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

EXECUTIVE SUMMARY

2012 Financial Overview

In 2012, our natural gas, NGLs and crude oil production from continuing operations averaged 135.6 MMcfe per day, an increase of approximately 10% 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 18.5% in 2012, while NGL production from continuing operations increased 17.0%. As a result, our liquids percentage of total production from continuing operations was 34.7% in 2012 compared 32.4% in 2011. Natural gas production increased 6.5% 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 28.9% year-over-year. The price of natural gas, however, rebounded significantly during the fourth quarter of 2012. During 2012, we recorded an impairment charge of $161.2 million related to our Piceance Basin proved oil and natural gas properties. 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. Realized gains from derivative transactions increased considerably to $49.4 million in 2012, compared to $17.2 million in 2011, an addition of approximately $0.99 per Mcfe sold during 2012.

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 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 report.

2013 Planned 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 have 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 derivatives, for aggregate cash consideration of approximately $200 million. The cash consideration is 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. 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 being 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 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction.

Production. Production from continuing operations increased significantly in 2012 as compared to 2011. In particular, primarily as a result of our Wattenberg Field drilling activities, oil production increased 18.5% and NGL production increased 17%. 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.

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating
results from continuing operations:
                                                                  Year Ended December 31,
                                                                                                       Change
                                           2012                2011               2010         2012-2011    2011-2010
                                           (dollars in millions, except per unit data)
Production (1)
Natural gas (MMcf)                        32,409.8            30,429.7            26,239.1         6.5  %      16.0  %
NGLs (MBbls)                                 841.3               719.2               569.6        17.0  %      26.3  %
Crude oil (MBbls)                          2,025.9             1,709.9             1,231.4        18.5  %      38.9  %
Natural gas equivalent (MMcfe) (2)        49,612.4            45,004.8            37,044.9        10.2  %      21.5  %
Average MMcfe per day                        135.6               123.3               101.5        10.0  %      21.5  %
Natural Gas, NGLs and Crude Oil
Sales
Natural gas                          $        70.8       $        99.6       $        94.6       (28.9 )%       5.3  %
NGLs                                          23.0                27.2                22.6       (15.4 )%      20.4  %
Crude oil                                    176.5               149.8                91.1        17.8  %      64.4  %
Provision for underpayment of
natural gas sales                                -                   -                (3.3 )         -  %    (100.0 )%
Total natural gas, NGLs and crude
oil sales                            $       270.3       $       276.6       $       205.0        (2.3 )%      34.9  %

Realized Gain (Losses) on
Derivatives, net (3)
Natural gas                          $        49.9       $        29.1       $        40.0        71.5  %     (27.3 )%
Crude oil                                     (0.5 )             (11.9 )               7.1       (95.8 )%    (267.6 )%
Total realized gain on derivatives,
net                                  $        49.4       $        17.2       $        47.1       187.2  %     (63.5 )%

Average Sales Price (excluding
gain/loss on derivatives)
Natural gas (per Mcf)                $        2.18       $        3.27       $        3.61       (33.3 )%      (9.4 )%
NGLs (per Bbl)                               27.36               37.82               39.66       (27.7 )%      (4.6 )%
Crude oil (per Bbl)                          87.14               87.63               73.96        (0.6 )%      18.5  %
Natural gas equivalent (per Mcfe)             5.45                6.15                5.63       (11.4 )%       9.2  %

Average Sales Price (including
realized gain/loss on derivatives)
Natural gas (per Mcf)                $        3.72       $        4.23       $        5.13       (12.1 )%     (17.5 )%
NGLs (per Bbl)                               27.36               37.82               39.66       (27.7 )%      (4.6 )%
Crude oil (per Bbl)                          86.87               80.69               79.70         7.7  %       1.2  %
Natural gas equivalent (per Mcfe)             6.44                6.53                6.89        (1.4 )%      (5.2 )%

Average Lifting Cost (per Mcfe) (4)
Western operating region             $        0.77       $        0.87       $        1.01       (11.5 )%     (13.9 )%
Eastern operating region                      1.38                1.33                1.55         3.8  %     (14.2 )%
Weighted-average                              0.85                0.92                1.05        (7.6 )%     (12.4 )%

Natural Gas Marketing Contribution
Margin (5)                           $         0.5       $         0.9       $         1.1       (44.4 )%     (18.2 )%

Other Costs and Expenses
Exploration expense                  $        22.6       $         6.3       $        13.7       261.5  %     (54.3 )%
Impairment of natural gas and crude
oil properties                               168.1                25.2                 6.5           *        288.2  %
General and administrative expense            58.8                61.5                42.2        (4.3 )%      45.7  %
Depreciation, depletion, and
amortization                                 146.9               128.9               108.1        13.9  %      19.3  %

Loss on extinguishment of debt       $        23.3       $           -       $           -       100.0  %         -  %
Interest Expense                     $        48.3       $        37.0       $        33.3        30.6  %      11.2  %

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

Amounts may not recalculate due to rounding.

(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.

