NATURAL GAS INFORMATION - UNAUDITED

Net Proved Reserves

All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, condensate and NGL reserves. As of December 31, 2013, 2012 and 2011, all of our reserve estimates were based on reserve reports prepared by 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 crude oil, natural gas and NGLs 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,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)

2013	$	82.18	$	3.22	$	29.92
2012	87.51		2.35		28.02
2011	88.94		3.41		39.59

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



	Crude Oil, Condensate (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved Reserves:
Proved reserves, January 1, 2011	23,236		657,306		10,649		143,436
Revisions of previous estimates	(1,904	)	(161,654	)	3,163		(25,683	)
Extensions, discoveries and other additions	17,092		176,689		5,633		52,173
Purchases of reserves	1,605		32,761		1,052		8,117
Dispositions	(435	)	(2,070	)	(94	)	(874	)
Production	(1,958	)	(30,887	)	(815	)	(7,921	)
Proved reserves, December 31, 2011 (1)	37,636		672,145		19,588		169,248
Revisions of previous estimates	(6,729	)	(289,436	)	(3,671	)	(58,639	)
Extensions, discoveries and other additions	27,482		172,933		11,637		67,941
Purchases of reserves	10,801		87,212		8,084		33,420
Dispositions	(7,854	)	(6,406	)	(1,970	)	(10,891	)
Production	(2,026	)	(32,410	)	(841	)	(8,269	)
Proved reserves, December 31, 2012 (2)	59,310		604,038		32,827		192,810
Revisions of previous estimates	(18,420	)	(117,068	)	(8,549	)	(46,480	)
Extensions, discoveries and other additions	55,759		365,563		25,249		141,935
Purchases of reserves	343		2,894		217		1,043
Dispositions	(252	)	(94,927	)	(30	)	(16,104	)
Production	(2,910	)	(20,860	)	(1,043	)	(7,430	)
Proved reserves, December 31, 2013	93,830		739,640		48,671		265,774



Proved Developed Reserves, as of:
January 1, 2011	8,287	227,341	4,013	50,190
December 31, 2011 (1)	16,910	299,369	11,753	78,558
December 31, 2012 (2)	20,412	281,925	14,353	81,753
December 31, 2013	23,997	220,387	14,825	75,553
Proved Undeveloped Reserves, as of:
January 1, 2011	14,949	429,965	6,636	93,246
December 31, 2011 (1)	20,726	372,776	7,835	90,690
December 31, 2012 (2)	38,898	322,113	18,474	111,058
December 31, 2013	69,833	519,253	33,846	190,221

__________

(1)

Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively.

(2)

Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil 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.



	Developed		Undeveloped		Total
	(MBoe)

Beginning proved reserves, January 1, 2012	78,558		90,690		169,248
Undeveloped reserves converted to developed	7,655		(7,655	)	—
Revisions of previous estimates	(18,318	)	(40,321	)	(58,639	)
Extensions, discoveries and other additions	11,298		56,643		67,941
Purchases of reserves	13,542		19,878		33,420
Dispositions	(2,713	)	(8,178	)	(10,891	)
Production	(8,269	)	—		(8,269	)
Ending proved reserves, December 31, 2012	81,753		111,057		192,810
Undeveloped reserves converted to developed	3,212		(3,212	)	—
Revisions of previous estimates	(6,751	)	(39,729	)	(46,480	)
Extensions, discoveries and other additions	19,830		122,105		141,935
Purchases of reserves	1,043		—		1,043
Dispositions	(16,104	)	—		(16,104	)
Production	(7,430	)	—		(7,430	)
Ending proved reserves, December 31, 2013	75,553		190,221		265,774

