ABRAXAS PETROLEUM CORP - Quarter Report: 2019 March (Form 10-Q)

Three Months Ended

March 31,

axas20190331_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2019

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______ TO ______

COMMISSION FILE NUMBER: 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada		74-2584033
(State of Incorporation)		(I.R.S. Employer Identification No.)

18803 Meisner Drive, San Antonio, TX 78258

(Address of principal executive offices) (Zip Code)

210-490-4788

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered:
Common Stock, pare value $.01 per share	AXAS	The NASDAQ Stock Market, LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filer ☐	Accelerated filer ☒
Non-accelerated filer ☐	Smaller reporting company ☐
(Do not mark if a smaller reporting company)	Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Sec 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐No ☒

The number of shares of the issuer’s common stock outstanding as of May 6, 2019 was 168,368,981.

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Forward-Looking Information

We make forward-looking statements throughout this report. Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “may,” “estimate,” “could,” “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable. The forward-looking information contained in this report is generally located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends. The factors that may affect our expectations regarding our operations include, among others, the following:

•

the prices we receive for our production and the effectiveness of our hedging activities;

•

the availability of capital including under our credit facility;

•

our success in development, exploitation and exploration activities;

•

declines in our production of oil and gas;

	•	our indebtedness and the significant amount of cash required to service our indebtedness;

	•	the proximity, capacity, cost and availability of pipelines and other transportation facilities; and

•

limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our bank credit facility and restrictive debt covenants;

•

our ability to make planned capital expenditures;

•

ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices;

•

political and economic conditions in oil producing countries, especially those in the Middle East;

•

price and availability of alternative fuels;

•

our ability to procure services and equipment for our drilling and completion activities;

•

our acquisition and divestiture activities;

•

weather conditions and events; and

•

other factors discussed elsewhere in this report.

Initial production, or IP, rates, for both our wells and for those wells that are located near our properties, are limited data points in each well’s productive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may change as additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimate recovery, or EUR, or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peak IP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable. Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as lease-line offsets. Abraxas' standard length laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-length laterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,500 feet and 8,000 feet. Long laterals, sometimes referred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet.

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GLOSSARY OF TERMS

Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit. Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

“Boed or Boepd" – barrels of oil equivalent per day.

“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

Terms used to describe our interests in wells and acreage:

“Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells.

“Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting reserves.

“Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion.

“Exploratory well” is a well drilled to find and produce oil and or gas in an unproved area, to find a new reservoir in a field previously found to be producing in another reservoir, or to extend a known reservoir.

“Gross acres” are the number of acres in which we own a working interest.

“Gross well” is a well in which we own a working interest.

“Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross acres is equivalent to 160 net acres).

“Net well” is the sum of fractional ownership working interests in gross wells.

“Productive well” is an exploratory or a development well that is not a dry hole.

“Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

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Terms used to assign a present value to or to classify our reserves:

“Developed oil and gas reserves*” Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Proved developed non-producing reserves*” are those quantities of oil and gas reserves that are developed behind pipe in an existing well bore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

“Proved developed reserves*” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves*” Reserves 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 undeveloped reserves” or “PUDs*” Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.

“PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”). PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

“Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation or de-escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, “Disclosures About Oil and Gas Producing Activities.”

“Undeveloped oil and gas reserves*" Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition, see: http://www.ecfr.gov/cgi-bin/retrieveECFR?gp=1&SID=7aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_610

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ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

PART I


ITEM 1 -	Financial Statements	6
	Condensed Consolidated Balance Sheets - March 31, 2019 (unaudited) and December 31, 2018	6
	Condensed Consolidated Statements of Operations – (unaudited) Three Months Ended March 31, 2019 and 2018	8
	Condensed Consolidated Statements of Stockholders' Equity (unaudited) Three Months Ended March 31, 2019 and 2018	9
	Condensed Consolidated Statements of Cash Flows – (unaudited) Three Months Ended March 31, 2019 and 2018	10
	Notes to Condensed Consolidated Financial Statements - (unaudited)	11

ITEM 2 -	Management's Discussion and Analysis of Financial Condition and Results of Operations	24

ITEM 3 -	Quantitative and Qualitative Disclosures about Market Risk	35

ITEM 4 -	Controls and Procedures	35

PART II
OTHER INFORMATION

ITEM 1 -	Legal Proceedings	36
ITEM 1A -	Risk Factors	36
ITEM 2 -	Unregistered Sales of Equity Securities and Use of Proceeds	36
ITEM 3 -	Defaults Upon Senior Securities	36
ITEM 4 -	Mine Safety Disclosure	36
ITEM 5 -	Other Information	36
ITEM 6 -	Exhibits	36
	Signatures	37

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Part I

FINANCIAL STATEMENTS

Item 1. Financial Statements

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	March 31,			December 31,
	2019			2018
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,325		$	867
Accounts receivable:
Joint owners, net		6,296			17,110
Oil and gas production sales		22,727			21,991
Other		503			535
Total accounts receivable		29,526			39,636

Derivative asset - short-term		294			9,602
Other current assets		792			626
Total current assets		31,937			50,731

Property and equipment:
Proved oil and gas properties, full cost method		1,120,788			1,091,905
Other property and equipment		39,494			39,453
Total		1,160,282			1,131,358
Less accumulated depreciation, depletion, amortization and impairment		(781,604	)		(768,140	)
Total property and equipment, net		378,678			363,218

Operating lease right-of-use assets		579			-
Deferred financing fees, net		1,084			1,149
Derivative asset - long-term		2,654			10,527
Other assets		265			265
Total assets	$	415,197		$	425,890

See accompanying notes to condensed consolidated financial statements (unaudited).

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

	March 31,			December 31,
	2019			2018
	(Unaudited)
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	40,070		$	39,571
Joint interest oil and gas production payable		24,323			23,063
Accrued interest		367			335
Other accrued expenses		795			511
Operating lease liability - current		371			—
Derivative liability short-term		10,417			616
Current maturities of long-term debt		270			267
Total current liabilities		76,613			64,363

Long-term debt – less current maturities		182,022			183,091
Operating lease liabilities		208			—
Derivative liability long-term		6,837			4,434
Future site restoration		7,688			7,492
Total liabilities		273,368			259,380

Commitments and contingencies (Note 9)

Stockholders’ Equity:
Preferred stock, par value $0.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding		—			—
Common stock, par value $0.01 per share, authorized 400,000,000 shares; 167,136,398 and 166,713,784 issued and outstanding at March 31, 2019 and December 31, 2018, respectively		1,671			1,667
Additional paid-in capital		418,614			417,844
Accumulated deficit		(278,456	)		(253,001	)
Total stockholders’ equity		141,829			166,510
Total liabilities and stockholders’ equity	$	415,197		$	425,890

See accompanying notes to condensed consolidated financial statements (unaudited).

