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;

 

•

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;

 

•

the proximity, capacity, cost and availability of pipelines and other transportation facilities; 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. In addition, 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.

 

 

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.

 

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

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

 

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

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)

(in thousands, except share and per share data)

 

 

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

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands except per share data)

 

 

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

 

 

ABRAXAS PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

 

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

 

 

ABRAXAS PETROLEUM CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(tabular amounts in thousands, except per share data)

 

 

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, 2017 filed with the SEC on March 16, 2018, 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, 2017.

 

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 2018 will impact the amount of cash generated from operating activities, which will in turn impact our financial position.

 

 

During the nine months ended September 30, 2018, the NYMEX future price for oil averaged $66.80 per Bbl as compared to $49.39 per Bbl in the same period of 2017. During the nine months ended September 28, 2018, the NYMEX future spot price for gas averaged $2.85 per MMBtu compared to $3.21 per MMBtu in the same period of 2017. Prices closed on September 28, 2018 at $73.25 per Bbl of oil and $3.01 per MMBtu of gas, compared to closing on September 30, 2017 at $51.67 per Bbl of oil and $3.01 per MMBtu of gas.  On November 5, 2018, prices closed at $62.21 per Bbl of oil and $3.56 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.

 

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 nine months ended September 30, 2018 and 2017:

 

		Oil - NYMEX								Gas - NYMEX
		2018				2017				2018				2017
Average realized price (1)		$	61.10			$	44.44			$	1.69			$	1.79
Average NYMEX price			66.80				49.39				2.85				3.21
Differential		$	(5.70	)		$	(4.95	)		$	(1.16	)		$	(1.42	)

_____________________________________

(1) Excludes the impact of derivative activities on oil for 2018 and for oil and gas for 2017. Gas derivative contracts expired in December 2017.

 

At September 30, 2018, 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.

 

Our derivative contracts equate to approximately 76% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at June 30, 2018) from October 2018 through December 31, 2018, 75% in 2019, 2020 and 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 nine months ended September 30, 2018, we realized a loss of $41.2 million, consisting of a loss of $16.6 million on closed contracts and a loss of $24.6 million related to open contracts. For the nine months ended September 30, 2017, we realized a gain of $10.4 million consisting of a gain of $3.4 million on closed contracts and a gain of $7.0 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 September 30, 2018:

 

		Oil - WTI
Contract Periods		Daily Volume (Bbl)				Swap Price (per Bbl)
Fixed Swaps
October - December 2018			4,477			$	53.70
January - December 2019			2,941			$	56.20
January - December 2020			2,204			$	54.35
January - December 2021			1,815			$	60.32
Basis Swaps
January - December 2019			500			$	3.00
January - December 2020			500			$	3.00

 

At September 30, 2018, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $39.6 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, 2017, our average annual estimated decline rate for our net proved developed producing reserves is 38%; 21%; 13%; 11% and 10% in 2018, 2019, 2020, 2021 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.

 

We had net capital expenditures during the nine months ended September 30, 2018 of $124.6 million related to our exploration and development activities as well as the acquisition of leasehold positions. We have a capital expenditure budget for 2018 of approximately $140.0 million to be funded by cash flows from operations and borrowings under our credit facility. The 2018 capital expenditure budget is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil and gas, the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, the availability of sufficient capital resources, the results of our exploitation efforts, and our ability to obtain permits for drilling locations.

 

The following table presents historical net production volumes for the three and nine months ended September 30, 2018 and 2017:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2018				2017				2018				2017
Total Production (Mboe)			926				805				2,615				1,889
Average daily production (Boepd)			10,070				8,745				9,579				6,920
% Oil			65	%			60	%			63	%			57	%

 

 

