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Supplemental Oil and Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Oil and Gas Disclosures (Unaudited)
Supplemental Oil and Gas Disclosures (Unaudited)
    
The accompanying tables presents information concerning the Company’s oil and gas producing activities inclusive of discontinued operations “Disclosures about Oil and Gas Producing Activities.”  Capitalized costs relating to oil and gas producing activities are as follows:

 
 
Years Ended December 31
 
 
2016
 
2017
 
 
(In thousands)
Proved oil and gas properties
 
$
794,634

 
$
923,237

Unproved properties
 
—

 
—

Total
 
794,634

 
923,237

Accumulated depreciation, depletion, amortization and impairment
 
(680,861
)
 
(706,537
)
Net capitalized costs
 
$
113,773

 
$
216,700



Cost incurred in oil and gas property acquisition and development activities are as follows:

 
 
Years Ended December 31
 
 
2015
 
2016
 
2017
 
 
(In thousands)
Development costs
 
$
68,631

 
$
18,262

 
$
94,478

Exploration costs
 
—

 
12,529

 
8,509

Property acquisition costs
 
—

 
—

 
31,409

 
 
$
68,631

 
$
30,791

 
$
134,396



 
 
Years Ended December 31,
 
 
2015
 
2016
 
2017
 
 
 
(In thousands)
Revenues
 
$
67,002

 
$
56,493

 
$
86,189

 
Production costs
 
(29,753
)
 
(23,659
)
 
(22,425
)
 
Depreciation, depletion, and amortization
 
(38,040
)
 
(22,803
)
 
(25,676
)
 
Proved property impairment
 
(128,573
)
 
(67,626
)
 
—

 
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)
 
$
(129,364
)
 
$
(57,595
)
 
$
38,088

 
Depletion rate per barrel of oil equivalent
 
$
17.44

 
$
10.08

 
$
9.52

 


Estimated Quantities of Proved Oil and Gas Reserves

  Reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties.  Accordingly, the estimates are expected to change as future information becomes available.  The estimates have been predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States.

Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the unweighted average prior 12-month-first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods presented.

The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2015, 2016 and 2017.
 
 
Oil
 
NGL
 
Gas
 
Oil
Equivalents
 
 
 
(MBbl)
 
(MBbl)
 
(MMcf)
 
(MBoe)
 
Change in Proved Reserves
 
 
 
 
 
 
 
Balance at December 31, 2014
 
29,390

 
3,708

 
55,853

 
42,406

 
Revisions of previous estimates
 
(9,485
)
 
(505
)
 
(8,002
)
 
(11,324
)
 
Extensions and discoveries
 
5,679

 
3,591

 
30,372

 
14,332

 
Sales of minerals in place
 
(13
)
 
—

 
(181
)
 
(43
)
 
Production
 
(1,440
)
 
(238
)
 
(3,015
)
 
(2,181
)
 
Balance at December 31, 2015
 
24,131

 
6,556

 
75,027

 
43,190

 
Revisions of previous estimates
 
1,379

 
2,300

 
(1,537
)
 
3,424

 
Extensions and discoveries
 
1,183

 
157

 
1,179

 
1,537

 
Sales of minerals in place
 
(1,112
)
 
(6
)
 
(680
)
 
(1,232
)
 
Production
 
(1,372
)
 
(363
)
 
(3,160
)
 
(2,262
)
 
Balance at December 31, 2016
 
24,209

 
8,644

 
70,829

 
44,657

 
Revisions of previous estimates
 
783

 
1,269

 
19,311

 
4,747

 
Extensions and discoveries
 
14,533

 
2,813

 
14,534

 
19,768

 
Purchase of minerals in place
 
8

 
14

 
1,001

 
189

 
Sales of minerals in place
 
(364
)
 
(289
)
 
(3,958
)
 
(1,312
)
 
Production
 
(1,574
)
 
(476
)
 
(3,889
)
 
(2,698
)
 
Balance at December 31, 2017
 
37,595

 
11,975

 
97,828

 
65,351

 

The following is a summary of the changes to the Company’s proved reserves that occurred during 2017:
Revisions to prior estimates:

There was an increase of 621 MBoe of net reserves attributable to changes in projections for the Company’s producing wells based on actual performance during 2017. Most of this increase was attributable to the Company’s Wolfcamp producing wells in Ward County, TX. There was also an increase of 1,951 net MBoe attributable to increases in projections for the Company’s Wolfcamp PUDs in Ward County. These increases were based on the over-performance of the Company’s existing Wolfcamp producing wells as mentioned above. There was also an increase in this category of 2,698 MBoe attributable to increased economic life calculations at the higher commodity pricing experienced during 2017. There were also seven miscellaneous cases in this category that were removed from the report due to the fact that the Company no longer intends to develop them within the five-year allowance. These cases accounted for 523 MBoe of net reserves.