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

	Three Months Ended March 31,
	2019			2018
Revenues:
Oil and gas production revenues
Oil	$	31,981		$	35,994
Gas		1,473			2,377
Natural gas liquids		1,056			2,223
Other		4			36
Total revenue		34,514			40,630
Operating costs and expenses:
Lease operating		7,734			4,569
Production and ad valorem taxes		3,098			3,113
Rig expense		672			-
Depreciation, depletion, amortization and accretion		13,574			10,260
General and administrative (including stock-based compensation of $373 and $586, respectively)		2,728			2,728
Total operating cost and expenses		27,806			20,670
Operating income		6,708			19,960

Other (income) expense:
Interest expense		2,967			1,199
Amortization of deferred financing fees		121			96
Loss on derivative contracts		29,075			7,883
Loss on sale of non-oil and gas assets		-			3
Total other expense		32,163			9,181
(Loss) income before income tax		(25,455	)		10,779
Income tax (expense) benefit		—			—
Net (loss) income	$	(25,455	)	$	10,779

Net (loss) income per common share - basic	$	(0.15	)	$	0.07
Net (loss) income per common share - diluted	$	(0.15	)	$	0.06

Weighted average shares outstanding:
Basic		166,041			165,133
Diluted		166,041			167,243

See accompanying notes to condensed consolidated financial statements (unaudited).

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ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

					Additional
	Common Stock				Paid in		Accumulated
	Shares		Amount		Capital		Deficit			Total
Balance at December 31, 2018		166,713,784	$	1,667	$	417,844	$	(253,001	)	$	166,510
Net loss		-		-		-		(25,455	)		(25,455	)
Stock-based compensation		-		-		373		-			373
Stock options exercised		422,614		4		397		-			401
Restricted stock issued, net of forfeitures				-		-		-			-
Balance at March 31, 2019		167,136,398	$	1,671	$	418,614	$	(278,456	)	$	141,829

						Additional
	Common Stock					Paid in		Accumulated
	Shares			Amount		Capital		Deficit			Total
Balance at December 31, 2017		165,889,901		$	1,659	$	415,471	$	(310,822	)	$	106,308
Net income		-			-		-		10,779			10,779
Stock-based compensation		-			-		586		-			586
Stock options exercised		11,918			-		11		-			11
Restricted stock issued, net of forfeitures		(20,125	)		-		-		-			-
Balance at March 31, 2018		165,881,694		$	1,659	$	416,068	$	(300,043	)	$	117,684

See accompanying notes to condensed consolidated financial statements (unaudited).

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2019			2018
Operating Activities
Net (loss) income	$	(25,455	)	$	10,779
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Loss on sale of non-oil and gas assets		-			3
Net loss on derivative contracts		29,075			7,883
Net cash settlements (paid) received on derivative contracts		(311	)		(3,789	)
Depreciation, depletion, and amortization		13,463			10,130
Amortization of deferred financing fees		121			96
Accretion of future site restoration		111			130
Stock-based compensation		373			586
Settlement of asset retirement obligation		(386	)		—
Changes in operating assets and liabilities:
Accounts receivable		10,110			6,467
Other assets		84			686
Accounts payable and accrued expenses		1,010			(741	)
Net cash provided by operating activities		28,195			32,230

Investing Activities
Capital expenditures, including purchases and development of properties		(28,008	)		(47,959	)
Proceeds from the sale of oil and gas properties		992			—
Proceeds from the sale of non-oil and gas assets		-			1
Net cash used in provided by investing activities		(27,016	)		(47,958	)

Financing Activities
Proceeds from long-term borrowings		3,000			26,000
Payments on long-term borrowings		(4,066	)		(6,065	)
Deferred financing fees		(56	)		(191	)
Exercise of stock options		401			11
Net cash provided by (used in) financing activities		(721	)		19,755

Increase in cash and cash equivalents		458			4,027
Cash and cash equivalents at beginning of period		867			1,618
Cash and cash equivalents at end of period	$	1,325		$	5,645

Supplemental disclosures of cash flow information:
Interest paid	$	2,939		$	1,020

Non-cash investing and financing activities
Change in capital expenditures included in accounts payable	$	1,822		$	(16,924	)
Change in asset retirement obligations	$	85		$	320

See accompanying notes to condensed consolidated financial statements (unaudited).

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ABRAXAS PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(tabular amounts in thousands, except per share data)

1. Basis of Presentation

The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on March 15, 2019. Such policies have been continued without change, except as noted herein, due to the change in lease accounting adopted in the current period. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim condensed consolidated financial statements have not been audited by our independent registered public accountants, and in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations and the cash flows for the three month period ended March 31, 2019 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

Reclassifications

Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.

Consolidation Principles

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including Raven Drilling, LLC (“Raven Drilling”).

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with properties in which the Company or its affiliates hold an ownership, or other economic interest. Any income not recognized as a result of this limitation is credited to the full cost pool and recognized through lower amortization as reserves are produced.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recently Adopted Lease Accounting Standard

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use (“ROU”) asset and lease liability for certain leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements.

The new standard was effective for us in the first quarter of 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized a ROU asset (or operating lease right-of-use asset) and a lease liability with no retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to:

●

Not apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of 12 months or less);

●

Not reassess whether a contract contains a lease, lease classification and initial direct costs; and

●

Not reassess certain land easements in existence prior to January 1, 2019.

The impact of adoption of this new standard on our balance sheet is as follows (in thousands):

	January 1, 2019
Operating lease ROU asset	$	687
Operating lease liability - current	$	(108	)
Operating lease liability - long-term	$	(579	)

Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update. For more information, see Note 8.

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Stock-Based Compensation and Option Plans

Stock Options

The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.

The following table summarizes the Company’s stock-based compensation expense related to stock options for the periods presented:

The following table summarizes the Company’s stock option activity for the three months ended March 31, 2019 (shares in thousands):

	Number of Shares (thousands)			Weighted Average Option Exercise Price Per Share		Weighted Average Grant Date Fair Value Per Share
Outstanding, December 31, 2018		7,549		$	2.37	$	1.68
Granted		—			—		—
Exercised		(467	)	$	0.98	$	0.68
Forfeited		(551	)	$	2.99	$	2.11
Outstanding, March 31, 2019		6,531		$	2.41	$	1.71

As of March 31, 2019, there was approximately $0.4 million of unamortized compensation expense related to outstanding stock options that will be recognized from 2019 through 2022.

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Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient of the award terminates employment with the Company prior to the lapse of the restrictions. The fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods.

The following table summarizes the Company’s restricted stock activity for the three months ended March 31, 2019:

	Number of Shares (thousands)		Weighted Average Grant Date Fair Value Per Share
Unvested, December 31, 2018		827	$	2.15
Granted		—	$	-
Vested/Released		—	$	-
Forfeited		—	$	-
Unvested, March 31, 2019		827	$	2.15

The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented:

As of March 31, 2019, there was approximately $1.1 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized from 2019 through 2021.

Performance Based Restricted Stock

The Company issues performance-based shares of restricted stock to certain officers and employees under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. The shares will vest in three years from the grant date upon the achievement of performance goals based on the Company’s Total Shareholder Return (“TSR”) as compared to a peer group of companies. The number of shares which would vest depends upon the rank of the Company’s TSR as compared to the peer group at the end of the three-year vesting period, and can range from zero percent of the initial grant up to 200% of the initial grant.