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 and nine months ended September 30, 2018 and 2017, by our major operating regions:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2018				2017				2018				2017
Oil Production (Bbls)
Rocky Mountain			369				339				947				789
Permian			207				123				601				210
South Texas			26				23				97				85
Total			602				485				1,645				1,084
Gas Production (Mcf)
Rocky Mountain			556				505				1,601				1,412
Permian			499				431				1,470				1,002
South Texas			122				169				411				340
Total			1,177				1,105				3,482				2,754
NGL Production (Bbl)
Rocky Mountain			86				105				265				272
Permian			40				30				120				71
South Texas			2				1				5				4
Total			128				136				390				347
Average sales price per Bbl of oil (1)
Rocky Mountain		$	64.41			$	42.98			$	61.75			$	43.35
Permian		$	55.14			$	46.13			$	59.00			$	46.86
South Texas		$	72.04			$	47.82			$	67.76			$	48.56
Composite		$	61.54			$	44.01			$	61.10			$	44.44
Average sales price per Mcf of gas (1)
Rocky Mountain		$	1.69			$	1.29			$	1.71			$	1.38
Permian		$	1.36			$	1.91			$	1.50			$	2.15
South Texas		$	2.27			$	2.36			$	2.27			$	2.40
Composite		$	1.61			$	1.70			$	1.69			$	1.79
Average sales price per Bbl of NGL
Rocky Mountain		$	20.18			$	9.79			$	16.32			$	8.59
Permian		$	22.02			$	15.00			$	19.14			$	16.37
South Texas		$	28.08			$	19.16			$	23.87			$	16.88
Composite		$	20.86			$	11.03			$	17.27			$	10.27
Average cost of production per Boe produced (2)
Rocky Mountain		$	6.99			$	4.15			$	6.35			$	4.75
Permian		$	6.13			$	5.08			$	5.48			$	7.15
South Texas		$	19.17			$	15.53			$	15.19			$	17.30
Composite		$	7.31			$	5.15			$	6.61			$	6.29

 

(1)

Before the impact of oil hedging activities in 2018 and oil and gas hedging activities in 2017. There were no gas hedges in 2018.

(2)

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

 

 

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.  In January 2017, we completed a stock offering of 28.8 million shares of common stock for net proceeds of approximately $65.2 million. The net proceeds from this offering were used to repay borrowings under our credit facility. As of September 30, 2018, the borrowing base under our credit facility was $200.0 million with $54.0 million of availability under our credit facility.

 

Borrowings and Interest.  At September 30, 2018, we had a total of $146.0 million outstanding under our credit facility and total indebtedness of $149.4 million (including the current portion). Our interest expense increases as a result of increased borrowings and increased interest rates.  Borrowings at September 30, 2018 were $82.0 million higher than at September 30, 2017.  The average interest rate under our credit facility for the nine months ended September 30, 2018 was 5.3%, as compared to 3.9% for the same period of 2017.  If interest expense continues to increase as a result of higher interest rates and/or borrowings increase, more cash flow from operations will be used to meet debt service requirements.  If this trend continues, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities and pay our increased interest expense 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, 2017, 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 67% of our estimated proved reserves on a Boe basis at December 31, 2017 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

 

 

Williston Basin, North Dakota

 

Drilling operations on the Abraxas four well Lillibridge NW Pad continued as planned. On the four well Ravin NE Pad, the fracture treatment (frac) is expected to be completed this week despite road closures caused by weather. Once the Ravin NE Pad fracture treatment is complete, Abraxas will place back on production the six remaining wells shut-in for frac protection along with the eight new wells on the Ravin Central and Ravin NE Pad's.

 

Delaware Basin, West Texas

 

Drilling operations on the Abraxas two well Creosote Pad continued as planned. Abraxas owns approximately 80% working interest in the Creosote Pad. The two well Mesquite Pad, in which Abraxas owns 73% working interest, is producing approximately 1,800 Boepd. The fracture treatment on the one well Pecan 47 Pad, in which Abraxas owns 100% working interest is scheduled to commence this week. All these pads call for 4,800' laterals.

