16.

Supplemental Oil and Gas Disclosures (Unaudited)

The accompanying tables (in thousands) presents information concerning the Company’s oil and gas producing activities “Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows as of

December 31:

	Years Ended December 31,
	2017			2018
Proved oil and gas properties	$	923,237		$	1,091,905
Unproved properties		-			-
Total		923,237			1,091,905
Accumulated depreciation, depletion, amortization and impairment		(706,537	)		(748,773	)
Net capitalized costs	$	216,700		$	343,132

Cost incurred in oil and gas property acquisition and development activities were as follows for the years ended

December 31 (

in thousands):

	2016		2017		2018
Development costs	$	18,262	$	94,478	$	131,271
Exploration costs		12,529		8,509		-
Property acquisition costs		-		31,409		41,465
	$	30,791	$	134,396	$	172,736

Results of operations from oil and gas producing activities were as follows for the years ended

December 31:


		2016			2017			2018
Revenues	$	56,493		$	86,189		$	149,030
Production costs		(23,659	)		(22,425	)		(36,323	)
Depreciation, depletion and amortization		(22,803	)		(25,676	)		(42,237	)
Proved property impairment		(67,626	)		-			-
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	(57,595	)	$	38,088		$	72,488

Depletion rate per barrel of oil equivalent	$	10.08		$	9.52		$	11.80

Estimated Quantities of Proved Oil and Gas Reserves

Reserve estimates are inherently imprecise and 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

provision for price and cost escalations except by contractual arrangements; therefore, the unweighted average prior

-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 set forth changes in estimated net proved reserves for the years ended

December

31,

2016,

2017

and

2018.

										Oil
	Oil			NGL			Gas			Equivalents
	(MBbl)			(MBbl)			(MMcf)			(Mboe)
Change in Proved Reserves
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		259			1,269			19,311			4,747
Extensions and discoveries		14,533			2,813			14,534			19,768
Purchases 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		37,071			11,975			97,828			65,351
Revisions of previous estimates		(4,206	)		(1,927	)		(2,618	)		(6,570	)
Extensions and discoveries		11,270			1,797			11,475			14,979
Purchases of minerals in place		688			-			1,137			877
Sales of minerals in place		(278	)		(1,303	)		(13,491	)		(3,829	)
Production		(2,308	)		(508	)		(4,587	)		(3,580	)
Balance at December 31, 2018		42,237			10,034			89,744			67,228

The following is a summary of the changes to the Company’s proved reserves that occurred during

2018:

Revisions to prior estimates

There was a decrease of

MBoe of net reserves attributable to changes in projections for the Company’s producing wells based on actual performance during

2018.

The Company also converted

thirteen

proved undeveloped Three Fork

bench locations in McKenzie County, North Dakota, to probable undeveloped reserves during

2018,

accounting for

6,525

MBoe of net reserves. These locations are

longer included in the Company’s

five

-year development plan.

Extensions, discoveries and other additions

The Company added

nineteen

new proved undeveloped operated locations accounting for

8,130

MBoe of net reserves along with

two

proved undeveloped non-operated locations accounting for

838

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

two

probable undeveloped locations to producing reserves accounting for

1,523

MBoe of net reserves. The Company also converted

five

probable undeveloped locations to proved undeveloped reserves accounting for

2,670

MBoe of net reserves. In the Bakken/Three Forks system in McKenzie County, North Dakota, during

2018

the Company added

three

new proved undeveloped locations attributable to unit line well configurations accounting for

1,692

MBoe of net reserves. The Company also added

six

new non-operated proved non-producing locations accounting for

126

MBoe of net reserves.

Purchases:

In the

Wolfcamp/3

Bone Spring system in Ward, County, Texas, during

2018

the Company acquired

four

new producing wells accounting for

877

MBoe of net producing reserves.

Sales:

The Company sold substantially all its holdings in the Ira Area accounting for

203

MBoe of net proved reserves. The Company also sold

one

producing and

two

proved undeveloped Delaware locations in Ward County, Texas, accounting for

3,558

MBoe of net reserves. Other miscellaneous asset sales during the year accounted for

MBoe of net reserves.

Production:

The Company produced

3,580

MBoe of net reserves during

2018.

