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DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
 12 Months Ended
Dec. 31, 2016
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]  
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
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