 

 

Results of Operations

 

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2018				2017				2018				2017
Operating revenue (1):
Oil sales		$	37,039			$	21,339			$	100,505			$	48,153
Gas sales			1,897				1,873				5,882				4,918
NGL sales			2,677				1,495				6,735				3,559
Other			12				15				49				46
Total operating revenues		$	41,625			$	24,722			$	113,171			$	56,676
Operating income		$	17,735			$	5,654			$	48,756			$	11,867
Oil sales (MBbls)			602				485				1,645				1,084
Gas sales (MMcf)			1,177				1,105				3,482				2,754
NGL sales (MBbls)			128				136				390				347
Oil equivalents (Mboe)			926				805				2,615				1,889
Average oil sale price (per Bbl)(1)		$	61.54			$	44.01			$	61.10			$	44.44
Average gas sales price (per Mcf)(1)		$	1.61			$	1.70			$	1.69			$	1.79
Average NGL price (per Bbl)		$	20.86			$	11.03			$	17.27			$	10.27
Average oil equivalent sales price (Boe)(1)		$	44.92			$	30.71			$	43.26			$	29.98

 

___________________

(1)

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

 

Comparison of Three Months Ended September 30, 2018 to Three Months Ended September 30, 2017

 

Operating Revenue. During the three months ended September 30, 2018, operating revenue increased to $41.6 million from $24.7 million for the same period of 2017. The increase in revenue was due to higher sales volumes for oil and gas and higher oil and NGL prices during the three months ended September 30, 2018 as compared to the same period of 2017. Higher sales volumes contributed $5.1 million to operating revenue for the three months ended September 30, 2018. Higher realized commodity prices contributed $11.8 million to operating revenue, of which $10.6 million was attributable to oil. 

 

Oil sales volumes increased to 602 MBbl during the three months ended September 30, 2018 from 485 MBbl for the same period of 2017. The increase in oil sales volume was primarily due to new wells brought on line since the third quarter of 2017, offset by natural field declines and property sales. New wells brought on line since the third quarter of 2017 contributed 399 MBbl for the three months ended September 30, 2018. Gas sales volumes increased to 1,177 MMcf for the three months ended September 30, 2018 from 1,105 MMcf for the same period of 2017. The increase in gas production was due to new wells brought on line since the third quarter of 2017 which contributed 392 MMcf for the three months ended September 30, 2018. NGL sales volumes decreased to 128 MBbl for the three months ended September 30, 2018 from 136 MBbl for the same period of 2017. The decrease in NGL sales was primarily due to shut in wells in the Rocky Mountain and Permian regions for frac protect and take away issues.

 

Lease Operating Expenses (“LOE”). LOE for the three months ended September 30, 2018 increased to $6.7 million from $4.1 million for the same period in 2017. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since September 30, 2017 as well as higher cost incurred repairing wells damaged by frac hits from offset wells.  LOE per Boe for the three months ended September 30, 2018 was $7.26 compared to $5.08 for the same period of 2017. The increase per Boe was due to higher costs offset by higher sales volumes for the three months ended September 30, 2018 as compared to the same period of 2017.

 

 

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended September 30, 2018 increased to $3.6 million from $2.0 million for the same period in 2017. The increase was primarily due to higher commodity prices and production volumes. Production and ad valorem taxes for the three months ended September 30, 2018 were 9%  compared to 8% for the same period of 2017 of total oil, gas and NGL sales. The increase in the percentage of taxes of total oil, gas and NGL sales was due to higher production in North Dakota which has a higher tax rate than other states in which we operate.

 

General and Administrative (“G&A”) Expense. G&A expense, excluding stock-based compensation, decreased to $2.2 million for the three months ended September 30, 2018 compared to $4.3 million for the same period of 2017. The decrease was primarily due to one-time discretionary bonuses paid in the third quarter of 2017.   G&A expense per Boe, excluding stock-based compensation, was $2.33 for the quarter ended September 30, 2018 compared to $5.35 for the same period of 2017. The decrease per Boe was primarily due to lower costs and 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 September 30, 2018 stock-based compensation expense was $0.4 million compared to $0.8 million for the same period of 2017. The decrease in stock-based compensation was primarily due to the forfeiture of restricted stock and option awards relating to resignations of certain officers.

