XML 45 R22.htm IDEA: XBRL DOCUMENT v3.8.0.1
Supplemental Oil and Natural Gas Disclosure (Unaudited)
 12 Months Ended
Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Oil and Natural Gas Disclosure - Unaudited
Geographic Area of Operation 
All of the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Kentucky, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. However, the Partnership also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the U.S. Therefore, the following disclosures about the Partnership’s costs incurred and proved reserves are presented on a consolidated basis.
Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities
Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(in thousands)
Acquisition Costs of Properties:1
 
 
 
 
 
 
Proved
 
$
96,596

 
$
40,242

 
$
2,302

Unproved
 
383,535

 
100,888

 
60,994

Exploration Costs
 
618

 
645

 
2,592

Development Costs
 
81,056

 
73,316

 
60,056

Total
 
$
561,805

 
$
215,091

 
$
125,944

 
1. 
See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment.
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below:
 
 
As of December 31,
 
 
2017
 
2016
 
 
(in thousands)
Proved properties
 
$
2,258,893

 
$
2,091,337

Unproved properties
 
988,720

 
605,736

Total
 
3,247,613

 
2,697,073

Accumulated depreciation, depletion, amortization, and impairment
 
(1,766,842
)
 
(1,652,930
)
Oil and natural gas properties, net
 
$
1,480,771

 
$
1,044,143

Oil and Natural Gas Reserve Information
The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB.
 
 
Crude Oil (MBbl)
 
Natural Gas (MMcf)
 
Total (MBoe)
Net proved reserves at December 31, 2014
 
17,067

 
204,256

 
51,109

Revisions of previous estimates1
 
(197
)
 
(17,043
)
 
(3,037
)
Purchases of minerals in place2
 
8

 
367

 
69

Extensions, discoveries and other additions3
 
2,529

 
57,484

 
12,110

Production
 
(3,565
)
 
(41,389
)
 
(10,463
)
Net proved reserves at December 31, 2015
 
15,842

 
203,675

 
49,788

Revisions of previous estimates1
 
3,007

 
29,024

 
7,844

Purchases of minerals in place4
 
1,322

 
5,683

 
2,269

Extensions, discoveries and other additions5
 
1,877

 
79,455

 
15,120

Production
 
(3,680
)
 
(47,498
)
 
(11,596
)
Net proved reserves at December 31, 2016
 
18,368

 
270,339

 
63,425

Revisions of previous estimates1
 
(1,234
)
 
21,067

 
2,277

Purchases of minerals in place6
 
2,267

 
30,250

 
7,309

Extensions, discoveries and other additions7
 
2,050

 
38,397

 
8,449

Production
 
(3,552
)
 
(59,779
)
 
(13,515
)
Net proved reserves at December 31, 2017
 
17,899

 
300,274

 
67,945

Net Proved Developed Reserves8
 
 

 
 

 
 

December 31, 2015
 
15,497

 
174,555

 
44,590

December 31, 2016
 
18,150

 
223,057

 
55,327

December 31, 2017
 
17,891

 
233,017

 
56,727

Net Proved Undeveloped Reserves9
 
 

 
 

 
 

December 31, 2015
 
345

 
29,120

 
5,198

December 31, 2016
 
218

 
47,282

 
8,098

December 31, 2017
 
8

 
67,257

 
11,218

1  
Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells.
2  
Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.
3  
Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays.
4  
Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.
5
Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayetteville plays.
6  
Includes the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins.
7  
Includes extensions and additions related to drilling activities within multiple basins.
8
Proved developed reserves of 61 MBoe, 74 MBoe, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.
9
As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests.
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion.
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(in thousands)
Future cash inflows
 
$
1,643,582

 
$
1,267,179

 
$
1,211,290

Future production costs
 
(211,064
)
 
(193,749
)
 
(205,861
)
Future development costs
 
(70,111
)
 
(36,509
)
 
(84,746
)
Future income tax expense
 
(2,655
)
 
(3,516
)
 
—

Future net cash flows (undiscounted)
 
1,359,752

 
1,033,405

 
920,683

Annual discount 10% for estimated timing
 
(497,103
)
 
(430,390
)
 
(365,711
)
Total1
 
$
862,649

 
$
603,015

 
$
554,972

 
1  
Includes standardized measure of discounted future net cash flows of approximately $0.5 million, $0.6 million, and $0.7 million for December 31, 2017, 2016, and 2015, attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
 
(in thousands)
Standardized measure, beginning of year
 
$
603,015

 
$
554,972

 
$
1,143,094

Sales, net of production costs
 
(295,941
)
 
(210,354
)
 
(222,206
)
Net changes in prices and production costs related to future production
 
169,608

 
(81,456
)
 
(621,065
)
Extensions, discoveries and improved recovery, net of future production and development costs
 
113,199

 
86,606

 
165,020

Previously estimated development costs incurred during the period
 
11,118

 
28,909

 
7,084

Revisions of estimated future development costs
 
2,653

 
—

 
669

Revisions of previous quantity estimates, net of related costs
 
86,228

 
147,507

 
(67,911
)
Accretion of discount
 
60,512

 
55,662

 
114,309

Purchases of reserves in place, less related costs
 
107,891

 
34,751

 
584

Other
 
4,366

 
(13,582
)
 
35,394

Net increase (decrease) in standardized measures
 
259,634

 
48,043

 
(588,122
)
Standardized measure, end of year
 
$
862,649

 
$
603,015

 
$
554,972


 
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimates and assumptions. 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 historical prices and 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.