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, and NGL reserves. As of December 31, 2016, 2015, and 2014, all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and beginning in 2016, NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date.

The indicated index prices for our reserves, by commodity, are presented below.



	Average Benchmark Prices
As of December 31,	Crude Oil (per Bbl)		Natural Gas (per Mcf)		NGLs (per Bbl)

2016	$	42.75	$	2.48	$	42.75
2015	50.28		2.59		50.28
2014	94.99		4.35		94.99

The netted back 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)

2016	$	38.67	$	1.85	$	11.97
2015	42.10		2.05		12.23
2014	84.65		3.92		32.27

___________


*	These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity.

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, 2014 (1)	93,830		739,640		48,671		265,774
Revisions of previous estimates	(29,777	)	(149,064	)	(10,204	)	(64,825	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	40,792		202,957		23,411		98,029
Acquisition of reserves	5		43		5		17
Dispositions	(13	)	(237,306	)	(8	)	(39,572	)
Production	(4,322	)	(19,298	)	(1,756	)	(9,294	)
Proved reserves, December 31, 2014	100,515		536,972		60,119		250,129
Revisions of previous estimates	(43,268	)	(154,775	)	(24,407	)	(93,471	)
Extensions, discoveries and other additions, including infill reserves in an existing proved field	48,707		311,709		30,835		131,494
Acquisition of reserves	17		215		23		76
Dispositions	(12	)	(82	)	(8	)	(34	)
Production	(6,984	)	(33,302	)	(2,835	)	(15,369	)
Proved reserves, December 31, 2015	98,975		660,737		63,727		272,825
Revisions of previous estimates	(22,097	)	(80,426	)	(7,130	)	(42,631	)
Extensions, discoveries and other additions	494		4,094		355		1,531
Acquisition of reserves	50,126		305,224		32,586		133,583
Dispositions	(601	)	(4,202	)	(424	)	(1,725	)
Production	(8,728	)	(51,730	)	(4,826	)	(22,176	)
Proved reserves, December 31, 2016	118,169		833,697		84,288		341,407



Proved Developed Reserves, as of:
December 31, 2014	26,798	186,633	17,002	74,905
December 31, 2015	26,257	175,367	15,011	70,496
December 31, 2016	30,013	264,452	24,196	98,284
Proved Undeveloped Reserves, as of:
December 31, 2014	73,717	350,339	43,117	175,224
December 31, 2015	72,718	485,370	48,716	202,329
December 31, 2016	88,156	569,245	60,092	243,122

2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin.

Extensions, discoveries and other additions for 2016 of 1.5 MMBoe includes the addition of five wells in the Utica Shale.

Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and proved undeveloped (“PUD”) locations acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction. Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of anticipated development in the field. This resulted in a downward revision to our proved reserves. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0 MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg Field were reported in extensions, discoveries and other additions, including infill reserves in an existing proved field. Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of previous estimates includes performance revisions and other items.

We had minimal dispositions of 1.7 MMBoe related to acreage traded in the acreage exchange.

At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent, resulting in 32.2 MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December 31, 2016.

Based on economic conditions on December 31, 2016, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2016, our 2017 PUD reserve conversion rate is expected to be approximately 26 percent. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 million MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16 percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015.

Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects are largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We have 791 gross PUD horizontal drilling locations at December 31, 2015, which is an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of prior year-end.

We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also, contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments.

Based on the economic conditions on December 31, 2015, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. The continued success of our increased well density tests in the Wattenberg Field in 2015 allowed for the additional increased well density of PUD locations as of December 31, 2015. Because we expect to continue to drill primarily proved Wattenberg Field locations in 2016 and as a result of additional newly-booked downspaced PUDs at December 31, 2015, our 2016 PUD conversion rate is expected to be approximately 19 percent. The balance of the locations are scheduled to be drilled over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2014 Activity. Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe. At December 31, 2013, we projected a PUD conversion rate of seven percent for 2014. Our actual conversion rate was seven percent, resulting in 13 MMBoe of reserves booked as PUDs at December 31, 2013 being converted to proved developed reserves during 2014. As shown, we acquired minimal proved reserves in 2014. We divested a total of 40 MMBoe in 2014, primarily from the sale of our Marcellus Shale assets.

