DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The proved reserve estimates at December 31, 2016, 2015 and 2014 are internally generated with an audit performed by NSAI, our third party independent reserve engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

All of BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 are as follows:



			Natural		Natural
	Oil		Gas		Gas Liquids
	(MBbl)⁽¹⁾		(MMcf)		(MBbl)⁽¹⁾
Balance-December 31, 2013	46.482		139.614		—
Extensions and discoveries⁽²⁾	13.222		41.963		—
Production	(6.018	)	(14.114	)	—
Sales of minerals in place	(0.043	)	(0.073	)	—
Purchases of minerals in place	0.709		1.214		—
Revisions to previous estimates⁽³⁾	3.76		19.947		—
Balance-December 31, 2014	58.112		188.551		—
Three stream conversion adjustment	(3.352	)	—		3.352
Extensions and discoveries⁽²⁾	6.936		15.849		2.43
Production	(6.072	)	(14.11	)	(1.676	)
Purchases of minerals in place	0.719		3.521		0.234
Revisions to previous estimates⁽³⁾	1.05		(49.584	)	15.578
Balance-December 31, 2015	57.393		144.227		19.918
Extensions, discoveries and infills⁽²⁾	6.133		15.128		2.142
Production	(4.31	)	(11.907	)	(1.491	)
Sales of minerals in place	(0.1	)	(0.343	)	(0.035	)
Revisions to previous estimates⁽³⁾	(9.02	)	(9.06	)	(2.987	)
Balance-December 31, 2016	50.096		138.045		17.547
Proved developed reserves:
December 31, 2014	30.542		94.494		—
December 31, 2015	28.892		77.48		10.359
December 31, 2016	26.313		85.972		9.951
Proved undeveloped reserves:
December 31, 2014	27.57		94.057		—
December 31, 2015	28.501		66.747		9.559
December 31, 2016	23.783		52.073		7.596

________________________

(1)

Natural gas liquid reserves were classified with oil reserves through December 31, 2014. Natural gas liquids are separately accounted for effective as of January 1, 2015, resulting in three-stream presentation. Effective January 1, 2015 the Company revised the agreements with its natural gas processors in the Rocky Mountain region to sell and report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in the Company's reporting of estimated reserve volumes. Prior period estimated reserve volumes have not been reclassified to conform to the current presentation given the prospective nature of the agreements.


(2)	At December 31, 2016, horizontal development in the Wattenberg Field resulted in additions of 1,632 MBoe and infill down-spacing within the Wattenberg Field resulted in 9,164 MBoe to the additions, extensions and infills category.

At December 31, 2015, horizontal development in the Wattenberg Field resulted in additions in extensions and discoveries of 11,708 MBoe, which is 97% of our total additions of 12,008 MBoe. The remainder of the additions were the result of vertical drilling during the year in the Dorcheat Macedonia Field, Mid-Continent region.

At December 31, 2014, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 18,980 MBoe, which is 94% of our total additions of 20,216 MBoe. The remainder of the additions came from our Dorcheat Madedonia Field, Mid-Continent region.

(3)

As of December 31, 2016, the Company revised its proved reserves downward by 13,517 MBoe. The commodity prices at December 31, 2016 decreased to $42.75 per Bbl WTI and $2.48 per MMBtu HH from $50.28 per Bbl WTI and $2.59 per MMBtu HH at December 31, 2015. The negative effects of commodity price reductions on reserves were offset by lower cost estimates to drill and complete future development locations in the Wattenberg Field along with lower operating cost estimates across the Company's operations to reflect a positive reserves adjustment (net of price reductions) of 4,652 MBoe. Also, all future proved undeveloped locations in the Mid-Continent region were demoted to non-proved reserves resulting in a negative revision of 7,761 MBoe. In the Wattenberg Field, certain proved undeveloped locations totaling 8,611 MBoe were demoted due to them not being centric to current infrastructure. The Company also had negative other engineering revisions of 1,797 MBoe in 2016.

