XML 40 R20.htm IDEA: XBRL DOCUMENT v3.6.0.2
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited) (Notes)
 12 Months Ended
Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Information About Oil & Natural Gas Producing Activities
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)
Costs Incurred For Oil and Natural Gas Producing Activities
The following table sets forth the capitalized costs incurred in the Company’s oil and gas production, exploration, and development activities:
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
(in thousands)
 
 
 
2015
 
2014
Acquisition costs:
 
 
 
 
 
 
 
 
Proved properties
$
561,251

 
 
$
16,386

 
$
14,268

 
$
5,758

Unproved properties
1,905,660

 
 
39,399

 
28,955

 
16,409

Development costs
44,602

 
 
53,512

 
87,452

 
324,802

Exploration costs
844

 
 
—

 
84

 
—

Total
$
2,512,357

 
 
$
109,297

 
$
130,759

 
$
346,969


Results of Oil and Natural Gas Producing Activities
The results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below:
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
(in thousands)
 
 
 
2015
 
2014
Revenues:
 
 
 
 
 
 
 
 
Oil, natural gas and NGL sales
$
29,717

 
 
$
69,116

 
$
90,460

 
$
131,825

Costs:
 
 
 
 
 
 
 
 
Lease operating expenses
3,541

 
 
11,036

 
21,173

 
17,690

Severance and ad valorem taxes
1,636

 
 
3,696

 
5,021

 
6,875

Transportation, processing, gathering and other operating expenses
2,187

 
 
4,583

 
5,732

 
4,772

Depletion, amortization and accretion of asset retirement obligations
14,486

 
 
62,228

 
89,350

 
68,981

Abandonment expense and impairment of unproved properties
—

 
 
2,545

 
7,619

 
20,025

Exploration
844

 
 
—

 
84

 
—

Contract termination and rig stacking
—

 
 
—

 
2,387

 
—

Income tax expense (benefit)
—

 
 
(406
)
 
(572
)
 
1,524

Results of operations
$
7,023

 
 
$
(14,566
)
 
$
(40,334
)
 
$
11,958


Oil and Gas Reserve Quantities
The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and natural gas producing activities and Securities and Exchange Commission (“SEC”) rules for oil and natural gas reporting reserves estimation and disclosure.
Estimates of the Company’s proved oil and natural gas reserves at December 31, 2016, 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
The following table summarizes the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) and for the years ended December 31, 2015 and 2014. The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows (“standardized measure”):
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
 
 
 
 
2015
 
2014
Oil (per Bbl)
$
38.49

 
 
$
36.98

 
$
41.85

 
$
84.94

Gas (per Mcf)
0.98

 
 
1.24

 
1.71

 
4.70

NGLs (per Bbl)
14.59

 
 
13.28

 
13.94

 
22.70


The table below presents a summary of changes in the Company’s estimated proved reserves:
 
Successor
 
 
Predecessor
 
October 11, 2016, through December 31, 2016
 
 
January 1, 2016, through October 10, 2016
 
Crude Oil (MBbls)
 
Natural Gas
(MMcf)
 
Natural Gas Liquids (MBbls)
 
 
Crude Oil (MBbls)
 
Natural Gas
(MMcf)
 
Natural Gas Liquids (MBbls)
Total proved reserves:
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of period
30,091

 
36,801

 
4,506

 
 
23,199

 
32,442

 
3,851

Extensions and discoveries
7,063

 
12,219

 
1,225

 
 
5,851

 
6,410

 
773

Revisions of previous estimates
184

 
16,445

 
983

 
 
1,025

 
(1,521
)
 
(110
)
Purchases of reserves in place
9,651

 
83,992

 
5,152

 
 
1,600

 
2,130

 
245

Divestitures of reserves in place
—

 
—

 
—

 
 
—

 
—

 
—

Production
(523
)
 
(1,113
)
 
(96
)
 
 
(1,584
)
 
(2,660
)
 
(253
)
End of period
46,466

 
148,344

 
11,770

 
 
30,091

 
36,801

 
4,506

 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of period
11,346

 
14,973

 
1,927

 
 
9,347

 
12,711

 
1,603

End of period
14,551

 
42,190

 
3,618

 
 
11,346

 
14,973

 
1,927

Proved undeveloped reserves:
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of period
18,745

 
21,828

 
2,579

 
 
13,852

 
19,731

 
2,248

End of period
31,914

 
106,154

 
8,152

 
 
18,745

 
21,828

 
2,579

 
Predecessor
 
Year Ended December 31, 2015
 
 
Year Ended December 31, 2014
 
Crude Oil (MBbls)
 
Natural Gas
(MMcf)
 
Natural Gas Liquids (MBbls)
 
 
Crude Oil (MBbls)
 
Natural Gas
(MMcf)
 
Natural Gas Liquids (MBbls)
Total proved reserves:
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of period
19,850

 
27,414

 
1,551

 
 
18,510

 
6,968

 
525

Extensions and discoveries
9,444

 
11,927

 
1,432

 
 
16,122

 
22,575

 
1,127

Revisions of previous estimates
(5,109
)
 
(5,204
)
 
995

 
 
56

 
178

 
180

Purchases of reserves in place
844

 
1,363

 
204

 
 
162

 
192

 
23

Divestitures of reserves in place
—

 
—

 
—

 
 
(13,572
)
 
(387
)
 
