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Supplementary Information on Oil and Gas Operations—Unaudited
 12 Months Ended
Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplementary Information of Oil and Gas Operations—Unaudited
Supplementary Information on Oil and Gas Operations—Unaudited
The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore in the continental United States:
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(amounts in thousands)
 
For the Year-Ended December 31,
 
2018
 
2017
 
2016
Acquisition costs:
 
 
 
 
 
     Proved
$
241

 
$
1,330

 
$
3,346

     Unproved (1)
6,190

 
12,762

 
2,197

Divestiture of proved leasehold
(2,604
)
 
(4,795
)
 
(7,000
)
Exploration costs:
 
 
 
 
 
     Proved
(51
)
 
9,466

 
715

     Unproved
233

 
(287
)
 
603

Development costs (2)
(18,928
)
 
32,622

 
1,522

Capitalized general and administrative and interest costs
8,070

 
8,269

 
7,558

Total costs incurred
$
(6,849
)
 
$
59,367

 
$
8,941


 
For the Year-Ended December 31,
  
2018
 
2017
 
2016
Accumulated depreciation, depletion and amortization (DD&A)
 
 
 
 
 
   Balance, beginning of year
$
(1,285,660
)
 
$
(1,243,286
)
 
$
(1,157,455
)
   Provision for DD&A
(22,410
)
 
(31,667
)
 
(27,962
)
   Ceiling test writedown
—

 
—

 
(40,304
)
   Sale of proved properties and other (3)
6,478

 
(10,707
)
 
(17,565
)
Balance, end of year
$
(1,301,592
)
 
$
(1,285,660
)
 
$
(1,243,286
)
 
 
 
 
 
 
DD&A per Mcfe
$
1.05

 
$
1.15

 
$
1.19

(1)
During 2017, the Company acquired approximately 24,600 gross acres for approximately $9.3 million in cash and 2.0 million shares of common stock. In total for 2017 and 2018, the Company has invested approximately $15.0 million in leasing costs and geological and engineering data.
(2)
During 2018, the Company sold its Gulf of Mexico properties and removed approximately $28.2 million of future discounted asset retirement obligations, which was recorded as a reduction in the capitalized costs of oil and gas properties.
(3)
During 2018, the Company sold its Gulf of Mexico properties, receiving no cash consideration and funding amounts related to the future abandonment costs for the properties and purchase price adjustments. During 2017, the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million. During 2016, the Company sold its remaining Oklahoma producing assets for net proceeds of $17.6 million.
At December 31, 2018 and 2017, unevaluated oil and gas properties totaled $23.5 million and $21.9 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2018 included $0.9 million of costs related to wells in progress at year-end. At December 31, 2017, unevaluated costs included $0.7 million related to two facilities in progress at year-end, which were transferred to evaluated oil and gas properties during 2018. The Company capitalized $1.8 million, $1.6 million and $0.9 million of interest during 2018, 2017 and 2016, respectively. Of the total unevaluated oil and gas property costs of $23.5 million at December 31, 2018, $7.4 million, or 32%, was incurred in 2018, $13.9 million, or 59%, was incurred in 2017 and $2.2 million, or 9%, was incurred in prior years. In connection with the sale of the Company's Gulf of Mexico assets, approximately $5.5 million, or 25% of the total unevaluated balance at December 31, 2017, was transferred to evaluated oil and gas properties in 2018. Of the remaining unevaluated balance at December 31, 2018, the Company expects the majority of the costs will be evaluated within the next three years, including $2.7 million expected to be evaluated during 2019.
Oil and Gas Reserve Information
The Company’s net proved oil and gas reserves at December 31, 2018 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-month, first of month, average pricing assumption.
The estimates of proved oil and gas reserves constitute those quantities of oil, gas,and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate), gas and natural gas liquid reserves, all located onshore and offshore in the continental United States:
 
Oil
in
MBbls
 
NGL
in
MMcfe
 
Natural Gas
in
MMcf
 
Total
Reserves
in MMcfe
Proved reserves as of December 31, 2015
1,806

 
34,826

 
132,344

 
178,004

  Revisions of previous estimates
247

 
(4,380
)
 
(11,854
)
 
(14,748
)
  Extensions, discoveries and other additions
—

 
—

 
1,485

 
1,485

  Sale of reserves in place
(154
)
 
—

 
(24,834
)
 
(25,759
)
  Production
(502
)
 
(3,871
)
 
(16,617
)
 
(23,501
)
Proved reserves as of December 31, 2016
1,397

 
26,575

 
80,524

 
115,481

  Revisions of previous estimates
308

 
(7,269
)
 
381

 
(5,040
)
  Extensions, discoveries and other additions
777

 
4,565

 
64,704

 
73,931

  Purchase of producing properties
48

 
—

 
473

 
761

  Sale of reserves in place
(90
)
 
—

 
(1,033
)
 
(1,573
)
  Production
(592
)
 
(4,450
)
 
(19,611
)
 