The table below provides a summary of Performance Based Restricted Stock as of the date indicated (shares in thousands):

	Number of Shares (thousands)		Weighted Average Grant Date Fair Value Per Share
Unvested, December 31, 2018		405	$	2.37
Granted		—	$	-
Vested/Released		—	$	-
Forfeited		—	$	-
Unvested, March 31, 2019		405	$	2.37

Compensation expense associated with the performance based restricted stock is based on the grant date fair value of a single share as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the performance based restricted stock awards with shares of the Company's common stock, the awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the awards.

The following table summarizes the Company’s stock-based compensation expense related to performance based restricted stock for the periods presented:

As of March 31, 2019, there was approximately $0.6 million of unamortized compensation expense relating to outstanding performance based restricted shares that will be recognized from 2019 through 2021.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with the acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated net revenue from proved reserves discounted at 10% are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accounting companies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool results in a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At March 31, 2019 and 2018, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

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Restoration, Removal and Environmental Liabilities

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component is fixed or reliably determinable.

The Company accounts for future site restoration obligations based on the guidance of ASC 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements.

The following table summarizes the Company’s future site restoration obligation transactions for the three months ended March 31, 2019 and the year ended December 31, 2018:

	March 31, 2019			December 31, 2018
Beginning future site restoration obligation	$	7,492		$	8,775
New wells placed on production and other		24			612
Deletions related to property disposals and plugging costs		(438	)		(2,270	)
Accretion expense		111			516
Revisions and other		499			(141	)
Ending future site restoration obligation	$	7,688		$	7,492

2. Revenue from Contracts with Customers

Revenue Recognition

Sales of oil, gas and natural gas liquids (“NGL”) are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGL fluctuates to remain competitive with other available oil, gas and NGL supplies in the market. The Company believes that the pricing provisions of our oil, gas and NGL contracts are customary in the industry.

Oil sales

The Company's oil sales contracts are generally structured such that it sells its oil production to a purchaser at a contractually specified delivery point at or near the wellhead. The crude oil production is priced on the delivery date based upon prevailing index prices less certain deductions related to oil quality, physical location and transportation costs incurred by the purchaser subsequent to delivery. The Company recognizes revenue when control transfers to the purchaser upon delivery at or near the wellhead at the net price received from the purchaser.

Gas and NGL Sales

Under the Company's gas processing contracts, it delivers wet gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to the Company based upon either (i) the resulting sales price of NGL and residue gas received by the midstream processing entity from third party customers or (ii) the prevailing index prices for NGL and residue gas in the month of delivery to the midstream processing entity. Gathering, processing, transportation and other expenses incurred by the midstream processing entity are typically deducted from the proceeds that the Company receives.

In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. In the Company's gas purchase contracts, the Company has concluded that it is the agent, and thus, the midstream processing entity is its customer. Accordingly, the Company recognizes revenue upon delivery to the midstream processing entity based on the net amount of the proceeds received from the midstream processing entity.

Imbalances

The Company utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at March 31, 2019 and 2018.

Disaggregation of Revenue

The Company is focused on the development of oil and natural gas properties primarily located in the following three operating regions in the United States: (i) the Permian/Delaware Basin, (ii) Rocky Mountain and (iii) South Texas. Revenue attributable to each of those regions is disaggregated in the table below.

	Three Months Ended March 31,
	2019						2018
	Oil		Gas		NGL		Oil		Gas		NGL
Operating Regions:
Permian/Delaware Basin	$	9,063	$	287	$	313	$	14,374	$	920	$	798
Rocky Mountain	$	21,800	$	954	$	740	$	19,240	$	1,127	$	1,403
South Texas	$	1,118	$	232	$	3	$	2,380	$	330	$	22

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Significant Judgments

Principal versus agent

The Company engages in various types of transactions in which midstream entities process the Company's gas and subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf, such as the Company's percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction price allocated to remaining performance obligations

A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC Topic 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under the Company's product sales contracts, the Company is entitled to payment from purchasers once its performance obligations have been satisfied upon delivery of the product, at which point payment is unconditional. The Company records invoiced amounts as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheet.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and also recorded as “Accounts receivable - Oil and gas production sales” in the accompanying condensed consolidated balance sheets. In this scenario, payment is also unconditional, as the Company has satisfied its performance obligations through delivery of the relevant product. As a result, the Company has concluded that its product sales do not give rise to contract assets or liabilities under ASU 2014-09. At March 31, 2019 and December 31, 2018, our receivables from contracts with customers were $22.7 million and $22.0 million, respectively.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGL sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the midstream purchaser and the price that will be received for the sale of the product. Additionally, to the extent actual volumes and prices of oil are unavailable for a given reporting period because of timing or information not received from third party purchasers, the expected sales volumes and prices for those barrels of oil are also estimated.

The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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3. Income Taxes

The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the tax rates and laws expected to be in effect when the differences are expected to reverse.

For the three months ended March 31, 2019 and 2018, there was no income tax benefit due to net operating loss carryforwards ("NOLs") and the Company recorded a full valuation allowance against its net deferred taxes.

At December 31, 2018, the Company had, subject to the limitation discussed below, $245.2 million of pre 2018 NOLs and $46.8 million of 2018 NOL carryforwards for U.S. tax purposes. The Company's pre-2018 NOLs will expire in varying amounts from 2023 through 2037, if not utilized; and can offset 100% of future taxable income for regular tax purposes. Any NOLs arising after January 1, 2018 can generally be carried forward indefinitely and can offset up to 80% of future taxable income for regular tax purposes. Effective January 1, 2018 the alternative minimum tax no longer applies to corporations.

The use of the Company's NOLs will be limited if there is an "ownership change" in its common stock, generally a cumulative ownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of March 31, 2019, the Company has not had an ownership change as defined by Section 382. Given historical losses, uncertainties exist as to the future utilization of the NOL. Therefore, the Company established a valuation allowance of $67.3 million for deferred tax assets at December 31, 2018.

As of March 31, 2019, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2013 through 2018 remain open to examination by the tax jurisdictions to which the Company is subject.

New tax legislation, commonly referred to as the Tax Cuts and Jobs Act (H.R. 1), was enacted on December 22, 2017. ASC740, Accounting for Income Taxes, requires companies to recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax years beginning after December 31, 2017. Since our federal deferred tax asset was fully offset by a valuation allowance, the reduction in the U.S. corporate income tax rate to 21% did not materially affect the Company's financial statements. Significant provisions may impact income taxes in future years include: the repeal of the corporate Alternative Minimum Tax, the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income for levered balance sheets, a limitation on utilization of NOLs generated after tax year 2017 to 80% of taxable income, the unlimited carryforward of NOLs generated after tax year 2017, temporary 100% expensing of certain business assets, additional limitations on certain general and administrative expenses, and changes in determining the excessive compensation limitation. Currently, the Company does not anticipate paying cash federal income taxes in the near term due to any of the legislative changes, primarily due to the availability of our NOL carryforwards. Future interpretations relating to the recently enacted U.S. federal income tax legislation which vary from our current interpretation and possible changes to state tax laws in response to the recently enacted federal legislation may have a significant effect on this projection.