(69
)
Production
(1,830
)
 
(3,058
)
 
(331
)
 
 
(1,428
)
 
(2,112
)
 
(235
)
End of period
23,199

 
32,442

 
3,851

 
 
19,850

 
27,414

 
1,551

 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of period
8,026

 
11,959

 
766

 
 
6,021

 
4,837

 
382

End of period
9,347

 
12,711

 
1,603

 
 
8,026

 
11,959

 
766

Proved undeveloped reserves:
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of period
11,823

 
15,455

 
785

 
 
12,489

 
2,131

 
143

End of period
13,852

 
19,731

 
2,248

 
 
11,823

 
15,455

 
785


Proved reserves at December 31, 2016 increased 104% to 82,959 MBoe, compared to 40,730 MBoe at October 10, 2016.
During the period from October 11, 2016, through December 31, 2016 (Successor), the Company acquired 28,801 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions. Additionally, the Company added 10,324 MBoe of proved reserves through extensions, primarily due to its drilling activity, as well as, 3,908 MBoe of revisions due to improved results in completion techniques and adjustments of natural gas and NGL treatment through the gas plants slightly offset by 805 MBoe of production.
Proved reserves at October 10, 2016 increased 25% to 40,730 MBoe, compared to 32,457 MBoe at December 31, 2015.
During the period from January 1, 2016, through October 10, 2016 (Predecessor), the Company acquired 2,200 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions. Additionally, the Company added 7,692 MBoe of proved reserves through extensions, primarily due to its drilling activity, as well as 660 MBoe due to positive performance revisions, slightly offset by 2,280 MBoe of production.
Proved reserves at December 31, 2015 increased 25% to 32,457 MBoe, compared to 25,970 MBoe at December 31, 2014.
During 2015, the Company added 12,864 MBoe of proved reserves through extensions, primarily due to its drilling activity.
During 2015, the Company had net negative revisions of 4,981 MBoe. The significant decrease in commodity prices seen in 2015 resulted in negative revisions related to the conversion of approximately 6,794 MBoe from PUDs to unproved reserves, partially offset by a positive revision in performance.
During 2015, the Company acquired 1,275 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions.
During 2014, the Company added 21,012 MBoe of proved reserves through extensions and discoveries, primarily due to its continued development drilling program and 265 MBoe of proved reserves, due to better than expected performance of its proved developed reserves.
During 2014, the Company divested of 13,706 MBoe of proved reserves. Refer to Note 3—Property Acquisitions and Dispositions.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of its’ Predecessor’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.
The following table presents the Company’s standardized measure of discounted future net cash flows:
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
(in thousands)
 
 
 
2015
 
2014
Future cash inflows
$
2,105,585

 
 
$
1,217,641

 
$
1,079,962

 
$
1,850,205

Future development costs
(482,162
)
 
 
(297,559
)
 
(277,837
)
 
(440,366
)
Future production costs
(640,306
)
 
 
(413,410
)
 
(450,058
)
 
(457,236
)
Future income tax expenses
(136,587
)
 
 
(5,614
)
 
(6,643
)
 
(10,834
)
Future net cash flows
846,530

 
 
501,058

 
345,424

 
941,769

10% discount to reflect timing of cash flows
(471,438
)
 
 
(291,345
)
 
(210,355
)
 
(575,886
)
Standardized measure of discounted future net cash flows
$
375,092

 
 
$
209,713

 
$
135,069

 
$
365,883

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
 
Successor
 
 
Predecessor
(in thousands)
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
Standardized measure of discounted future net cash flows, beginning of period
$
209,713

 
 
$
135,069

Sales of oil, natural gas and NGLs, net of production costs
(22,354
)
 
 
(49,801
)
Purchase of minerals in place
127,842

 
 
10,145

Divestiture of minerals in place
—

 
 
—

Extensions and discoveries, net of future development costs
55,825

 
 
46,438

Change in estimated development costs
10,891

 
 
11,743

Net change in prices and production costs
(978
)
 
 
6,661

Change in estimated future development costs
571

 
 
28,998

Revisions of previous quantity estimates
20,190

 
 
3,673

Accretion of discount
4,753

 
 
11,319

Net change in income taxes
(47,990
)
 
 
(1,568
)
Net change in timing of production and other
16,629

 
 
7,036

Standardized measure of discounted future net cash flows, end of period
$
375,092

 
 
$
209,713

 
Predecessor
 
Year Ended December 31,
(in thousands)
2015
 
 
2014
Standardized measure of discounted future net cash flows, beginning of period
$
365,883

 
 
$
371,307

Sales of oil, natural gas and NGLs, net of production costs
(58,534
)
 
 
(102,488
)
Purchase of minerals in place
14,416

 
 
5,650

Divestiture of minerals in place
—

 
 
(242,344
)
Extensions and discoveries, net of future development costs
57,894

 
 
312,532

Change in estimated development costs
16,100

 
 
10,386

Net change in prices and production costs
(494,734
)
 
 
(3,027
)
Change in estimated future development costs
247,642

 
 
2,935

Revisions of previous quantity estimates
(51,342
)
 
 
924

Accretion of discount
37,517

 
 
13,561

Net change in income taxes
1,601

 
 
(2,762
)
Net change in timing of production and other
(1,374
)
 
 
(791
)
Standardized measure of discounted future net cash flows, end of period
$
135,069

 
 
$
365,883