Extensions, discoveries and other additions:

The Company added three new Wolfcamp producing wells in Ward, County, TX, accounting for 1,229 MBoe of net producing reserves. The Company also converted three probable undeveloped Wolfcamp A locations in Ward County, TX, to proved producing reserves during 2017 accounting for 2,028 MBoe of net reserves. The Company also added 27 proved undeveloped Wolfcamp A locations, four Third Bone Spring locations, and two Wolfcamp B locations in Ward County, TX, accounting for 11,928 MBoe of net reserves. These locations are direct offsets to either successful Abraxas producing wells or producing wells operated by others. The Company also converted ten probable undeveloped Wolfcamp A locations in Ward County, TX, to proved undeveloped reserves during 2017 accounting for 4,343 MBoe of net reserves. The Company also developed a new Eagle Ford well in Atascosa County, TX, accounting for 240 MBoe of net reserves.

Purchases:

The company purchased wells and acquired additional interest in existing wells which added 189 MBoe of net reserves.

Sales:

The Company sold substantially all of its holdings in the Powder River Basin of Wyoming during 2017. These sales accounted for the decrease of 1,312 MBoe of net proved reserves.

Production:

The Company produced 2,698 MBoe of net reserves during 2017.

The following is a summary of the changes to the Company’s proved reserves that occurred during 2016:
Revisions to prior estimates:


An increase of 5,005 MBoe of reserves was attributable to the Company’s Bakken and Three Forks proved undeveloped locations in McKenzie County, ND, due to continuing improvement in its producing well production results. Well results improved as a result of the application of optimized completion methods. Similarly, reserves for the Company’s Bakken and Three Forks producing wells increased by 1,360 MBoe of net producing reserves due to improved performance. Projections for the Hedgehog State 16-2H producing well and its two related proved undeveloped locations in the Porcupine Field, Campbell County, WY, decreased by 670 MBoe of net reserves due to the under-performance of the Hedgehog State 16-2H. There was also a reduction in this category of 2,271 MBoe attributable to shortened economic life calculations at the lower commodity pricing.

Extensions, discoveries and other additions:

The Company added the Caprito 99 302H as a new Wolfcamp producing well in Ward County, TX, accounting for 449 MBoe of net producing reserves. It also added five new proved undeveloped Wolfcamp locations offsetting this new producer accounting for 805 MBoe of net undeveloped reserves. The Company also developed a new Austin Chalk producer in Atascosa County, TX, which accounted for 265 MBoe of net producing reserves. Further, the Company added eight new proved undeveloped Bakken/Three Forks locations on non-operated units in McKenzie County, ND, accounting for 18 MBoe of net undeveloped reserves. These locations were added in response to operator well proposals.

Sales:

The Company sold all its holdings in the Portilla Field in San Patricio County, TX, and in the Brooks Draw Field in Converse County, WY, during 2016. These sales accounted for 1,232 MBoe of net proved reserves.

Production:
The Company produced 2,262 MBoe of net reserves during 2016.
The following is a summary of the changes to the Company’s proved reserves that occurred during 2015:
Revisions of prior estimates:
A total of 48 proved locations accounting for approximately 7.9 net MMBoe of reserves were dropped from the report in 2015 due to lack of economic viability at the lower commodity pricing applied of which 42 were in the undeveloped category. Most significant of these were 38 South Texas Eagle Ford locations representing approximately 7,717 MBoe of net reserves. There was also a reduction of 614 net MBoe attributable to shortened economic life calculations at lower commodity pricing which were partially offset by an increase of 600 net MBoe in the Company’s Bakken/Three Forks undeveloped locations due to better-than-anticipated production. There were also reduction in this category of 1.8 MMBoe of net reserves attributable to shortened economic life calculations at the lower commodity pricing and 1.6 MMBoe of net reserves attributable to lower than anticipated production performance in various wells.
Extensions, discoveries and other additions:

The Company added 28 new proved undeveloped Bakken locations during 2015 on the Company’s prospect acreage in McKenzie County, North Dakota, accounting for approximately 6.5 MMBoe of net reserves, 20 of which accounted for 4.9 net MMBoe, were for the Three Forks (2nd Bench) which were proved by local development activity in that reservoir during the year. There were also 8 other cases in the Bakken/Three Forks, accounting for 1.6 net MMBoe, which were added because the Company gained operational control of the Yellowstone Unit resulting in the Company developing the properties in accordance with its normal well spacing pattern.

The Company also gained proved undeveloped reserves of approximately 1.3 net MMBOE, due to the change in classification of 21 probable and possible undeveloped Bakken cases into the proved category. This change was warranted by local well development in the specific local areas during 2015.

The Company also added 6 new Montoya proved undeveloped locations on the Company’s prospect acreage in Ward County, Texas, accounting for 6.5 MMBOE of net reserves. These locations were added based on the performance of existing Montoya producers on the subject acreage.

Sales:
During 2015, the Company sold properties accounting for 43 net MBoe of reserves.

