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Oil and Gas Reserves (Unaudited):
12 Months Ended
Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Reserves (Unaudited)
OIL AND GAS RESERVES (Unaudited)

BHEP has operating and non-operating interests in 1,006 gross developed oil and gas wells in 10 states and holds leases on approximately 236,545 net acres.

Costs Incurred

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
 
2015
2014
2013
Acquisition of properties:
 
 
 
Proved
$
1,407

$
4,881

$
234

Unproved
669

5,056

6,022

Exploration costs
35,434

54,355

12,817

Development costs
128,998

52,262

48,641

Asset retirement obligations incurred
566

68

143

Total costs incurred
$
167,074

$
116,622

$
67,857



Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2015, 2014 and 2013 and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
 
2015
 
2014
 
2013
 
Oil
Gas
NGL
 
Oil
Gas
NGL
 
Oil
Gas
 
(in Mbbls of oil and NGL, and MMcf of gas)
Proved developed and undeveloped reserves:
 
 
 
 
 
 
 
 
 
 
Balance at beginning of year
4,276

65,440

1,720

 
3,921

63,190


 
4,116

55,985

Production (a)
(371
)
(10,058
)
(102
)
 
(337
)
(7,156
)
(135
)
 
(336
)
(6,984
)
Additions - acquisitions (sales)
(11
)
(828
)

 
(40
)
(61
)

 
(30
)
(46
)
Additions - extensions and discoveries
199

24,462

232

 
733

11,003

182

 
379

10,456

Revisions to previous estimates
(643
)
(5,604
)
(98
)
 
(1
)
(1,536
)
1,673

 
(208
)
3,779

Balance at end of year
3,450

73,412

1,752

 
4,276

65,440

1,720

 
3,921

63,190

 
 
 
 
 
 
 
 
 
 
 
Proved developed reserves at end of year included above
3,436

73,390

1,752

 
3,780

57,427

1,530

 
3,689

60,224

 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves at the end of year included in above
14

22


 
496

8,013

191

 
232

2,966

 
 
 
 
 
 
 
 
 
 
 
NYMEX prices
$
50.28

$
2.59

$

(b) 
$
94.99

$
4.35

$

(b) 
$
96.94

$
3.67

 
 
 
 
 
 
 
 
 
 
 
Well-head reserve prices
$
44.72

$
1.27

$
18.96

 
$
85.80

$
3.33

$
34.81

 
$
89.79

$
3.45

________________________
(a)
Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.
(b)
A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production.

Reserve additions for 2015 totaled 27.0 Bcfe, replacing 209% of annual production. Reserve additions resulted from drilling in the Piceance and Powder River Basins. Drilling in the Piceance for Mancos Shale accounted for 25.9 Bcfe and Powder River Basin drilling accounted for 1.2 Bcfe. Capital spending in 2015 was primarily for drilling and completion activities in the Piceance Basin. Future capital spending rates will be dependent on product prices, processing availability and support of our Cost of Service Gas program.

In 2015, we had negative revisions of (10.1 Bcfe) to previous reserve estimates. Most of the negative revision was the result of lower equivalent prices of oil, liquids and gas received at the wellhead of (20.1 Bcfe), partially offset by improved wellhead performance of 3.6 Bcfe and non-consent interests we assumed related to new wells drilled in the southern Piceance Basin of 6.9 Bcfe. We changed our process for reporting natural gas in 2014 to separate NGL from wet gas steam. This change was from increased NGL recovery from the Powder River Finn Field and the Piceance wells. 2013 NGL was reported wet. The industry standard multiplication of liquid production by 6 to arrive at the equivalent gas volume results in higher overall equivalent volumes. This is offset by negative revisions of dry natural gas resulting from higher shrink factors during processing of the wet gas to dry gas and NGLs. We will continue to report oil, natural gas and NGL volumes in the future.

SEC regulations require that proved undeveloped (PUD) locations meet the test of being developed within five years of being categorized as proved. In 2015, we had no PUD locations that were required to be dropped because of the five year rule.

Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year and investment and progress made in converting the PUD locations to proved developed during the year.

The decrease in 2015 of 28 PUD locations is driven by low commodity prices and economics. The remaining six PUD locations are in the Williston Basin and require approximately $0.4 million of future investment.

Due to economic conditions in 2015, no new gross PUD locations were added for future drilling in the Williston Bakken, Piceance Mancos or Powder River Basin.