4. Long-Term Debt

The following is a description of the Company’s debt as of March 31, 2019 and December 31, 2018, respectively:

	March 31, 2019			December 31, 2018
Senior secured credit facility	$	179,000		$	180,000
Real estate lien note		3,292			3,358
		182,292			183,358
Less current maturities		(270	)		(267	)
	$	182,022		$	183,091

Credit Facility

The Company has a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. As of March 31, 2019, $179.0 million was outstanding under the credit facility.

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At March 31, 2019, the Company had a borrowing base of $217.5 million. The borrowing base is determined semi-annually by the lenders based upon the Company's reserve reports, one of which must be prepared by its independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Company's proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and the Company is able to request one redetermination during any six-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or the Company must pledge additional oil and gas properties or other assets as collateral. The Company does not currently have any substantial unpledged assets and it may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause the Company to fail to be in compliance with the financial covenants described below. The Company's borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of its then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. The Company's borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the credit facility bear interest (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below, and (b) at all other times, at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the Federal Funds Rate plus 0.5%, and (z) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or (ii) if we elect, LIBOR plus, in each case, 2.5%-3.5% depending on the utilization of the borrowing base. At March 31, 2019, the interest rate on the credit facility was approximately 5.75% assuming LIBOR borrowings.

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Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is May 16, 2021. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the credit facility and is able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

Each of the Company's subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. The Company has also granted our lenders a security interest in our headquarters building.

Under the credit facility, the Company is subject to customary covenants, including certain financial covenants and reporting requirements. The Company is required to maintain a current ratio, as defined in the credit facility, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. The Company is also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 3.50 to 1.00. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income and franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the headquarters building and obligations with respect to surety bonds and derivative contracts.

At March 31, 2019, the Company was in compliance with all of these financial covenants. As of March 31, 2019, the interest coverage ratio was 8.70 to 1.00, the total debt to EBITDAX ratio was 2.34 to 1.00, and our current ratio was 1.06 to 1.00.

The credit facility contains a number of covenants that, among other things, restrict our ability to:

•

incur or guarantee additional indebtedness;

•

transfer or sell assets;

•

create liens on assets;

•

engage in transactions with affiliates other than on an “arm’s length” basis;

•

make any change in the principal nature of our business; and

•

permit a change of control.

The credit facility also contains certain additional covenants including requirements that:

•

100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and

•

if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility.

The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. As of March 31, 2019, the Company was in compliance with all of the terms of the credit facility.

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Real Estate Lien Note

The Company has a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The note was modified on June 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of $35,672. The maturity date of the note is July 20, 2023. As of March 31, 2019 and December 31, 2018 , $3.3 million and $3.4 million, respectively, were outstanding on the note.

5. Earnings per Share

The following table sets forth the computation of basic and diluted earnings per share:

	Three Months Ended March 31,
	2019			2018
	(In thousands, except per share data)
Numerator:
Net (loss) income	$	(25,455	)	$	10,779
Denominator:
Denominator for basic earnings per share – weighted-average common shares outstanding		166,041			165,133
Effect of dilutive securities:
Stock options and restricted shares		-			2,110
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares		166,041			167,243

Net (loss) income per common share - basic	$	(0.15	)	$	0.07

Net (loss) income per common share - diluted	$	(0.15	)	$	0.06

Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the period ended March 31, 2019, 1,582 of potential shares relating to stock options, unvested restricted shares and unvested performance based restricted shares were excluded from the calculation of diluted income (loss) per share since their inclusion would have been anti-dilutive due to the loss incurred in the period. For the three months ended March 31, 2018, no shares related to options, or unvested restricted shares were omitted from the calculation of diluted income per share.

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6. Hedging Program and Derivatives

The derivative contracts the Company utilizes are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. The Company's derivative contracts do not qualify for hedge accounting; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there is no policy to offset.

The following table sets forth the summary position of our derivative contracts as of March 31, 2019:

	Oil - WTI
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)
Fixed Swaps
2019 April - December		3,715	$	56.68
2020 January - December		3,023	$	55.25
2021 January - December		2,051	$	59.78

Basis Swaps
2019 April - December		4,000	$	2.98
2020 January - December		4,000	$	2.98

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

Fair Value of Derivative Contracts as of March 31, 2019
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives – current	$	294	Derivatives – current	$	10,417
Commodity price derivatives	Derivatives – long-term		2,654	Derivatives – long-term		6,837
		$	2,948		$	17,254

Fair Value of Derivative Contracts as of December 31, 2018
	Asset Derivatives			Liability Derivatives
Derivatives not designated as hedging instruments	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity price derivatives	Derivatives – current	$	9,602	Derivatives – current	$	616
Commodity price derivatives	Derivatives – long-term		10,527	Derivatives – long-term		4,434
		$	20,129		$	5,050

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7. Financial Instruments

Assets and liabilities measured at fair value are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•

Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•

Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2019 and December 31, 2018, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of March 31, 2019
Assets:
NYMEX fixed price derivative contracts	$	—	$	2,948	$	—	$	2,948
Total Assets	$	—	$	2,948	$	—	$	2,948
Liabilities:
NYMEX fixed price derivative contracts	$	—	$	9,271	$	—	$	9,271
NYMEX basis differential swaps		—		—		7,983		7,983
Total Liabilities	$	—	$	9,271	$	7,983	$	17,254

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2018
Assets:
NYMEX fixed price derivative contracts	$	—	$	18,172	$	—	$	18,172
NYMEX basis differential swap contracts		—		—		1,957		1,957
Total Assets	$	—	$	18,172	$	1,957	$	20,129

Liabilities:
NYMEX fixed price derivative contracts	$	—	$	—	$	—	$	—
NYMEX basis differential swaps		—		—		5,050		5,050
Total Liabilities	$	—	$	-	$	5,050	$	5,050

The Company’s derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of March 31, 2019 and December 31, 2018. Under fixed price swaps, the Company receives a fixed price for its production and pays a variable market price to the contract counter-party. Under a basis differential swap, if the market price is above the fixed price, the Company pays the counter-party, if the market price is below the fixed price, the counter-party pays the Company. The NYMEX-based fixed price derivative swaps and basis swaps contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of NYMEX-based fixed price swaps are based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, the Company enters the various inputs into a model and compares our results to the third party for reasonableness. The fair value of the basis differential swap instruments are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value, volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3.

The following is additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the three months ended March 31, 2019 (in thousands).

Unobservable inputs at January 1, 2019	$	(3,093	)
Changes in market value		(5,533	)
Settlements during the period		643
Unobservable inputs at March 31, 2019	$	(7,983	)

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Nonrecurring Fair Value Measurements

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As it relates to the Company, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value and the initial recognition of asset retirement obligations for which fair value is used.

