gas Marketing11,09014,713Unallocated92,74773,913Assets held for sale—148,249Total Assets$1,826,848$1,698,005





NOTE 19 - SUBSEQUENT EVENTS





On June 18, 2013 , we closed on the divestiture of our Piceance Basin, NECO and certain non-core Colorado oil and gas properties for cash consideration of approximately $185.2 million .


F- 37


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


SUPPLEMENTAL INFORMATION - UNAUDITED





NATURAL GAS AND CRUDE OIL INFORMATION - UNAUDITED





Net Proved Reserves





All of our natural gas, NGLs and crude oil reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our natural gas, crude oil, condensate and NGL reserves. As of December 31, 2012 , 2011 and 2010, all of our reserve estimates were based on reserve reports prepared by Ryder Scott Company, L.P. ("Ryder Scott"). These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.





Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas, NGLs and crude oil expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities.





The price used to estimate our reserves, by commodity, are presented below.





Price Used to Estimate ReservesAs of December 31,Natural Gas(per Mcf)NGLs(per Bbl)Crude Oil(per Bbl)2012$2.35$28.02$87.5120113.4139.5988.9420103.5434.1271.95























F- 38


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


The following tables present the changes in our estimated quantities of proved reserves:





Natural Gas(MMcf)NGLs(MBbls)Crude Oil, Condensate (MBbls)Total(MMcfe)Proved Reserves:Proved reserves, January 1, 2010608,925—18,070717,345Revisions of previous estimates6,5048,908(85)59,442Extensions, discoveries and other additionsWestern Operating Region56,5248112,24774,872Eastern Operating Region35,092——35,092Purchases of reservesWestern Operating Region20,9201,5314,36756,308Eastern Operating Region220——220Other————Dispositions(43,690)—(55)(44,020)Production(27,189)(601)(1,308)(38,643)Proved reserves, December 31, 2010657,30610,64923,236860,616Revisions of previous estimates(161,654)3,163(1,904)(154,100)Extensions, discoveries and other additionsWestern Operating Region125,3745,63317,092261,724Eastern Operating Region51,315——51,315Purchases of reservesWestern Operating Region24,7761,0521,58140,574Eastern Operating Region7,985—248,129Dispositions(2,070)(94)(435)(5,244)Production(30,887)(815)(1,958)(47,525)Proved reserves, December 31, 2011 (1)672,14519,58837,6361,015,489Revisions of previous estimates(289,436)(3,671)(6,729)(351,836)Extensions, discoveries and other additionsWestern Operating Region116,20511,63727,482350,919Eastern Operating Region56,728——56,728Purchases of reservesWestern Operating Region87,1898,08410,801200,499Eastern Operating Region23——23Dispositions(6,406)(1,970)(7,854)(65,350)Production(32,410)(841)(2,026)(49,612)Proved reserves, December 31, 2012 (2)604,03832,82759,3101,156,860


Proved Developed Reserves, as of:January 1, 2010258,375—6,244295,839December 31, 2010227,3414,0138,287301,141December 31, 2011 (1)299,36911,75316,910471,347December 31, 2012 (2)281,92514,35320,412490,515Proved Undeveloped Reserves, as of:January 1, 2010350,550—11,826421,506December 31, 2010429,9656,63614,949559,475December 31, 2011 (1)372,7767,83520,726544,142December 31, 2012 (2)322,11318,47438,898666,345


__________


|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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 Exhibit 99.1 for additional details related to the divestiture of our Permian asset group. Total proved reserves included6,242MMcf of natural gas,7,825MBbls of crude oil and1,970MBbls of NGLs, for an aggregate of65,018MMcfe of natural gas equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included1,750MMcf,1,815MBbls,550MBbls and15,940MMcfe, respectively, and proved undeveloped reserves included4,492MMcf,6,010MBbls,1,420MBbls and49,078MMcfe, respectively.

F- 39


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Includes estimated reserve data related to our Piceance and NECO assets, which were divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations, to our consolidated financial statements included elsewhere in this Exhibit 99.1 for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include83,656MMcf of natural gas and148MBbls of crude oil, for an aggregate of84,544MMcfe of natural gas equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012.