The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2015 were:
 
Proved Reserves (in Bcfe)
Gross PUD Locations
Future Development Costs (in millions)
 
 
 
 
Existing 2014:
 
 
 
Williston
1.1

30

$
5.4

Piceance
9.0

3

$
23.5

Powder River
2.0

1

$
13.0

Year End Total 2014
12.1

34

$
41.9

 
 
 
 
Dropped 2015:
 
 
 
Williston
(1.0
)
(21
)
$
(4.6
)
Piceance
(4.4
)
(1
)
$
(11.5
)
 
(5.4
)
(22
)
$
(16.1
)
 
 
 
 
Drilled in 2015:
 
 
 
Williston

(3
)
$
(0.3
)
Piceance
(4.6
)
(2
)
$
(12.0
)
Powder River
(2.0
)
(1
)
$
(13.0
)
 
(6.6
)
(6
)
$
(25.3
)
Revisions:
 
 
 
Piceance


$
(0.1
)
 
 
 
 
Added in 2015:
 
 
 
Williston


$

Piceance


$

Powder River


$

 


$

 
 
 
 
Total Proved Undeveloped
0.1

6

$
0.4



None of our PUD locations have been reflected in our reserves for five or more years. Consistent with SEC guidance, these PUD locations will be monitored and reported each year until either drilled or revised.

Capitalized Costs

Following is information concerning capitalized costs for the years ended December 31 (in thousands):
 
2015
2014
2013
Unproved oil and gas properties
$
47,254

$
75,329

$
62,553

Proved oil and gas properties
1,008,466

807,518

725,345

Gross capitalized costs
1,055,720

882,847

787,898

 
 
 
 
Accumulated depreciation, depletion and amortization and valuation allowances
(888,775
)
(612,012
)
(592,505
)
Net capitalized costs
$
166,945

$
270,835

$
195,393



Results of Operations

Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
 
2015
2014
2013
Revenue
$
43,283

$
55,114

$
54,884

 
 
 
 
Production costs
19,762

22,155

20,140

Depreciation, depletion and amortization and valuation provisions
28,062

23,288

16,717

Impairment of long-lived assets
249,608



Total costs
297,432

45,443

36,857

Results of operations from producing activities before tax
(254,149
)
9,671

18,027

 
 
 
 
Income tax benefit (expense)
93,743

(3,415
)
(6,308
)
Results of operations from producing activities (excluding general and administrative costs and interest costs)
$
(160,406
)
$
6,256

$
11,719



Unproved Properties

Unproved properties not subject to amortization at December 31, 2015, relate primarily to the four wells drilled in the Mancos formation of the Piceance Basin, for which completions were deferred. Unproved properties not subject to amortization at December 31, 2014 and 2013 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $1.0 million, $1.0 million and $1.1 million of interest during 2015, 2014 and 2013, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.
The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2015 and notes the year in which the associated costs were incurred (in thousands):

 
2015
2014
2013
Prior
Total
Leasehold acquisition cost
$
4,256

$
4,475

$
9,006

$
1,433

$
19,170

Exploration cost
37,770

8,159



45,929

Capitalized interest
940

351

736

981

3,008

Total
$
42,966

$
12,985

$
9,742

$
2,414

$
68,107



Standardized Measure of Discounted Future Net Cash Flows

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):
 
2015
2014
2013
Future cash inflows
$
295,173

$
675,973

$
602,501

Future production costs
(146,552
)
(245,180
)
(213,578
)
Future development costs, including plugging and abandonment
(24,833
)
(45,123
)
(40,557
)
Future income tax expense

(29,523
)
(81,566
)
Future net cash flows
123,788

356,147

266,800

10% annual discount for estimated timing of cash flows
(44,760
)
(173,125
)
(107,375
)
Standardized measure of discounted future net cash flows
$
79,028

$
183,022

$
159,425



The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):
 
2015
2014
2013
Standardized measure - beginning of year
$
183,022

$
159,425

$
136,103

Sales and transfers of oil and gas produced, net of production costs
(29,948
)
(32,139
)
(35,932
)
Net changes in prices and production costs
(127,199
)
(28,544
)
15,126

Extensions, discoveries and improved recovery, less related costs
15,718

17,582

29,574

Changes in future development costs
(7,387
)
3,195

(12,216
)
Development costs incurred during the period
27,211

2,079

3,554

Revisions of previous quantity estimates
(6,941
)
23,722

12,851

Accretion of discount
18,870

18,437

15,126

Net change in income taxes
5,682

19,265

(3,892
)
Purchases of reserves



Sales of reserves


(869
)
Standardized measure - end of year
$
79,028

$
183,022

$
159,425



Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting and service availability.