The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 1.

Other Financial Instruments

The carrying amounts of the Company's cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the interest rates are market rates and this debt is considered Level 2.

8. Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheet through a Right of Use ("ROU") asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed below.

Our operating leases are reflected as operating lease ROU assets, operating lease liability - current and long-term operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement and initial direct cost incurred less any lease incentives. Lease expense for operating leases is recognized on a straight-line basis over the lease term.

Nature of Leases

We lease certain real estate, field equipment and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below.

Real Estate Leases

We rent a residence in North Dakota from a third party for living accommodations for certain field employees. Our real estate lease is non-cancelable with a term of five years. We have concluded our real estate agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.

Field Equipment

We rent compressors and coolers from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one year and continue thereafter on a month-to-month basis subject to termination by either party with thirty days' notice. These leases are considered short term and are not capitalized. We have a small number of compressor leases that are longer than twelve months. We have concluded that our compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days' notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the full cost method, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid.

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

Practical Expedients and Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component. In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. None of our current leases contain variable payments. Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

The components of our total lease expense for the three months ended March 31, 2019, the majority of which is included in lease operating expense, are as follows (in thousands):

	Three Months Ended March 31, 2019
Operating lease cost	$	117
Short-term lease expense (1)	$	463
Total lease expense	$	580

Short-term lease costs (2)	$	1,517

	(1)	Short-term lease expense represents expense related to leases with a contract term of 12 months or less.
	(2)	These short-term lease costs are related to leases with a contract term of 12 months or less which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheet.

Supplemental balance sheet information related to our operating leases is included in the table below (in thousands):

	Three Months Ended March 31, 2019
Operating lease ROU assets	$	579
Operating lease liability - current	$	371
Operating lease liabilities - long-term	$	208

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows:

	Three Months Ended March 31, 2019
Weighted Average Remaining Lease Term (in years)		2.48
Weighted Average Discount Rate		6	%

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):

	Operating Leases
Remainder of 2019	$	388
2020		98
2021		47
2022		42
2023		36
Thereafter		15
Total lease payments		626
Less imputed interest		(47	)
Total lease liability	$	579

Supplemental cash flow information related to our operating leases included in the table below (in thousands):

	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities	$	117
ROU assets added in exchange for lease obligations (since adoption)	$	687

9. Commitments and Contingencies

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At March 31, 2019, the Company was not involved in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its financial position or results of operations.

10. Subsequent Events

On April 29, 2019 the Company entered into a definitive agreement to sell its interest in certain non-operated properties located in the Williston Basin in North Dakota to an undisclosed buyer for $15.5 million plus the assumption of an estimated $5.4 million in outstanding AFEs, subject to closing adjustments. The net proceeds from the sale are expected to reduce outstanding debt.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on March 15, 2019, and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

Except as otherwise noted, all tabular amounts are in thousands, except per unit values.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2018, except for the adoption of the leasing standard which was effective January 1, 2019.

General

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in the United States. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.

Factors Affecting Our Financial Results

Our financial results depend upon many factors which significantly affect our results of operations including the following:

•

commodity prices and the effectiveness of our hedging arrangements;

•

the level of total sales volumes of oil and gas;

•

the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;

•

the level of and interest rates on borrowings; and

•

the level and success of exploration and development activity.

Commodity Prices and Hedging Arrangements. The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis.

Oil and gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL and gas prices in the future. The market price of oil and condensate, NGL and gas in 2019 will impact the amount of cash generated from operating activities, which will in turn impact our financial position.

During the three months ended March 31, 2019, the NYMEX future price for oil averaged $54.91 per Bbl as compared to $62.90 per Bbl in the same period of 2018. During the three months ended March 31, 2019, the NYMEX future spot price for gas averaged $2.87 per MMBtu compared to $2.85 per MMBtu in the same period of 2018. Prices closed on March 31, 2019 at $60.14 per Bbl of oil and $2.66 per MMBtu of gas, compared to closing on March 31, 2018 at $64.94 per Bbl of oil and $2.73 per MMBtu of gas. On May 6, 2019, prices closed at $62.25 per Bbl of oil and $2.52 per MMBtu of gas. If commodity prices decline, our revenue and cash flow from operations will also likely decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. If oil and gas prices decline, our revenues, profitability and cash flow from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income. The prices that we receive are also impacted by basis differentials, which can be significant, and are dependent on actual delivery points. Finally, low commodity prices will likely cause a reduction of our proved reserves, resulting in a reduction of the borrowing base under our credit facility.

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The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:

•

basis differentials which are dependent on actual delivery location;

•

adjustments for BTU content;

•

quality of the hydrocarbons; and

•

gathering, processing and transportation costs.

The following table sets forth our average differentials for the three months ended March 31, 2019 and 2018:

	Oil - NYMEX						Gas - NYMEX
	2019			2018			2019			2018
Average realized price (1)	$	49.00		$	59.56		$	1.28		$	2.00
Average NYMEX price		54.91			62.90			2.87			2.85
Differential	$	(5.91	)	$	(3.34	)	$	(1.59	)	$	(0.85	)

(1) Excludes the impact of derivative activities.

At March 31, 2019, our derivative contracts consisted of NYMEX-based fixed price swaps and NYMEX basis swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. Under basis swaps, we receive payment if the basis differential is greater than our swap price and pay when the differential is less than our swap price.

Our derivative contracts equate to approximately 71% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at December 31, 2018) from April 1, 2019 through December 31, 2019, 85% in 2020 and 75% in 2021. By removing a portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow. We have in the past and will in the future sustain losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts. For the three months ended March 31, 2019, we realized a loss of $29.1 million, consisting of a loss of $1.0 million on closed contracts and a loss of $28.1 million related to open contracts. For the three months ended March 31, 2018, we realized a loss of $7.9 million consisting of a loss of $3.8 million on closed contracts and a loss of $4.1 million related to open contracts. We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules.

The following table sets forth our derivative contracts at March 31, 2019:

	Oil - WTI
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)
Fixed Swaps
2019 April - December		3,715	$	56.68
2020 January - December		3,023	$	55.25
2021 January - December		2,051	$	59.78

Basis Swaps
2019 April - December		4,000	$	2.98
2020 January - December		4,000	$	2.98

At March 31, 2019, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $14.3 million.

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities. Based on the reserve information set forth in our reserve report as of December 31, 2018, our average annual estimated decline rate for our net proved developed producing reserves is 35%; 19%; 14%; 11% and 9% in 2019, 2020, 2021, 2022 and 2023, respectively, 11% in the following five years, and approximately 8% thereafter. These rates of decline are estimates and actual production declines could be materially different. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.

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We had capital expenditures during the three months ended March 31, 2019 of $29.9 million related to our exploration and development activities as well as the acquisition of leasehold. We have a capital expenditure budget for 2019 of approximately $86.0 million, of which approximately $47.0 million is allocated to acquiring additional acreage and developing our Bone Spring/Wolfcamp acres in the Permian/Delaware Basin. The 2019 budget also allocates approximately $27.0 million for developing our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to acquisitions, facilities and general corporate purposes. The 2019 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.