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,
                                                                             Change
Production by Operating Region     2012        2011        2010      2012-2011    2011-2010
 Natural gas (MMcf)
Western
Wattenberg Field                  9,845.2     8,980.2     7,229.7        9.6  %      24.2  %
Piceance Basin (1)               13,226.9    13,350.0    12,001.5       (0.9 )%      11.2  %
NECO, other (1)                   3,194.3     3,709.6     4,481.9      (13.9 )%     (17.2 )%
Total Western                    26,266.4    26,039.8    23,713.1        0.9  %       9.8  %
Eastern                           6,143.4     4,389.9     2,526.0       39.9  %      73.8  %
Total                            32,409.8    30,429.7    26,239.1        6.5  %      16.0  %
Crude oil (MBbls)
Western
Wattenberg Field                  1,979.7     1,670.9     1,190.3       18.5  %      40.4  %
Piceance Basin (1)                   37.7        33.2        33.1       13.6  %       0.3  %
NECO, other (1)                       0.4         1.0         2.1      (60.0 )%     (52.4 )%
Total Western                     2,017.8     1,705.1     1,225.5       18.3  %      39.1  %
Eastern                               8.1         4.8         5.9       68.8  %     (18.6 )%
Total                             2,025.9     1,709.9     1,231.4       18.5  %      38.9  %
NGLs (MBbls)
Western
Wattenberg Field                    837.3       712.1       561.1       17.6  %      26.9  %
NECO, other (1)                       4.0         7.1         8.5      (43.7 )%     (16.5 )%
Total                               841.3       719.2       569.6       17.0  %      26.3  %
Natural gas equivalent (MMcfe)
Western
Wattenberg Field                 26,747.0    23,278.4    17,738.4       14.9  %      31.2  %
Piceance Basin (1)               13,453.1    13,549.3    12,199.9       (0.7 )%      11.1  %
NECO, other (1)                   3,220.1     3,758.2     4,545.2      (14.3 )%     (17.3 )%
Total Western                    43,420.2    40,585.9    34,483.5        7.0  %      17.7  %
Eastern                           6,192.2     4,418.9     2,561.4       40.1  %      72.5  %
Total                            49,612.4    45,004.8    37,044.9       10.2  %      21.5  %

Amounts may not recalculate due to rounding.
(1) On February 4, 2013, we entered into a purchase and sale agreement pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture.

                                                        Year Ended December 31,
 Average Sales Price by
Operating Region                                                                      Change
(excluding gain/loss on
derivatives)                         2012           2011          2010        2012-2011     2011-2010
 Natural gas (per Mcf)
Western
Wattenberg Field                 $     2.61     $     3.52     $    3.70        (25.9 )%       (4.9 )%
Piceance Basin (1)                     1.67           2.82          3.38        (40.8 )%      (16.6 )%
NECO, other (1)                        2.08           3.26          3.60        (36.2 )%       (9.4 )%
Western                                2.07           3.12          3.52        (33.7 )%      (11.4 )%
Eastern                                2.66           4.15          4.44        (35.9 )%       (6.5 )%
Weighted-average price                 2.18           3.27          3.61        (33.3 )%       (9.4 )%
Crude oil (per Bbl)
Western
Wattenberg Field                      87.27          87.93         74.46         (0.8 )%       18.1  %
Piceance Basin (1)                    80.20          78.50         56.60          2.2  %       38.7  %
NECO, other (1)                       83.80         (95.33 )       40.23       (187.9 )%     (337.0 )%
Western                               87.14          87.63         73.95         (0.6 )%       18.5  %
Eastern                               86.43          87.09         77.10         (0.8 )%       13.0  %
Weighted-average price                87.14          87.63         73.96         (0.6 )%       18.5  %
NGLs (per Bbl)
Western
Wattenberg Field                      27.33          37.62         39.56        (27.4 )%       (4.9 )%
NECO, other (1)                       32.80          58.07         46.29        (43.5 )%       25.4  %
Weighted-average price                27.36          37.82         39.66        (27.7 )%       (4.6 )%
Natural gas equivalent (per
Mcfe)
Western
Wattenberg Field                       8.27           8.82          7.81         (6.2 )%       12.9  %
Piceance Basin (1)                     1.87           2.97          3.40        (37.0 )%      (12.6 )%
NECO, other (1)                        2.12           3.30          3.65        (35.8 )%       (9.6 )%
Western                                5.83           6.35          5.71         (8.2 )%       11.2  %
Eastern                                2.76           4.22          4.55        (34.6 )%       (7.3 )%
Weighted-average price                 5.45           6.15          5.63        (11.4 )%        9.2  %

Amounts may not recalculate due to rounding.

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

                                                          Year Ended December 31,
                                                        2012                   2011
                                                               (in millions)
Increase in production                           $           38.8       $           56.4
Decrease in average natural gas price                       (35.3 )                (10.2 )
Decrease in average NGL price                                (8.8 )                 (1.3 )
Increase (decrease) in average crude oil price               (1.0 )                 23.4
Decrease in provision for underpayment of
natural gas sales                                               -                    3.3
Total increase (decrease) in natural gas, NGLs
and crude oil sales revenue                      $           (6.3 )     $           71.6

Natural gas, NGLs and crude oil sales revenue in 2012 decreased 2.3% compared to 2011. The decrease was primarily attributable to the 33.3% and 27.7% declines in the average price of natural gas and NGLs, respectively, during 2012. The decrease was offset in part by significantly higher volumes sold, in particular liquids, which shifted our liquids percentage of total production to approximately 34.7% in 2012 compared to 32.4% in 2011. Our average daily sales volumes increased to 135.6 MMcfe per day in 2012 compared to 123.3 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 143 MMcfe per day compared to 139 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 16.8 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 . . .