NATURAL GAS AND CRUDE OIL INFORMATION - UNAUDITED

Net Proved Reserves

All of our natural gas, NGL 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, 2011, all of our reserve estimates were based on a reserve report 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, NGL 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 Reserves
As of December 31,	Natural Gas (per Mcf)		NGLs (per Bbl)		Crude Oil (per Bbl)

2011	$	3.41	$	39.59	$	88.94
2010	3.54		34.12		71.95
2009 (1)	3.17		—		54.64

__________


(1)	Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2011 and 2010 to 2009.

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



	Natural Gas (MMcf)		NGLs (MBbls) (1)		Crude Oil, Condensate (MBbls)		Total (MMcfe)
Proved Reserves:
Proved reserves, January 1, 2009	662,857		—		15,037		753,079
Revisions of previous estimates	(101,923	)	—		2,957		(84,181	)
Extensions, discoveries and other additions
Western Operating Region	79,574		—		1,322		87,506
Eastern Operating Region	3,190		—		—		3,190
Purchases of reserves
Western Operating Region	648		—		47		930
Eastern Operating Region	59		—		—		59
Other	63		—		—		63
Dispositions	(7	)	—		(1	)	(13	)
Production	(35,536	)	—		(1,292	)	(43,288	)
Proved reserves, December 31, 2009	608,925		—		18,070		717,345
Revisions of previous estimates	6,504		8,908		(85	)	59,442
Extensions, discoveries and other additions
Western Operating Region	56,524		811		2,247		74,872
Eastern Operating Region	35,092		—		—		35,092
Purchases of reserves
Western Operating Region	20,920		1,531		4,367		56,308
Eastern Operating Region	220		—		—		220
Dispositions	(43,690	)	—		(55	)	(44,020	)
Production	(27,189	)	(601	)	(1,308	)	(38,643	)
Proved reserves, December 31, 2010	657,306		10,649		23,236		860,616
Revisions of previous estimates	(161,654	)	3,163		(1,904	)	(154,100	)
Extensions, discoveries and other additions
Western Operating Region	125,374		5,633		17,092		261,724
Eastern Operating Region	51,315		—		—		51,315
Purchases of reserves
Western Operating Region	24,776		1,052		1,581		40,574
Eastern Operating Region	7,985		—		24		8,129
Dispositions	(2,070	)	(94	)	(435	)	(5,244	)
Production	(30,887	)	(815	)	(1,958	)	(47,525	)
Proved reserves, December 31, 2011 (2)	672,145		19,588		37,636		1,015,489



Proved Developed Reserves, as of:
January 1, 2009	297,041	—	5,438	329,669
December 31, 2009	258,375	—	6,244	295,839
December 31, 2010	227,341	4,013	8,287	301,141
December 31, 2011 (2)	299,369	11,753	16,910	471,347
Proved Undeveloped Reserves, as of:
January 1, 2009	365,816	—	9,599	423,410
December 31, 2009	350,550	—	11,826	421,506
December 31, 2010	429,965	6,636	14,949	559,475
December 31, 2011 (2)	372,776	7,835	20,726	544,142

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(1)	Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2011 and 2010 to 2009.

(2)

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 11, Commitments and Contingencies - Purchase and Sale Agreement, and Note 13, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian asset group. Total proved reserves include 6,242 MMcf of natural gas, 7,825 MBbls of crude oil, 1,971 MBbls of NGLs and 65,018 MMcfe of natural gas equivalent related to our Permian asset group. Similarly, total proved developed reserves include 1,750 MMcf, 1,815 MBbls, 550 MBbls and 15,940 MMcfe, respectively, and proved undeveloped reserves include 4,492 MMcf, 6,010 MBbls, 1,421 MBbls and 49,078 MMcfe, respectively.



	Developed		Undeveloped		Total
	(MMcfe)

Beginning proved reserves, January 1, 2010	295,839		421,506		717,345
Undeveloped reserves transferred to developed	17,967		(17,967	)	—
Revisions of previous estimates	16,782		42,660		59,442
Extensions, discoveries and other additions	21,572		88,392		109,964
Purchases of reserves	28,728		27,800		56,528
Dispositions	(41,104	)	(2,916	)	(44,020	)
Production	(38,643	)	—		(38,643	)
Ending proved reserves, December 31, 2010	301,141		559,475		860,616
Undeveloped reserves transferred to developed	43,597		(43,597	)	—
Revisions of previous estimates	73,643		(227,743	)	(154,100	)
Extensions, discoveries and other additions	58,979		254,060		313,039
Purchases of reserves	46,756		1,947		48,703
Dispositions	(5,244	)	—		(5,244	)
Production	(47,525	)	—		(47,525	)
Ending proved reserves, December 31, 2011	471,347		544,142		1,015,489

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 was removed from proved undeveloped reserves to satisfy 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, approximately 125 Bcfe were transfered from proved undeveloped to proved developed as a result of the Company's determination that costs related to a refracture becoming less significant as compared to the costs associated with drilling a new well. New 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 interest in some of our other existing properties. We divested a total of approximately 5 Bcfe in 2011. This included the sale of 100% of of our North Dakota assets, or 2 Bcfe, to an unrelated third party and our non-core Permian Basin assets, or 3 Bcfe, to another unrelated third party. Based on the economic conditions on December 31, 2011, we are reasonably certain that we would develop the balance of our proved undeveloped reserves within five years.