The following table presents historical net production volumes for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019			2018
Total production (MBoe)		979			944
Average daily production (Boepd)		10,874			10,485
% Oil		67	%		64	%

The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the three months ended March 31, 2019 and 2018, by our major operating regions:

	Three Months Ended March 31,
	2019		2018
Oil production (MBbls)
Rocky Mountain		444		331
Permian/Delaware Basin		189		236
South Texas		20		37
Total		653		604
Gas production (MMcf)
Rocky Mountain		604		525
Permian/Delaware Basin		452		519
South Texas		95		142
Total		1,151		1,186
NGL production (MBbls)
Rocky Mountain		98		95
Permian/Delaware Basin		36		46
South Texas		-		1
Total		134		142
Total production (MBoe) (1)		979		944
Average sales price per Bbl of oil (2)
Rocky Mountain	$	49.06	$	58.05
Permian/Delaware Basin		48.01		60.99
South Texas		56.99		63.83
Composite		49.00		59.56
Average sales price per Mcf of gas (2)
Rocky Mountain	$	1.58	$	2.15
Permian/Delaware Basin		0.64		1.77
South Texas		2.44		2.32
Composite		1.28		2.00
Average sales price per Bbl of NGL
Rocky Mountain	$	7.59	$	14.76
Permian/Delaware Basin		8.60		17.59
South Texas		15.42		19.06
Composite		7.87		15.70
Average sales price per Boe (2)		35.26		43.02
Average cost of production per Boe produced (3)
Rocky Mountain	$	3.92	$	4.61
Permian/Delaware Basin		15.81		3.92
South Texas		14.80		13.28
Composite		7.96		4.91

(1)

Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.

(2)

Before the impact of hedging activities.

(3)

Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

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Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. As of March 31, 2019, our borrowing base was $217.5 million with $38.5 million of availability under our credit facility.

Borrowings and Interest. At March 31, 2019, we had a total of $179.0 million outstanding under our credit facility and total indebtedness of $182.3 million (including the current portion). If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2018, we operated properties accounting for approximately 96% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility may also decline. In addition, approximately 63% of our estimated proved reserves on a Boe basis at December 31, 2018 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition could be adversely affected.

Operational Update

Delaware Basin, West Texas

In the Delaware Basin of West Texas are proceeding smoothly. The two well Creosote pad (5000-foot laterals on the Wolfcamp A-1 and A-2) has been on flowback for approximately 44 days and is currently producing approximately 1,840 barrels of oil (BO) and 3.7 MMCFPD for a total of 2,456 BOEPD (67 percent oil). The gas is currently not being sold due to extended maintenance on our third-party sour gas processing plant. Because of our “slowback” protocol, where production is constrained to conserve reservoir pressure and increase well performance, this production rate could continue to escalate over the next month or so. Abraxas owns an approximate 96 percent working interest in this two well pad.

On the Woodberry pad, in which we own a 100 percent working interest, two 5000-foot laterals in the Third Bone Spring and the Wolfcamp A-1 have been drilled and cased with frac operations scheduled to commence in June. The rig is moving to a two -well Greasewood pad, in which we own a 100 percent working interest, to drill two 5000-foot laterals. Upon completion, the rig will be released giving us time to work on production optimization on the twenty plus producing wells we have in the area.

Williston Basin, North Dakota

In North Dakota, the four well Ravin NE Pad, which is still under production restrictions due to a gas pipeline installation, has produced over 715 MBOE (73 percent oil) in its first 160 days and is currently producing approximately 900 BOEPD per well. The Company is pleased with the performance of the Ravin NE Pad as these are all child wells that have now produced an average of 75 percent of the cumulative production of the legacy parent wells on the same pad, which have been on production for over seven years. We believe this is a testimony to the advances we have incorporated over the years into our frac designs, where we are now on our fifth generation. Weather is improving and our four well Lillibridge NW pad (in which we own an approximately 33 percent working interest) is scheduled to start frac operations this week, which should allow first production in June. During the quarter, we were successful in recovering the coil tubing stuck in the Ravin 12H and are currently drilling out bridge plugs in advance of flowing the well.

Raven Rig #1 has commenced drilling operations on our six -well Jore Fed Ext pad, in which we own an approximate 75 percent working interest. Timing of first production from this pad will depend on weather, oil prices, and gas takeaway capacity.

Results of Operations

Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.

	Three Months Ended March 31,
	2019		2018
Operating revenue (1):
Oil sales	$	31,981	$	35,994
Gas sales		1,473		2,377
NGL sales		1,056		2,223
Other		4		36
Total operating revenues	$	34,514	$	40,630
Operating income	$	6,708	$	19,960
Oil sales (MBbls)		653		604
Gas sales (MMcf)		1,151		1,186
NGL sales (MBbls)		134		142
Oil equivalents (MBoe)		979		944
Average oil sales price (per Bbl)(1)	$	49.00	$	59.56
Average gas sales price (per Mcf)(1)	$	1.28	$	2.00
Average NGL sales price (per Bbl)	$	7.87	$	15.70
Average oil equivalent sales price (Boe) (1)	$	35.26	$	43.02

___________________

(1)

Revenue and average sales prices are before the impact of hedging activities.

Comparison of Three Months Ended March 31, 2019 to Three Months Ended March 31, 2018

Operating Revenue. During the three months ended March 31, 2019, operating revenue decreased to $34.5 million from $40.6 million for the same period of 2018. The decrease in revenue was due to lower prices for all products, lower sales volumes for gas and NGL partially offset by higher oil sales volumes, during the three months ended March 31, 2019 as compared to the same period of 2018. Higher oil sales volumes contributed $2.8 million to operating revenue for the three months ended March 31, 2019. Lower realized commodity prices for all products had a negative impact of $8.9 million on operating revenue.

Oil sales volumes increased to 653 MBbl during the three months ended March 31, 2019 from 604 MBbl for the same period of 2018. The increase in oil sales volume was primarily due to new wells brought on line since the first quarter of 2018, offset by natural field declines and property sales. New wells brought on line since the first quarter of 2018 contributed 380 MBbl for the three months ended March 31, 2019. Gas sales volumes decreased to 1,151 MMcf for the three months ended March 31, 2019 from 1,186 MMcf for the same period of 2018. The decrease in gas production was due to field declines and pipeline constraints partially offset by new wells brought on line since the first quarter of 2018 which contributed 358 MMcf for the three months ended March 31, 2019. NGL sales volumes decreased to 134 MBbl for the three months ended March 31, 2019 from 142 MBbl for the same period of 2018. The decrease in NGL sales corresponds to the decrease in gas sales.