DevelopedUndevelopedTotal(MMcfe)Beginning proved reserves, January 1, 2011301,141559,475860,616Undeveloped reserves converted to developed43,597(43,597)—Revisions of previous estimates73,643(227,743)(154,100)Extensions, discoveries and other additions58,979254,060313,039Purchases of reserves46,7561,94748,703Dispositions(5,244)—(5,244)Production(47,525)—(47,525)Ending proved reserves, December 31, 2011471,347544,1421,015,489Undeveloped reserves converted to developed45,929(45,929)—Revisions of previous estimates(109,909)(241,927)(351,836)Extensions, discoveries and other additions67,787339,860407,647Purchases of reserves81,253119,269200,522Dispositions(16,280)(49,070)(65,350)Production(49,612)—(49,612)Ending proved reserves, December 31, 2012490,515666,3451,156,860





2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 352 Bcfe. The revision was primarily due to a decrease of approximately 240 Bcfe due to lower gas pricing, mostly related to the Piceance Basin, approximately 6 Bcfe due to increased operating costs, approximately 46 Bcfe due to adjustments for geological reasons and approximately 77 Bcfe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 3 Bcfe due to non-acquisition interest adjustments and approximately 14 Bcfe due to asset performance. Discoveries and extensions of approximately 408 Bcfe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 57 Bcfe were added in the Eastern Operating Region related to the Marcellus Shale and approximately 351 Bcfe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 201 Bcfe of proved reserves, approximately 200 Bcfe due to an acquisition in the Wattenberg Field. We divested a total of 65 Bcfe in 2012, primarily our core Permian Basin assets.  Based on the economic conditions on December 31, 2012, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Based on our decision to drill predominantly horizontal wells in 2012, our drilling program focused on locations that were not included in proved undeveloped reserves in the December 2011 reserve report. By focusing on non-PUD drilling locations in 2012, we were able to add considerable PUD reserves in the 2012 reserve report. In 2013, we anticipate the majority of our drilling to be focused on horizontal well locations that are included in our proved undeveloped reserves in the 2012 reserve report. Therefore, we expect to convert 15% to 20% of our PUDs to proved developed producing reserves in 2013. This level of capital spending is consistent with the most recent years.





2011 Activity. In 2011 , we recorded a downward revision of our previous estimate of proved reserves of approximately 154 Bcfe. The revision was primarily due to a decrease of approximately 4 Bcfe due to lower gas pricing and approximately 173 Bcfe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 6 Bcfe due to increased efficiencies in operating costs, approximately 5 Bcfe due to non-acquisition interest adjustments and approximately 12 Bcfe due to asset performance. In addition, the “Revisions of previous estimates” line item includes a deduction in the “Undeveloped” column and an increase in the “Developed” column of approximately 125 Bcfe. These reserves were transferred from proved undeveloped to proved developed as a result of the Company's determination that costs related to a refracture became less significant as compared to the costs associated with drilling a new well. Discoveries and extensions of approximately 313 Bcfe in 2011 are due to the drilling of 195 gross wells and the addition of new proved undeveloped reserves. Approximately 51 Bcfe were added in the Eastern Operating Region, approximately 262 Bcfe were added in the Western Operating Region ( 141 Bcfe in the Wattenberg Field, 80 Bcfe in the Piceance Basin and 41 Bcfe in the Permian Basin). We acquired approximately 49 Bcfe of proved reserves, approximately 8 Bcfe through acquisitions in the Eastern Operating Region, and approximately 41 Bcfe in the Western Operating Region ( 28 Bcfe were acquired in the Wattenberg Field and 13 Bcfe were acquired in the Piceance Basin) due to the repurchase of the 2003/2002-D and 2005 Partnerships as well as the purchase of interests in some of our other existing properties. We divested a total of approximately 5 Bcfe in 2011 . This included the sale of 100% of our North Dakota assets, or 2 Bcfe, to an unrelated third-party and our non-core Permian Basin assets, or 3 Bcfe, to unrelated third parties.





F- 40


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


2010 Activity. In 2010, we revised our previous estimate of proved reserves upward by 59.4 Bcfe. The revision was primarily due to an increase of 55.6 Bcfe due to asset performance, 35.9 Bcfe due to higher commodity pricing, 28.1 Bcfe due to the impact of evaluating NGLs as a separate stream and 1.5 Bcfe due to interest adjustments. This was partially offset by a decrease of 58.7 Bcfe due to adjustments for geological reasons or reclassification of prior period proved undeveloped reserves to probable reserves due to aging and 3 Bcfe due to increased operating costs. Discoveries and extensions of 110 Bcfe in 2010 are due to drilling of 213 gross wells and the addition of new proved undeveloped reserves: 35.1 Bcfe were added in the Eastern Operating Region and 74.9 Bcfe were added in the Western Operating Region ( 29.4 Bcfe in Wattenberg Field, 36.2 Bcfe in the Piceance Basin, 9.1 Bcfe in the NECO area and 0.2 Bcfe in North Dakota) and Permian Basin. We acquired 56.5 Bcfe of proved reserves, approximately 32.6 Bcfe through two acquisitions in the Permian Basin, and 23.9 Bcfe in both the Western and Eastern Operating Regions due to the repurchase of the 2004 Partnerships as well as the purchase of interests in some of our other existing properties. Of the 23.9 Bcfe, 12.8 Bcfe were acquired in the Wattenberg Field and 10.9 Bcfe were acquired in the Piceance Basin. Total dispositions of 44 Bcfe in 2010 included the deconsolidation of PDCM, or 28.9 Bcfe, and the sale of all of our Michigan assets, or 15.1 Bcfe, to an unaffiliated third-party.