As of December 31, 2015, the Company revised its proved reserves upward by 8,364 Mboe. The Company was successful in offsetting the negative pricing revision of 28,810 Mboe that resulted from a decrease in commodity price from $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014 to $50.28 per Bbl WTI and $2.59 per MMBtu HH for the year ended December 31, 2015, by reducing the costs to drill and complete wells in both the Rocky Mountain and Mid-Continent regions and improving reserves by increasing productivity of proved developed producing wells in the Wattenberg Field horizontal program. Total positive engineering revisions as of December 31, 2015, were 37,174 MBoe, of which 30,086 MBoe (81%) related to reserve changes in the Wattenberg Field. In the Wattenberg Field, the majority of the positive revisions resulted from a combination of decreased drilling and completion costs of 29% ($3.0 million per standard reach lateral well as of December 31, 2015 compared to $4.2 million as of December 31, 2014) and an increase in productivity from horizontal proved developed producing wells which increased the offsetting proved undeveloped reserves. The increase in proved developed producing reserves is primarily attributed to the installation of infrastructure in the east side of the Wattenberg Field. Another significant contribution to the positive reserve revision in the Wattenberg Field is a contract change as of January 1, 2015 which gives the Company ownership of the natural gas liquids from the Company's gas production. This conversion from two stream (wet gas and oil) to three stream (dry gas, natural gas liquids and oil) added 8,560 MBoe to the Company's proved reserves as of December 31, 2015.

As of December 31, 2014, we revised our proved reserves upward by 7,333 Mboe, excluding pricing revisions, due primarily to the addition of 49 new proved undeveloped locations on 80-acre spacing, directly offsetting economic proved producing wells drilled prior to 2014, 21 diagonal offsets to economic proved producing wells and 12 proved undeveloped locations greater than one offset to economic proved producing wells but within developed areas and surrounded by proved producing wells. As of December 31, 2014, approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara B formation. A total of 119 horizontal proved undeveloped locations were added to the proved reserves at December 31, 2014 to either extensions and discoveries or revisions to previous estimates. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A small negative pricing revision of 248 MBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with accounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company's oil and natural gas properties.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:



	For the Years Ended December 31,
	2016			2015			2014
	(in thousands)
Future cash flows	$	2,424,415		$	3,122,574		$	5,780,745
Future production costs		(1,365,765	)		(1,706,607	)		(2,257,572	)
Future development costs		(468,804	)		(697,045	)		(952,041	)
Future income tax expense		—			—			(457,625	)
Future net cash flows		589,846			718,922			2,113,507
10% annual discount for estimated timing of cash flows		(312,891	)		(391,106	)		(1,006,131	)
Standardized measure of discounted future net cash flows	$	276,955		$	327,816		$	1,107,376

Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end.

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:



	For the Years Ended December 31,
	2016			2015			2014
	(in thousands)
Beginning of period	$	327,816		$	1,107,376		$	925,283
Sale of oil and gas produced, net of production costs		(123,494	)		(197,643	)		(435,792	)
Net changes in prices and production costs		(126,536	)		(1,117,624	)		(331,930	)
Extensions, discoveries and improved recoveries		22,800			76,429			492,144
Development costs incurred		19,701			84,180			116,958
Changes in estimated development cost		281,062			178,003			(15,131	)
Purchases of minerals in place		—			(971	)		30,919
Sales of minerals in place		16			—			(1,173	)
Revisions of previous quantity estimates		(182,938	)		(170,277	)		122,169
Net change in income taxes		—			233,086			68,856
Accretion of discount		32,782			134,046			122,722
Changes in production rates and other		25,746			1,211			12,351
End of period	$	276,955		$	327,816		$	1,107,376

The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2016, 2015 and 2014 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location.



	For the Years Ended December 31,
	2016		2015		2014
Oil (per Bbl)	$	38.42	$	44.00	$	84.28
Gas (per Mcf)	$	2.07	$	2.33	$	5.24
Natural gas liquids (per Bbl)	$	12.12		12.90		N/A