Lease Operating Expenses (“LOE”). LOE for the three months ended March 31, 2019 increased to $7.7 million from $4.6 million for the same period in 2018. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since March 31, 2018 as well as significant non-recurring cost related to frac protect and repair of frac damage to wells from offset fracs. LOE per Boe for the three months ended March 31, 2019 was $7.90 compared to $4.84 for the same period of 2018. The increase per Boe was due to higher costs offset by higher sales volumes for the three months ended March 31, 2019 as compared to the same period of 2018.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended March 31, 2019 and 2018 were flat at $3.1 million for each period. Production and ad valorem taxes for the three months ended March 31, 2019 were 9% of total oil, gas and NGL sales compared to 8.0% for the same period of 2018. The increase in the percentage of total oil, gas and NGL sales was due to increased production in North Dakota which has a higher tax rate.

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General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, increased slightly to $2.4 million for the three months ended March 31, 2019 compared to $2.1 million for the same period of 2018. G&A expense per Boe, excluding stock-based compensation, was $2.41 for the quarter ended March 31, 2019 compared to $2.27 for the same period of 2018. The increase per Boe was primarily due to higher G&A expense offset by higher sales volumes.

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options' vesting period. In addition to options, restricted shares of the Company’s common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended March 31, 2019 stock-based compensation expense was $0.4 million compared to $0.6 million for the same period of 2018.

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense, excluding accretion, for the three months ended March 31, 2019 increased to $13.5 million from $10.1 million for the same period of 2018. The increase was primarily due to higher future development cost included in the December 31, 2018 reserve report, based on our current development program, as well as higher production volumes during the three months ended March 31, 2019 as compared to the same period of 2018. DD&A expense per Boe for the three months ended March 31, 2019 was $13.76 compared to $10.74 in 2018. The increase in DD&A expense per Boe was primarily due to a higher full cost pool as well as higher capital cost in relation to reserve additions.

Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of March 31, 2019, and March 31, 2018, our net capitalized costs of oil and gas properties did not exceed the cost ceiling of our estimated proved reserves.

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.

Interest Expense. Interest expense for the three months ended March 31, 2019 increased to $3.0 million compared to $1.2 million for the same period of 2018. The increase in interest expense in 2019 was due to higher levels of debt during the three months ended March 31, 2019 as compared to the same period in 2018, as well as higher interest rates in the first three months of 2019 as compared to 2018. For the three months ended March 31, 2019 the interest rate on our credit facility averaged 6% as compared to 5% for the same period of 2018.

Loss (Gain) on Derivative Contracts. Derivative gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place at period end. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of March 31, 2019, and NYMEX-based fixed price swaps, basis differential swaps and collars contracts as of March 31, 2018. The net estimated value of our commodity derivative contracts was a net liability of approximately $14.3 million as of March 31, 2019. When our derivative contract prices are higher than prevailing market prices, we incur gains and, conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the three months ended March 31, 2019, we recognized a loss on our commodity derivative contracts of $29.1 million, consisting of a loss on closed contracts of $1.0 million and a loss of $28.1 million related to open contracts. For the three months ended March 31, 2018, we recognized a loss on our commodity derivative contracts of $7.9 million, consisting of a loss of $3.8 million on closed contracts and a loss of $4.1 million related to open contracts.

Income Tax Expense. For the three months ended March 31, 2019 there was no income tax expense recognized as a result of a loss for the period. For the three months ended March 31, 2018 there was no income tax expense recognized due to our NOL carryforwards.

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Liquidity and Capital Resources

General. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following:

•

the development and exploration of existing properties, including drilling and completion costs of wells;

•

acquisition of interests in additional oil and gas properties; and

•

production and transportation facilities.

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties.

Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative contracts and if appropriate opportunities are available, the sale of debt or equity securities, although we may not be able to complete any such transactions on terms acceptable to us, if at all. Based upon current oil, gas and NGL price expectations and our commodity derivatives positions, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our revolving credit facility will provide us sufficient liquidity to fund our operations for the remainder of 2019 including our planned capital expenditures.

Working Capital (Deficit). At March 31, 2019, our current liabilities of $76.6 million exceeded our current assets of $31.9 million resulting in a working capital deficit of $44.7 million. This compares to a working capital deficit of $13.6 million at March 31, 2018. Current assets at March 31, 2019 primarily consisted of cash of $1.3 million, accounts receivable of $29.5 million, current amount of our derivative asset of $0.3 million and other current assets of $0.8 million. Current liabilities at March 31, 2019 primarily consisted of trade payables of $40.1 million, revenues due third parties of $24.3 million, current maturities of long-term debt of $0.3 million, the current amount of our derivative liability of $10.4 million and accrued expenses of $1.2 million. The working capital deficit is expected to be funded by cash flows from operations and borrowings under our credit facility.

Capital Expenditures. Capital expenditures for the three months ended March 31, 2019 and 2018 were $29.9 million and $31.4 million, respectively.

The table below sets forth the components of these capital expenditures:

	Three Months Ended March 31,
	2019		2018
	(In thousands)
Expenditure category:
Exploration/Development	$	29,935	$	16,853
Acquisitions		-		14,293
Facilities and other		40		209
Total	$	29,975	$	31,355

During the three months ended March 31, 2019 our expenditures were primarily for development of our existing properties. For the three months ended March 31, 2018, expenditures were primarily for the development of our existing properties and the acquisition of leaseholds. Capital expenditures for the three months ended December 31, 2019 include $1.8 million increase in expenditures in accounts payable and $0.08 million from the change in the asset retirement obligation accounts at March 31, 2019, resulting in net capital expenditures of $28.0 million for the period ended March 31, 2019. We anticipate making capital expenditures in 2019 of approximately $86.0 million, of which approximately $47.0 million is allocated to acquiring additional acreage and developing our Bone Spring/Wolfcamp acres in the Permian/Delaware Basin. The 2019 budget also allocates approximately $27.0 million for developing our Williston Basin/Bakken/Three Forks play in North Dakota, with the remaining amount allocated to acquisitions, facilities and general corporate purposes. The 2019 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows from operations will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field declines.

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Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Net cash provided by operating activities	$	28,195		$	32,230
Net cash used in provided by investing activities		(27,016	)		(47,958	)
Net cash provided by (used in) financing activities		(721	)		19,755
Total	$	458		$	4,027

Operating activities for the three months ended March 31, 2019 provided $28.2 million in cash compared to providing $32.2 million in the same period of 2018. Reductions in operating income offset by changes in operating assets and liabilities accounted for most of these funds. Investing activities used $27.0 million during the three months ended March 31, 2019 for the development of our existing properties and leasehold acquisition. Investing activities used $48.0 million during the three months ended March 31, 2018 for the development of our existing properties and acquisition of leasehold. Financing activities used $0.7 million for the three months ended March 31, 2019 compared to providing $19.8 million for the same period of 2018. Funds used during the three months ended March 31, 2019 were primarily due to a net reduction in borrowings under our credit facility. Funds provided during the three months ended March 31, 2018 were primarily net borrowings under our credit facility.

Future Capital Resources. Our principal sources of capital going forward are cash flows from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing derivative instruments and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all.