Results of Operations for Natural Gas and Crude Oil Producing Activities





The results of operations for natural gas and crude oil producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services.





Year Ended December 31,201220112010(in thousands)Revenue:Natural gas, NGLs and crude oil sales$274,783$304,157$216,159Commodity price risk management gain, net32,33946,09059,891307,122350,247276,050Expenses:Production costs77,53775,71760,121Exploration expense22,6056,28920,291Impairment of proved natural gas and oil properties162,28725,1594,666Depreciation, depletion, and amortization146,879128,458103,303Accretion of asset retirement obligations4,0601,8971,423Gain on sale of  properties and equipment(24,273)(4,050)(174)389,095233,470189,630Results of operations for natural gas and crude oil producingactivities before provision for income taxes(81,973)116,77786,420Provision for income taxes31,163(36,785)(5,937)Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs$(50,810)$79,992$80,483





Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates.





F- 41


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities





Costs incurred in natural gas and crude oil property acquisition, exploration and development are presented below.





Year Ended December 31,201220112010(in thousands)Acquisition of properties: (1)Proved properties$105,303$79,554$87,241Unproved properties276,22595,08184,636Development costs (2)233,144301,008138,018Exploration costs: (3)Exploratory drilling18,8033,62621,223Geological and geophysical1,9251,8462,367Total 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 endedDecember 31, 2012,2011and2010,$62.0 million,$80.6 millionand$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.




Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities





Aggregate capitalized costs related to natural gas and crude oil exploration and production activities with applicable accumulated DD&A are presented below:





As of December 31,20122011(in thousands)Proved natural gas and crude oil properties$2,075,924$1,694,847Unproved natural gas and crude oil properties319,327102,466Capitalized costs2,395,2511,797,313Less accumulated DD&A(905,458)(621,074)Capitalized costs, net$1,489,793$1,176,239





Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves





The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu  content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties.





The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for natural gas, NGLs and crude oil, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.





F- 42


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


As of December 31,201220112010(in thousands)Future estimated cash flows$7,529,292$6,415,255$4,361,095Future 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 flows2,756,3682,289,6241,314,64210% 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





The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:





Year Ended December 31,201220112010(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)95,501383,293180,124Extensions, discoveries, and improved recovery, less related costs (2)632,781467,34788,637Sales of reserves (3)(86,902)(4,224)(24,174)Purchases of reserves (4)296,20864,76145,538Development costs incurred during the period69,19894,94144,491Revisions of previous quantity estimates (5)(452,775)(112,468)47,884Changes 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 discount124,10565,28435,951Timing and other(121,247)(45,712)32,587Total$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$3.45from$3.19resulting 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) | The35%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, a30%increase,52.2%of which was gas and47.8%was liquids. Approximately86%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, were427%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 and16.7%of which was liquids. At December 31, 2011, extensions, discoveries and other additions had increased to 313,039 MMcfe, a185%increase,56.4%of which was gas and43.6%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 drilled17horizontal Niobrara wells and80vertical wells, completed190zones and participated in48non-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 approximately38.2%,38.1%and38%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.




It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot


F- 43


---

PDC ENERGY, INC.
 SUPPLEMENTAL INFORMATION
 (Unaudited)


be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.





F- 44


---

PDC ENERGY, INC.





QUARTERLY FINANCIAL INFORMATION - UNAUDITED





Quarterly financial data for the years ended December 31, 2012 and 2011 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share attributable to shareholders due to changes in the weighted-average shares outstanding throughout the year.