(27,613
)
Proved reserves as of December 31, 2017
1,848

 
19,421

 
125,438

 
155,947

  Revisions of previous estimates
130

 
(1,469
)
 
2,737

 
2,044

  Extensions, discoveries and other additions
41

 
2,929

 
7,947

 
11,121

  Sale of reserves in place
(507
)
 
(486
)
 
(13,945
)
 
(17,472
)
  Production
(326
)
 
(3,373
)
 
(16,013
)
 
(21,335
)
Proved reserves as of December 31, 2018
1,186

 
17,022

 
106,164

 
130,305

 
 
 
 
 
 
 
 
Proved developed reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  As of December 31, 2016
1,212

 
13,073

 
47,349

 
67,694

 
 
 
 
 
 
 
 
  As of December 31, 2017
1,078

 
12,564

 
57,409

 
76,441

 
 
 
 
 
 
 
 
  As of December 31, 2018
567

 
10,220

 
47,516

 
61,143

 
 
 
 
 
 
 
 
Proved undeveloped reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  As of December 31, 2016
185

 
13,502

 
33,175

 
47,787

 
 
 
 
 
 
 
 
  As of December 31, 2017
770

 
6,857

 
68,029

 
79,506

 
 
 
 
 
 
 
 
  As of December 31, 2018
619

 
6,802

 
58,648

 
69,162


Year Ended December 31, 2018    
During 2018, the Company’s estimated proved reserves decreased by 16%. The decrease in reserves was the result of 10.1 Bcfe removed as a result of the sale of our Gulf of Mexico assets in January 2018 and 7.3 Bcfe removed due to the selldown of certain of our PUDs in East Texas. Partially offsetting these decreases was an increase of 11.1 Bcfe of PUD reserves from third party drilling as well as the Company's leasing efforts in East Texas. Overall, the Company had a 100% drilling success rate on two wells completed during 2018.
Year Ended December 31, 2017    
During 2017, the Company’s estimated proved reserves increased by 35%. The increase in reserves was the result of 73.9 Bcfe added due to the Company's drilling program in East Texas where it drilled eight gross wells during 2017. In response to low ethane prices, during 2017 the Company elected to bypass ethane processing on a portion of its East Texas production. As a result, the Company reduced its estimated proved ngl reserves to reflect the assumption that ethane would continue to not be recovered as natural gas liquids. Overall, the Company had a 100% drilling success rate during 2017.
Year Ended December 31, 2016 
During 2016, the Company's estimated proved reserves decreased by 35% primarily due to the divestiture of the Company's remaining Oklahoma assets and significant reductions in capital spending during 2016. Extensions, discoveries and other additions of 1.5 Bcfe were primarily due to the successful completion of the Company's final Oklahoma wells. Revisions of previous estimates included the reclassification of certain PUD reserves to probable reserves as a result of the Company's assessment of the timing of development. Overall, the Company had a 100% drilling success rate during 2016 on 5 gross wells drilled.
The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by ASC Topic 932. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate.
Standardized Measure
 
 
December 31,
 
2018
 
2017
 
2016
Future cash flows
$
482,766

 
$
539,244

 
$
299,035

Future production costs
(171,999
)
 
(184,171
)
 
(117,283
)
Future development costs
(73,258
)
 
(128,447
)
 
(83,720
)
Future income taxes
—

 
—

 
—

Future net cash flows
237,509

 
226,626

 
98,032

10% annual discount
(113,484
)
 
(99,329
)
 
(30,763
)
Standardized measure of discounted future net cash flows
$
124,025

 
$
127,297

 
$
67,269


Changes in Standardized Measure
 
Year Ended December 31,
 
2018
 
2017
 
2016
Standardized measure at beginning of year
$
127,297

 
$
67,269

 
$
127,685

 
 
 
 
 
 
Sales and transfers of oil and gas produced, net of production costs
(64,148
)
 
(70,362
)
 
(35,993
)
Changes in price, net of future production costs
18,542

 
53,516

 
(30,427
)
Extensions and discoveries, net of future production and development costs
2,983

 
50,977

 
864

Changes in estimated future development costs, net of development costs incurred during this period
16,241

 
17,144

 
26,356

Revisions of quantity estimates
2,755

 
(7,482
)
 
(14,889
)
Accretion of discount
12,730

 
6,727

 
12,769

Purchase of reserves in place
—

 
549

 
—

Sale of reserves in place
1,614

 
(1,305
)
 
(16,701
)
Changes in production rates (timing) and other
6,011

 
10,264

 
(2,395
)
Net increase (decrease) in standardized measure
(3,272
)
 
60,028

 
(60,416
)
Standardized measure at end of year
$
124,025

 
$
127,297

 
$
67,269


    
The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were:
 
2018
 
2017
 
2016
Oil, $/Bbl
$68.71
 
$52.49
 
$40.85
Ngls, $/Mcfe
4.08

 
3.23

 
2.40

Natural Gas, $/Mcf
3.13

 
3.03

 
1.82