Cash from operating activities is dependent upon commodity prices and production volumes. Depressed commodity prices have reduced, and further decreases in commodity prices from current levels could reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced. In the future, we may continue to sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including availability of capital and the risk that no commercially productive oil and gas reservoirs will be found. If our proved reserves decline in the future, our production could also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility could also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 63% of our total estimated proved reserves on a Boe basis at December 31, 2018 were classified as undeveloped.

We have in the past, and may in the future, sell producing properties. We have also sold debt and equity securities in the past, and may sell additional debt and equity securities in the future when the opportunity presents itself.

Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements:

•

Long-term debt, and

•

Operating leases for office facilities.

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Below is a schedule of the future payments that we are obligated to make based on agreements in place as of March 31, 2019:

	Payments due in twelve month periods ending:
Contractual Obligations (In thousands)	Total		March 31, 2020		March 31, 2021-2022		March 31, 2023-2024		Thereafter
Long-term debt (1)	$	182,292	$	270	$	179,583	$	2,439	$	-
Interest on long-term debt (2)		23,304		10,450		12,709		145		-
Lease obligations (3)		579		371		128		67		13
Total	$	206,175	$	11,091	$	192,420	$	2,651	$	13

(1)

These amounts represent the balances outstanding under our credit facility and the real estate lien note. These payments assume that we will not borrow additional funds.

(2)

Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.

(3)

Lease obligations.

We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At March 31, 2019, our reserve for these obligations totaled $7.7 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.

Off-Balance Sheet Arrangements. At March 31, 2019, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At March 31, 2019, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

Long-Term Indebtedness.

Long-term debt consisted of the following:

	March 31, 2019			December 31, 2018
	(In thousands)
Credit facility	$	179,000		$	180,000
Real estate lien note		3,292			3,358
		182,292			183,358
Less current maturities		(270	)		(267	)
	$	182,022		$	183,091

Credit Facility

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At March 31, 2019, we had a borrowing base of $217.5 million. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge additional oil and gas properties or other assets as collateral. We do not currently have any substantial unpledged assets and we may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause us to fail to be in compliance with the financial covenants described below. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the credit facility bear interest at (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below, and (b) at all other times, at the greater of (x) the reference rate announced from time to time by Société Générale, (y) the Federal Funds Rate plus 0.5%, and (z) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or, (ii) if we elect, LIBOR plus, in each case, 2.5%-3.5% depending on the utilization of the borrowing base. At March 31, 2019, the interest rate on the credit facility was approximately 5.75% assuming LIBOR borrowings.

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Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is May 16, 2021. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. We have also granted our lenders a security interest in our headquarters building.

Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio, as defined in the credit facility, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. We are also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 3.50 to 1.00. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income and franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net loss, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with our headquarters building and obligations with respect to surety bonds and derivative contracts.

At March 31, 2019, we were in compliance with all of these financial covenants. As of March 31, 2019, the interest coverage ratio was 8.70 to 1.00, the total debt to EBITDAX ratio was 2.34 to 1.00, and our current ratio was 1.06 to 1.00.

The credit facility contains a number of covenants that, among other things, restrict our ability to:

•

incur or guarantee additional indebtedness;

•

transfer or sell assets;

•

create liens on assets;

•

engage in transactions with affiliates other than on an “arm’s length” basis;

•

make any change in the principal nature of our business; and

•

permit a change of control.

The credit facility also contains certain additional covenants including requirements that:

•

100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and

•

if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility.

The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. As of March 31, 2019, we were in compliance with all of the terms of our credit facility.

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Real Estate Lien Note

We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The note was modified on June 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of $35,672. The maturity date of the note is July 20, 2023. As of March 31, 2019 and December 31, 2018, $3.3 million and $3.4 million, respectively, were outstanding on the note.

Hedging Activities

Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. We have entered into commodity swaps on approximately 71% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates at December 31, 2018) from April 1 through December 31, 2019, 85% for 2020 and 75% for 2021.

By removing a portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained, and in the future, will sustain, losses on our derivative contracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts.

If the disparity between our contract prices and market prices continues, we will sustain gains or losses on our derivative contracts. While gains and losses resulting from the periodic mark to market of our open contracts do not impact our cash flow from operations, gains and losses from settlements of our closed contracts do impact our cash flow from operations.

In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than our existing derivative contracts, our future cash flow from operations would likely be materially lower.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Commodity Price Risk

As an independent oil and gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for our oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the three months ended March 31, 2019, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $3.5 million. If commodity prices decline from current levels, the impact on operating revenues and cash flow, could be much more significant. However, we do have derivative contracts in place that will mitigate the impact of low commodity prices.

Derivative Instrument Sensitivity

At March 31, 2019, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $14.3 million. The fair market value of our commodity derivative contracts is sensitive to changes in the market price for oil and gas. When our derivative contract prices are higher than prevailing market prices, we incur gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses.

Interest Rate Risk

We are subject to interest rate risk associated with borrowings under our credit facility. As of March 31, 2019, we had $179.0 million of outstanding indebtedness under our credit facility. Outstanding amounts under the credit facility bear interest at (a) at any time an event of default exists, at 3% per annum plus the amounts set forth below and (b) at all other times, the greater of (x) the reference rate announced from time to time by Société Générale, (y) the Federal Funds Rate plus 0.5%, and (z) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (i) 1.5%-2.5%, depending on the utilization of the borrowing base, or, (ii) if we elect LIBOR plus 2.5%-3.5%, depending on the utilization of the borrowing base. At March 31, 2019, the interest rate on the credit facility was approximately 5.75% assuming LIBOR borrowings. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.8 million on an annual basis, based on our outstanding indebtedness as of March 31, 2019.

Item 4. Controls and Procedures.

As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas’ “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that the disclosure controls and procedures were effective.

There were no changes in our internal controls over financial reporting during the three months ended March 31, 2019 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

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PART II

Item 1. Legal Proceedings.

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At March 31, 2019, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse impact on its financial position or results of operations.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing Abraxas. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None

Item 3. Defaults Upon Senior Securities.

None

Item 4. Mine Safety Disclosure.

Not applicable

Item 5. Other Information.

None

Item 6. Exhibits.

(a)

Exhibits


	Exhibit 31.1		Certification - Robert L.G. Watson, CEO
	Exhibit 31.2		Certification - Steven P. Harris, CFO
	Exhibit 32.1		Certification pursuant to 18 U.S.C. Section 1350 - Robert L.G. Watson, CEO
	Exhibit 32.2		Certification pursuant to 18 U.S.C. Section 1350 - Steven P. Harris, CFO

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ABRAXAS PETROLEUM CORPORATION

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date	May10, 2019	By: /s/Robert L.G. Watson
		ROBERT L.G. WATSON,
		President and
		Principal Executive Officer

Date	May 10, 2019	By: /s/Steven P. Harris
		STEVEN P. HARRIS
		Vice President and
		Principal Financial Officer

Date	May 10, 2019	By: /s/G. William Krog, Jr.
		G. WILLIAM KROG, JR.,
		Vice President and
		Principal Accounting Officer