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, Texas. 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

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, Texas 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

proved undeveloped Wolfcamp A locations,

four

Third Bone Spring locations, and

two

Wolfcamp B locations in Ward County, Texas, 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, Texas, 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, Texas, 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, North Dakota, 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

producing well and its

two

related proved undeveloped locations in the Porcupine Field, Campbell County, Wyoming, decreased by

670

MBoe of net reserves due to the under-performance of the Hedgehog State

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

302H

as a new Wolfcamp producing well in Ward County, Texas, 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, Texas, 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, North Dakota, accounting for

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, Texas, and in the Brooks Draw Field in Converse County, Wyoming, 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 table presents the Company's estimate of its net proved developed and undeveloped oil and gas reserves as of

December 31, 2016,

2017

and

2018:

	Total
							Oil
	OIl		NGL		Gas		Equilavents
	(MBbl)		(MBbl)		(MMcf)		(Mboe)
Proved Developed Reserves:
December 31, 2016		7,818		2,568		27,792		15,018
December 31, 2017		10,820		3,794		39,974		21,720
December 31, 2018		13,586		3,804		43,271		24,602

Proved Undeveloped Reserves:
December 31, 2016		16,391		6,076		43,037		29,639
December 31, 2017		25,808		8,181		57,854		43,631
December 31, 2018		28,651		6,230		46,473		42,626

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, 2016,

and

2017

and LaRoche Petroleum Consultants as of

December 31,

2018,

assisted by the engineering and operations departments of the Company.

The following information has been prepared in accordance with SEC rules and accounting standards based on the

-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

2016,

2017,

and

2018,

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 LaRoche Petroleum Consultants 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. LaRoche Petroleum Consultants 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 LaRoche Petroleum Consultants were developed utilizing studies performed by LaRoche Petroleum Consultants and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers. The report of LaRoche Petroleum Consultants dated

February 12

2019,

contains further discussions of the reserve estimates and evaluations prepared by LaRoche Petroleum Consultants as well as the qualifications of LaRoche Petroleum Consultants’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, 2016,

2017

and

2018

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

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, 2016,

2017

and

2018

(in thousands):

	Years Ended December 31,
	2016			2017			2018
Future cash inflows	$	999,716		$	2,035,619		$	2,876,976
Future production costs		(357,917	)		(609,921	)		(849,063	)
Future development costs		(267,836	)		(461,619	)		(547,163	)
Future income tax expense (1)		-			(83,915	)		(181,224	)
Future net cash flows		373,963			880,164			1,299,526
Discount	$	(213,363	)	$	(474,423	)	$	(647,642	)
Standardized Measure of discounted future net cash relating to proved reserves	$	160,600		$	405,741		$	651,884

(

)

There was

provision for future income tax expense for the year ended

December 31, 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 for the periods indicated (in thousands):

	Years Ended December 31,
	2016			2017			2018
Standardized Measure, beginning of year	$	197,251		$	160,600		$	405,741
Sales and transfers of oil and gas produced, net of production costs		(32,834	)		(63,764	)		(112,707	)
Net change in prices and development and production costs from prior year		(58,425	)		159,661			268,942
Extensions, discoveries, and improved recovery, less related costs		5,531			129,277			153,544
Sales of minerals in place		(4,433	)		(8,583	)		(39,253	)
Purchases of minerals in place		-			1,238			8,990
Revisions of previous estimates		12,317			31,044			(67,345	)
Change in timing and other		21,468			1,908			30,811
Change in future income tax expense		-			(21,700	)		(37,413	)
Accretion of discount		19,725			16,060			40,574
Standardized Measure, end of year	$	160,600		$	405,741		$	651,884

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

	Years Ended December 31,
	2016		2017		2018
Oil (per Bbl) (1)	$	42.74	$	51.34	$	65.56
Gas (per MMbtu) (2)	$	2.50	$	2.99	$	3.05
Oil (per Bbl) (3)	$	35.54	$	46.83	$	56.95
Gas (per MMbtu) (4)	$	1.41	$	1.79	$	1.76
NGL's (per Bbl) (5)	$	5.17	$	13.19	$	19.95

_____________________

(

)

The quoted oil price for the year ended

December 31

of each year,

2016,

2017

and

2018

is the

-month unweighted average

first

-day-of-the-month West Texas Intermediate spot price for each month of

2016,

2017

and

2018.

(

)

The quoted gas price for the year ended

December 31, 2016,

2017

and

2018

is the

-month unweighted average

first

-day-of-the-month Henry Hub spot price for each month of

2016,

2017

and

2018.

(

)

The oil price is the realized price at the wellhead as of

December 31

of each year after the appropriate differentials have been applied.

(

)

The gas price is the realized price at the wellhead as of

December 31

of each year after the appropriate differentials have been applied.

(

)

The NGL price is the realized price as of

December 31

of each year after the appropriate differentials have been applied.