2012Quarter EndedMarch 31June 30September 30December 31Year Ended(in thousands, except per share data)Revenues:Natural gas, NGLs and crude oil sales$66,955$51,342$52,291$67,773$238,361Sales from natural gas marketing11,3818,61311,17814,19945,371Commodity price risk management gain (loss), net11,50138,729(31,943)14,05232,339Well operations, pipeline income and other1,1691,0561,1941,1154,534Total revenues91,00699,74032,72097,139320,605Costs, expenses and other:Production costs12,93612,37315,79713,59454,700Cost of natural gas marketing11,0918,49011,26014,18245,023Exploration expense1,8722,3741,77314,87520,894Impairment of natural gas and crude oil properties5883563884,5635,895General and administrative expense14,70814,37813,71016,01958,815Depreciation, depletion and amortization27,91223,83922,12124,90698,778Accretion of asset retirement obligations7277321,1011,1273,687Gain on sale of properties and equipment(154)(2,246)(1,508)(445)(4,353)Total costs, expenses and other69,68060,29664,64288,821283,439Income (loss) from operations21,32639,444(31,922)8,31837,166Loss on extinguishment of debt———(23,283)(23,283)Interest expense(10,444)(10,053)(11,360)(16,430)(48,287)Interest income2—338Income (loss) from continuing operations before income taxes10,88429,391(43,279)(31,392)(34,396)Provision for income taxes(4,120)(10,213)15,26811,76612,701Income (loss) from continuing operations6,76419,178(28,011)(19,626)(21,695)Income (loss) from discontinued operations, net of tax9,071(6,907)(4,632)(106,549)(109,017)Net income (loss)$15,835$12,271$(32,643)$(126,175)$(130,712)Earnings per share:BasicIncome (loss) from continuing operations$0.29$0.72$(0.93)$(0.65)$(0.78)Income (loss) from discontinued operations0.38(0.26)(0.15)(3.52)(3.94)Net income (loss)$0.67$0.46$(1.08)$(4.17)$(4.72)DilutedIncome (loss) from continuing operations$0.28$0.72$(0.93)$(0.65)$(0.78)Income (loss) from discontinued operations0.37(0.26)(0.15)(3.52)(3.94)Net income (loss)$0.66$0.46$(1.08)$(4.17)$(4.72)Weighted-average common shares outstanding:Basic23,60926,59730,21430,23327,677Diluted23,88926,72830,21430,23327,677


F- 45


---

PDC ENERGY, INC.























2011Quarter EndedMarch 31June 30September 30December 31Year Ended(in thousands, except per share data)Revenues:Natural gas, NGLs and crude oil sales$43,820$53,424$57,840$68,213$223,297Sales from natural gas marketing14,44618,08416,43614,50463,470Commodity price risk management gain (loss), net(23,882)20,53746,7062,72946,090Well operations, pipeline income and other1,0851,1491,1261,0724,432Total revenues35,46993,194122,10886,518337,289Costs, expenses and other:Production costs10,6869,88310,80813,45544,832Cost of natural gas marketing14,32417,48516,52614,49662,831Exploration expense1,4941,1091,0312,1005,734Impairment of natural gas and crude oil properties4513763841,0902,301General and administrative expense13,87319,50913,68314,38961,454Depreciation, depletion and amortization19,75720,57421,36025,94287,633Accretion of asset retirement obligations2752762925551,398Gain on sale of properties and equipment——(32)(164)(196)Total costs, expenses and other60,86069,21264,05271,863265,987Income (loss) from operations(25,391)23,98258,05614,65571,302Interest expense(9,062)(9,067)(9,496)(9,360)(36,985)Interest income9236—47Income (loss) from continuing operations before income taxes(34,444)14,91748,5965,29534,364Provision for income taxes13,105(4,307)(18,651)(1,947)(11,800)Income (loss) from continuing operations(21,339)10,61029,9453,34822,564Income from discontinued operations, net of tax1,415(1,445)2,615(11,712)(9,127)Net income (loss)(19,924)9,16532,560(8,364)13,437Earnings per share:BasicIncome (loss) from continuing operations$(0.91)$0.45$1.27$0.15$0.96Income from discontinued operations0.06(0.06)0.11(0.50)(0.39)Net income (loss) attributable to shareholders$(0.85)$0.39$1.38$(0.35)$0.57DilutedIncome (loss) from continuing operations$(0.91)$0.45$1.26$0.15$0.95Income from discontinued operations0.06(0.07)0.11(0.50)(0.39)Net income (loss) attributable to shareholders$(0.85)$0.38$1.37$(0.35)$0.56Weighted-average common shares outstandingBasic23,42823,49123,56923,59223,521Diluted23,42823,72323,78323,59223,871





F- 46


---

PDC ENERGY, INC.


FINANCIAL STATEMENT SCHEDULE





Schedule II -VALUATION AND QUALIFYING ACCOUNTS





DescriptionBeginningBalanceJanuary 1Deconsolidation/Purchase Price Adjustment for PDCMCharged toCosts andExpensesDeductions (1)EndingBalanceDecember 31(in thousands)2012:Allowance for doubtful accounts$921$—$258$153$1,026Valuation allowance for unproved natural gas and crude oil properties12,204—4,2078,3758,0362011:Allowance for doubtful accounts68612113521921Valuation allowance for unproved natural gas and crude oil properties16,9962602,6117,14312,2042010:Allowance for doubtful accounts54813530734686Valuation allowance for state tax benefits747——747—Valuation allowance for unproved natural gas and crude oil properties15,001196,1204,10616,996


___ ____________


|    |                                                                                                                                                                                                                                                                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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.

F- 47