Extensions, discoveries and other additions, including infill reserves, resulted in an increase of approximately 98 MMBoe in 2014, substantially all of which was added in the Wattenberg Field and primarily related to Niobrara and Codell projects. These reserve increases are primarily due to adding 78 MMBoe from new proved undeveloped reserves as a result of adjustments in well spacing, which extended the field by enabling us to book more reserves per section in the Niobrara and Codell formations. In addition, approximately 16 MMBoe of previously unbooked locations were developed in the current year and 2 MMBoe due to various other factors. Approximately 2 MMBoe was added in the Utica Shale.

We recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field to focus on a more balanced commodity production mix and increased well density which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. In addition, 8 MMBoe of Utica Shale PUDs are no longer in our drilling plans as we directed more capital to higher-return projects in the Wattenberg Field and 2 MMBoe that were due to various other factors.

Based on the economic conditions on December 31, 2014, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field.

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 gas marketing and other income.



	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	497,353		$	378,713		$	495,562
Commodity price risk management gain (loss), net	(125,681		)	203,183			309,219
	371,672			581,896			804,781
Expenses:
Lease operating expenses	59,950			56,992			43,682
Production taxes	31,410			18,443			27,194
Transportation, gathering and processing expenses	18,415			10,151			8,128
Exploration expense	4,669			1,102			948
Impairment of properties and equipment	9,973			161,620			167,280
Depreciation, depletion, and amortization	413,105			298,760			201,656
Accretion of asset retirement obligations	7,080			6,293			3,455
Loss on sale of properties and equipment	(43		)	(385		)	(75,972		)
	544,559			552,976			376,371
Results of operations for crude oil and natural gas producing activities before provision for income taxes	(172,887		)	28,920			428,410

Provision for income taxes	64,733			(10,394		)	(166,930		)

Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	(108,154	)	$	18,526		$	261,480

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,
	2016		2015		2014
	(in thousands)
Acquisition of properties: (1)
Proved properties (2)	$	268,567	$	3,561	$	11,973
Unproved properties	1,843,985		15		45,999
Development costs (3)	383,336		552,104		608,176
Exploration costs: (4)
Exploratory drilling	—		—		—
Geological and geophysical	4,669		—		1
Total costs incurred	$	2,500,557	$	555,680	$	666,149

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


(2)	Includes approximately $40.9 million of infrastructure and pipeline costs in 2016.

(3)

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, 2016, 2015, and 2014, $204.6 million, $207.8 million, and $125.2 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end.


(4)	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,
	2016			2015
	(in thousands)

Proved crude oil and natural gas properties	$	3,499,718		$	2,881,189
Unproved crude oil and natural gas properties	1,874,671			60,498
Uncompleted wells, equipment and facilities	150,424			109,385
Capitalized costs	5,524,813			3,051,072
Less accumulated DD&A	(1,534,678		)	(1,131,705		)
Capitalized costs, net	$	3,990,135		$	1,919,367

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 obligations. 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,
	2016			2015			2014
	(in thousands)

Future estimated cash flows	$	7,122,525		$	6,297,298		$	12,550,515
Future estimated production costs*	(1,624,167		)	(1,493,040		)	(2,746,811		)
Future estimated development costs	(2,219,914		)	(2,036,685		)	(2,528,755		)
Future estimated income tax expense	(597,476		)	(508,332		)	(2,336,510		)
Future net cash flows	2,680,968			2,259,241			4,938,439
10% annual discount for estimated timing of cash flows	(1,260,339		)	(1,162,377		)	(2,631,974		)
Standardized measure of discounted future estimated net cash flows	$	1,420,629		$	1,096,864		$	2,306,465

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*	Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses.

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



	Year Ended December 31,
	2016			2015			2014
	(in thousands)

Beginning of period	$	1,096,864		$	2,306,465		$	1,782,163
Sales of crude oil, natural gas and NGLs production, net of production costs	(387,576		)	(293,127		)	(387,789		)
Net changes in prices and production costs (1)	(205,760		)	(1,752,921		)	129,213
Extensions, discoveries, and improved recovery, less related costs	15,128			489,178			1,444,581
Sales of reserves	(3,745		)	(463		)	(402,595		)
Purchases of reserves	487,636			374			238
Development costs incurred during the period	268,672			368,840			161,404
Revisions of previous quantity estimates	(320,286		)	(1,286,462		)	(654,318		)
Changes in estimated income taxes	(13,630		)	902,994			(221,874		)
Net changes in future development costs	391,145			112,958			46,499
Accretion of discount	133,747			345,007			270,389
Timing and other	(41,566		)	(95,979		)	138,554
End of period	$	1,420,629		$	1,096,864		$	2,306,465

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(1)	Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to $15.73 as compared to $17.30 for 2015 and $37.78 for 2014.

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.