2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, we recorded a downward revision of our previous estimate of proved reserves of approximately 46 MMBoe. The revision was primarily due to a decrease of approximately 55 MMBoe of which approximately 32 MMBoe is due to adjustments in previous PUD well spacing plans in the Wattenberg Field and the Marcellus Shale, which were offset by replacements in the extension category, approximately 9 MMBoe is due to expired leases, approximately 11 MMBoe is due to our shift from vertical to horizontal drilling in the Wattenberg Field and approximately 3 MMBoe is to remove Wattenberg Field PUDs that are no longer in our core drilling area. This was partially offset by an increase of 1 MMBoe due to higher gas pricing and lower operating costs in the vertical Wattenberg Field wells and horizontal Marcellus Shale wells, an increase of approximately 3 MMBoe due to non-acquisition interest adjustments, approximately 2 MMBoe due to asset performance and approximately 2 MMBoe due to production from wells that were either uneconomic, added or divested in the current year. Discoveries and extensions of approximately 142 MMBoe in 2013 are due to the addition of approximately 17 MMBoe of proved developed reserves from non-PUD drilling and the addition of approximately 125 MMBoe of new proved undeveloped reserves including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and the Marcellus Shale. Approximately 18 MMBoe was added in the Marcellus Shale, approximately 14 MMBoe was added in the Utica Shale and approximately 110 MMBoe was added in the Wattenberg Field, mostly related to the Niobrara and Codell formations. We acquired approximately 1 MMBoe of proved reserves due to an acquisition in the Appalachian-Marcellus Shale area and the acquisition of non-affiliated investor partner interests in shallow Upper Devonian wells. We divested a total of 16 MMBoe in 2013, primarily our Piceance Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. Based on the economic conditions on December 31, 2013, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2013 drilling program focused on locations that were not included in proved undeveloped reserves in the December 31, 2012 reserve report due to increased well density testing in the Wattenberg Field. The success of this increased well density testing allowed us to add considerable PUD reserves in the 2013 reserve report. Because we will continue to drill both proven and non-proven downspaced Wattenberg Field locations in 2014, our PUD conversion rate is expected to be approximately 7.4%. The balance of the locations are scheduled to be drilled over the remaining four years with total PUD conversion rates of 22% in 2015, 27% in 2016, 24% in 2017 and 19% in 2018. This level of capital spending is consistent with the most recent years and our guidance for future activity.

2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 59 MMBoe. The revision was primarily due to a decrease of approximately 40 MMBoe due to lower gas pricing, mostly related to the Piceance Basin, approximately 1 MMBoe due to increased operating costs, approximately 8 MMBoe due to adjustments for geological reasons and approximately 13 MMBoe 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 0.5 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. Discoveries and extensions of approximately 68 MMBoe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 10 MMBoe were added in the Marcellus Shale and approximately 59 MMBoe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 33 MMBoe of proved reserves due to an acquisition in the Wattenberg Field. We divested a total of 11 MMBoe 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.

2011 Activity. In 2011, we recorded a downward revision of our previous estimate of proved reserves of approximately 26 MMBoe. The revision was primarily due to a decrease of approximately 0.7 MMBoe due to lower gas pricing and approximately 29 MMBoe 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 1 MMBoe due to increased efficiencies in operating costs, approximately 0.8 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe 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 21 MMBoe. 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 52 MMboe in 2012 are due to the drilling of 195 gross wells and the addition of new proved undeveloped reserves. Approximately 9 MMBoe were added in the Marcellus Shale, approximately 24 MMBoe in the Wattenberg Field, 13 MMBoe in the Piceance Basin and 7 MMBoe in the Permian Basin. We acquired approximately 8 MMboe of proved reserves, approximately 1 MMBoe through acquisitions in the Marcellus Shale, approximately 5 MMBoe in the Wattenberg Field and 2 MMBoe 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 0.8 MMBoe in 2012. This included the sale of 100% of our North Dakota assets, or 0.3 MMBoe, to an unrelated third-party and our non-core Permian Basin assets, or 0.5 MMBoe, to unrelated third parties.

