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Oil and Gas Exploration and Production Industries Disclosure (Tables)
12 Months Ended
Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure
Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
 
2016
Acquisition of properties:
 
Proved
$

Unproved
910

Exploration costs
1,102

Development costs
4,657

Asset retirement obligations incurred

Total costs incurred
$
6,669

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities
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, 2016 and a reconciliation of the changes. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 31 years of practical experience in petroleum engineering and over 29 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were 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.
 
2016
 
Oil
Gas
NGL
 
(in Mbbls of oil and NGL, and MMcf of gas)
Proved developed and undeveloped reserves:
 
 
 
Balance at beginning of year
3,450

73,412

1,752

Production (a)
(319
)
(9,430
)
(133
)
Sales
(570
)
(1,291
)
(17
)
Additions - extensions and discoveries
3

52


Revisions to previous estimates
(322
)
(8,173
)
110

Balance at end of year
2,242

54,570

1,712

 
 
 
 
Proved developed reserves at end of year included above
2,242

54,570

1,712

 
 
 
 
Proved undeveloped reserves at the end of year included in above



 
 
 
 
NYMEX prices
$
42.75

$
2.48

$

 
 
 
 
Well-head reserve prices(c)
$
37.35

$
2.25

$
11.92

________________________
(a)
Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods.
(b)
A specific NYMEX price for NGL was 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. Ethane was not being recovered at any of the facilities that process our natural gas production.
(c)
For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure
Following is information concerning capitalized costs for the years ended December 31 (in thousands):
 
2016
Unproved oil and gas properties
$
18,547

Proved oil and gas properties
1,043,558

Gross capitalized costs
1,062,105

 
 
Accumulated depreciation, depletion and amortization and valuation allowances
(1,000,091
)
Net capitalized costs
$
62,014



Results of Operations for Oil and Gas Producing Activities Disclosure
Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
 
2016
Revenue
$
34,058

 
 
Production costs
17,231

Depreciation, depletion and amortization
12,574

Impairment of long-lived assets
106,957

Total costs
136,762

Results of operations from producing activities before tax
(102,704
)
 
 
Income tax benefit (expense)
37,916

Results of operations from producing activities (excluding general and administrative costs and interest costs)
$
(64,788
)
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization
The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):

 
2016
Leasehold acquisition cost
$
963

Exploration cost
532

Capitalized interest
50

Total
$
1,545

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure
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):
 
2016
Future cash inflows
$
246,221

Future production costs
(166,248
)
Future development costs, including plugging and abandonment
(18,333
)
Future net cash flows
61,640

10% annual discount for estimated timing of cash flows
(26,574
)
Standardized measure of discounted future net cash flows
$
35,066

Changes In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures
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):
 
2016
Standardized measure - beginning of year
$
79,028

Sales and transfers of oil and gas produced, net of production costs
(4,314
)
Net changes in prices and production costs
(32,698
)
Changes in future development costs
1,825

Revisions of previous quantity estimates
(7,477
)
Accretion of discount
7,903

Sales of reserves
(9,201
)
Standardized measure - end of year
$
35,066