Production:

During 2015, the Company produced 2,181 of net MBoe of reserves


The following table presents the Company's estimate of its net proved oil and gas reserves as of December 31, 2015, 2016 and 2017:
 
 
Total
 
 
 
Oil
 
NGL
 
Gas
 
Oil
Equivalents
 
 
 
(MBbl)
 
(MBbl)
 
(MMcf)
 
(MBoe)
 
 
 
(In thousands)
Proved Developed Reserves:
 
 
 
 
 
 
 
 
 
December 31, 2015
 
10,022

 
1,956

 
31,298

 
17,194

 
December 31, 2016
 
7,818

 
2,568

 
27,792

 
15,018

 
December 31, 2017
 
10,820

 
3,794

 
39,974

 
21,720

 
Proved Undeveloped Reserves:
 
 
 
 
 
 
 
 
 
December 31, 2015
 
14,109

 
4,599

 
43,729

 
25,996

 
December 31, 2016
 
16,391

 
6,076

 
43,037

 
29,639

 
December 31, 2017
 
25,808

 
8,181

 
57,854

 
43,631

 


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
The Company’s proved oil and gas reserves have been estimated by the Company with the assistance of an independent petroleum engineering firm (DeGolyer & MacNaughton) as of December 31, 2015, 2016 and 2017.

The following information has been prepared in accordance with SEC rules and accounting standards based on the 12-month first-day-of-the-month unweighted average prices in accordance with provisions of the FASB’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis and net operating losses associated with the properties.  Since prices used in the calculation are average prices for 2017, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year.
 
The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.    All reports by DeGolyer and MacNaughton were developed utilizing studies performed by DeGolyer and MacNaughton and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers.  The report of DeGolyer and MacNaughton dated February 14, 2018, contains further discussions of the reserve estimates and evaluations prepared by DeGolyer and MacNaughton as well as the qualifications of DeGolyer and MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.
 
Estimates of proved reserves at December 31, 2015, 2016 and 2017 were based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas.  The Engineering department is directly responsible for Abraxas’ reserve evaluation process.  The Vice President of Engineering is the manager of this department and is the primary technical person responsible for this process.  The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and has 39 years of experience in reserve evaluations. The Vice President of Engineering is a Registered Professional Engineer in the State of Texas.  The operations department of Abraxas assisted in the process.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent the fair market value of the Company’s proved oil and gas reserves.  An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below sets forth the Standardized Measure of our proved oil and gas reserves for the three years ended December 31, 2015, 2016 and 2017:
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2015
 
2016
 
2017
 
 
 
(In thousands)
 
Future cash inflows
 
$
1,241,334

 
$
999,716

 
$
2,035,619

 
Future production costs
 
(438,784
)
 
(357,917
)
 
(609,921
)
 
Future development costs
 
(338,316
)
 
(267,836
)
 
(461,619
)
 
Future income tax expense (1)
 
—

 
—

 
(83,915
)
 
Future net cash flows
 
464,234

 
373,963

 
880,164

 
Discount
 
(266,983
)
 
(213,363
)
 
(474,423
)
 
Standardized Measure of discounted future net cash relating to proved reserves
 
$
197,251

 
$
160,600

 
$
405,741

 


(1) There was no provision for future income tax expense for the years ended December 31, 2015 and 2016 due to net operating loss carryovers.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure:

 
 
Year Ended December 31,
 
 
2015
 
2016
 
2017
 
 
(In thousands)
Standardized Measure, beginning of year
 
$
512,557

 
$
197,251

 
$
160,600

Sales and transfers of oil and gas produced, net of production costs
 
(37,249
)
 
(32,834
)
 
(63,764
)
Net change in prices and development and production costs from prior year
 
(488,160
)
 
(58,425
)
 
159,661

Extensions, discoveries, and improved recovery, less related costs
 
63,341

 
5,531

 
129,277

Sales of minerals in place
 
(197
)
 
(4,433
)
 
(8,583
)
Purchases of minerals in place
 
—

 
—

 
1,238

Revisions of previous quantity estimates
 
(49,602
)
 
12,317

 
31,044

Change in timing and other
 
20,419

 
21,468

 
1,908

Change in future income tax expense
 
124,886

 
—

 
(21,700
)
Accretion of discount
 
51,256

 
19,725

 
16,060

Standardized Measure, end of year
 
$
197,251

 
$
160,600

 
$
405,741




The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates:

 
 
Year Ended December 31,
 
 
2015
 
2016
 
2017
Oil (per Bbl) (1)
 
$
50.12

 
$
42.74

 
$
51.34

Gas (per MMbtu) (2)
 
$
2.63

 
$
2.50

 
$
2.99

Oil (per Bbl) (3)
 
$
41.25

 
$
35.54

 
$
46.83

Gas (per MMBtu) (4)
 
$
2.36

 
$
1.41

 
$
1.79

NGL’s (per Bbl) (5)
 
$
10.52

 
$
5.17

 
$
13.19

_____________________
(1)
The quoted oil price for the year ended December 31 of each year, 2015, 2016 and 2017 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2015, 2016 and 2017.
(2)
The quoted gas price for the year ended December 31, 2015, 2016 and 2017 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2015, 2016 and 2017.
(3)
The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
(4)
The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
(5)
The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.