Results of Operations for Crude Oil and Natural Gas Producing Activities

The results of operations for crude oil and natural gas 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,
	2013			2012			2011
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	379,796		$	274,783		$	304,157
Commodity price risk management gain, net	(23,905		)	32,339			46,090
	355,891			307,122			350,247
Expenses:
Production costs	81,365			77,537			75,717
Exploration expense	7,071			22,605			6,289
Impairment of proved crude oil and natural gas properties	53,438			162,287			25,159
Depreciation, depletion, and amortization	124,202			146,879			128,458
Accretion of asset retirement obligations	4,747			4,060			1,897
(Gain) loss on sale of properties and equipment	3,722			(24,273		)	(4,050		)
	274,545			389,095			233,470
Results of operations for crude oil and natural gas producing activities before provision for income taxes	81,346			(81,973		)	116,777

Provision for income taxes	(29,400		)	31,163			(36,785		)

Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	51,946		$	(50,810	)	$	79,992

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 Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities

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



	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Acquisition of properties: (1)
Proved properties	$	28,698	$	105,303	$	79,554
Unproved properties	3,390		276,225		95,081
Development costs (2)	332,250		233,144		301,008
Exploration costs: (3)
Exploratory drilling	58,988		18,803		3,626
Geological and geophysical	752		1,925		1,846
Total costs incurred	$	424,078	$	635,400	$	481,115

__________


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

(2)

Development costs represent 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 crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2013, 2012 and 2011, $40.1 million, $62.0 million and $80.6 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 crude oil, natural gas and NGLs.

Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities

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



	As of December 31,
	2013			2012
	(in thousands)

Proved crude oil and natural gas properties	$	1,781,681		$	2,075,924
Unproved crude oil and natural gas properties	307,203			319,327
Uncompleted wells, equipment and facilities	51,773			62,392
Capitalized costs	2,140,657			2,457,643
Less accumulated DD&A	(529,607		)	(905,458		)
Capitalized costs, net	$	1,611,050		$	1,552,185

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 crude oil, natural gas and NGLs, 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,
	2013			2012			2011
	(in thousands)

Future estimated cash flows	$	11,550,917		$	7,529,292		$	6,415,255
Future estimated production costs	(2,329,836		)	(1,690,453		)	(1,704,645		)
Future estimated development costs	(2,778,148		)	(1,852,177		)	(1,474,137		)
Future estimated income tax expense	(2,119,615		)	(1,230,294		)	(946,849		)
Future net cash flows	4,323,318			2,756,368			2,289,624
10% annual discount for estimated timing of cash flows	(2,541,155		)	(1,587,871		)	(1,348,415		)
Standardized measure of discounted future estimated net cash flows	$	1,782,163		$	1,168,497		$	941,209

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



	Year Ended December 31,
	2013			2012			2011
	(in thousands)

Sales of crude oil, natural gas and NGLs production, net of production costs	$	(286,021	)	$	(194,346	)	$	(226,227	)
Net changes in prices and production costs (1)	89,527			95,501			383,293
Extensions, discoveries, and improved recovery, less related costs (2)	1,529,006			632,781			467,347
Sales of reserves (3)	(142,724		)	(86,902		)	(4,224		)
Purchases of reserves (4)	10,610			296,208			64,761
Development costs incurred during the period	46,366			69,198			94,941
Revisions of previous quantity estimates (5)	(397,738		)	(452,775		)	(112,468		)
Changes in estimated income taxes (6)	(381,369		)	(131,256		)	(204,377		)
Net changes in future development costs	(40,707		)	(3,979		)	(29,827		)
Accretion of discount	142,040			124,105			65,284
Timing and other	44,676			(121,247		)	(45,712		)
Total	$	613,666		$	227,288		$	452,791

__________

(1)

Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $24.24 as compared to $20.70 in our 2012 reserve report. This is due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which further increased our liquids as a percentage of proved reserves. Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Boe, in our 2012 reserve report increased to $20.70 from $19.14 resulting from our increase in liquids as a percentage of total proved reserves.

(2)

The 142% increase in 2013 as compared to 2012 is primarily due to the additions of PUDs in the Utica Shale and our continued focus on our Wattenberg drilling program. Our increased PUD count in Wattenberg is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 68 MMBoe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program.


(3)	The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. 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 decrease in purchases of reserves in 2013 as compared to 2012 was due to no material acquisitions having occurred in 2013. The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field.

(5)

The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. The change 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.

(6)

The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.0%, 38.2% and 38.1% for the years ended December 31, 2013, 2012 and 2011, 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.

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 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.