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 reserve decreases 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. New 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 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 interest 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 includes 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.

2009 Activity. In 2009, we revised our previous estimate of proved reserves downward by 84.2 Bcfe. The revision was primarily due to a decrease of 99.5 Bcfe due to lower commodity pricing and 45.1 Bcfe due to adjustments to reserves removed or reclassified due to new rules limiting proved undeveloped reserves locations to those scheduled to be drilled within the next five years. The downward adjustments were partially offset by an increase of 41.4 Bcfe due to decreased operating costs, 1 Bcfe due to interest adjustments and 17.9 Bcfe due to asset performance. New discoveries and extensions of 90.7 Bcfe in 2009 were due to drilling of 100 gross wells and the addition of new proved undeveloped reserves: 3.2 Bcfe in the Eastern Operating Region and 87.5 Bcfe in the Western Operating Region (13.7 Bcfe in Wattenberg Field, 73.3 Bcfe in the Piceance Basin and 0.5 Bcfe in North Dakota). We acquired 1.1 Bcfe of proved reserves through the purchase of interest in some of our existing properties. Reserves acquired were primarily in the Wattenberg Field, as were the reserves divested.

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,
	2011			2010			2009
	(in thousands)
Revenue:
Natural gas, NGL and crude oil sales	$	304,157		$	216,159		$	179,093
Commodity price risk management gain (loss), net	46,090			59,891			(10,053		)
	350,247			276,050			169,040
Expenses:
Production costs	77,614			61,544			57,825
Exploration expense	6,289			20,291			21,961
Depreciation, depletion, and amortization	128,458			103,303			125,415
Impairment of proved natural gas and oil properties	25,159			4,666			926
Gain on sale of properties and equipment	(4,050		)	(174		)	(470		)
	233,470			189,630			205,657
Results of operations for natural gas and crude oil producing activities before provision for income taxes	116,777			86,420			(36,617		)

Provision (benefit) for income taxes	36,785			5,937			(13,186		)

Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs	$	79,992		$	80,483		$	(23,431	)

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.

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,
	2011		2010		2009
	(in thousands)
Acquisition of properties: (1)
Proved properties	$	79,554	$	87,241	$	2,251
Unproved properties	95,081		84,636		5,867
Development costs (2)	301,008		138,018		72,416
Exploration costs: (3)
Exploratory drilling	3,626		21,223		18,317
Geological and geophysical	1,846		2,367		1,788
Total costs incurred	$	481,115	$	333,485	$	100,639

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(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, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store natural gas, NGLs and crude oil. Of these costs incurred for the years ended December 31, 2011, 2010 and 2009, $80.6 million, $37.4 million and $44.4 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, NGL and crude oil reserves.

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,
	2011		2010
	(in thousands)

Proved natural gas and crude oil properties (1)	$	1,694,847	$	1,481,191
Unproved natural gas and crude oil properties	102,466		85,502
	1,797,313		1,566,693
Less accumulated DD&A	621,074		492,501
	$	1,176,239	$	1,074,192

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(1)	As of December 31, 2011, we had no capitalized proved undeveloped natural gas and crude oil properties disclosed as such for longer than 5 years.

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 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 future pretax 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.



	As of December 31,
	2011			2010			2009
	(in thousands)

Future estimated cash flows	$	6,415,255		$	4,361,095		$	2,915,377
Future estimated production costs	(1,704,645		)	(1,418,044		)	(1,088,337		)
Future estimated development costs	(1,474,137		)	(1,119,604		)	(825,139		)
Future estimated income tax expense	(946,849		)	(508,805		)	(237,790		)
Future net cash flows	2,289,624			1,314,642			764,111
10% annual discount for estimated timing of cash flows	(1,348,415		)	(826,224		)	(416,475		)

Standardized measure of discounted future estimated net cash flows	$	941,209		$	488,418		$	347,636

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



	Year Ended December 31,
	2011			2010			2009
	(in thousands)

Sales of natural gas, NGL and crude oil production, net of production costs	$	(226,227	)	$	(163,104	)	$	(136,568	)
Net changes in prices and production costs	383,293			180,124			(107,766		)
Extensions, discoveries, and improved recovery, less related costs	467,347			88,637			30,851
Sales of reserves	(4,224		)	(24,174		)	(21		)
Purchases of reserves	64,761			45,538			1,266
Development costs incurred during the period	94,941			44,491			40,603
Revisions of previous quantity estimates	(112,468		)	47,884			(46,226		)
Changes in estimated income taxes	(204,377		)	(105,557		)	38,371
Net changes in future development costs	(29,827		)	(41,595		)	101,765
Accretion of discount	65,284			35,951			49,434
Timing and other	(45,712		)	32,587			19,122

Total	$	452,791		$	140,782		$	(9,169	)

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow 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 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.