 

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense for the three months ended September 30, 2018 increased to $11.0 million from $7.9  million for the same period of 2017. The increase was primarily due to increased production for the three months ended September 30, 2018 as compared to the same period of 2017 as well as increased future development costs included in our internally prepared June 30, 2018 reserve report, and an increase in the full cost pool due to acquisitions and capital expenditures. DD&A expense per Boe for the three months ended September 30, 2018 was $11.89 compared to $9.79 in 2017. The increase was primarily the result of higher future development costs.

 

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,  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 September 30, 2018, and September 30, 2017, 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 September 30, 2018 increased to $2.1 million compared to $0.9 million for the same period of 2017. The increase in interest expense in 2018 was due to higher levels of debt during the three months ended September 30, 2018 as compared to the same period in 2017 as well as higher interest rates in 2018 as compared to 2017. The average interest rate during the three months ended September 30, 2018 was 5.6% compared to 4.4% during the same period of 2017.

 

 

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. 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 September 30, 2018, and NYMEX-based fixed price swaps, basis differential swaps and collar contracts as of September 30, 2017. The net estimated value of our commodity derivative contracts was a net liability of approximately $39.6 million as of September 30, 2018. 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 September 30, 2018, we recognized a loss on our commodity derivative contracts of $13.6 million, consisting of a loss on closed contracts of $6.7 million and a loss of $6.9 million related to open contracts. For the three months ended September 30, 2017, we recognized a loss on our commodity derivative contracts of $5.5 million, consisting of a gain of $1.4 million on closed contracts and a loss of $6.9 million related to open contracts.

 

Income Tax Expense. For the three months ended September 30, 2018 and 2017 there was no income tax expense recognized as a result of a loss for the period and our NOL carryforwards.

 

Comparison of Nine Months Ended September 30, 2018 to Nine Months Ended September 30, 2017

 

Operating Revenue. During the nine months ended September 30, 2018, operating revenue increased to $113.2 million from $56.7 million for the same period of 2017. The increase in revenue was due to higher sales volumes for all products and higher oil and NGL prices during the nine months ended September 30, 2018 as compared to the same period of 2017. Higher sales volumes contributed $26.9 million to operating revenue for the nine months ended September 30, 2018. Higher realized commodity prices for oil and NGL contributed $29.6 million to operating revenue of which $27.4 million was attributable to oil.

 

Oil sales volumes increased to 1,645 MBbl during the nine months ended September 30, 2018 from 1,084 MBbl for the same period of 2017. The increase in oil sales volume was primarily due to new wells brought on line since the third quarter of 2017, offset by natural field declines and property sales. New wells brought on line since the third quarter of 2017 contributed 570 MBbl for the nine months ended September 30, 2018. Gas sales volumes increased to 3,482  MMcf for the nine months ended September 30, 2018 from 2,754  MMcf for the same period of 2017. The increase in gas production was due to new wells brought on line since the third quarter of 2017 which contributed 565 MMcf for the nine months ended September 30, 2018. NGL sales volumes increased to 390 MBbl for the nine months ended September 30, 2018 from 347  MBbl for the same period of 2017. The increase in NGL sales was primarily due to more gas production in the Permian Basin and Rocky Mountain regions which have a high NGL content.

 

Lease Operating Expenses (“LOE”). LOE for the nine months ended September 30, 2018 increased to $17.0 million from $11.6 million for the same period in 2017. The increase in LOE was primarily due to higher cost of services and new wells brought onto production since September 30, 2017 as well as non-recurring costs related to repair from frac hits. LOE per Boe for the nine months ended September 30, 2018 was $6.51 compared to $6.16 for the same period of 2017. The increase per Boe was due to higher costs offset by higher sales volumes for the nine months ended September 30, 2018 as compared to the same period of 2017.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes for the nine months ended September 30, 2018 increased to $9.2 million from $4.8 million for the same period in 2017. The increase was primarily due to higher commodity prices and production volumes. Production and ad valorem taxes for the nine months ended September 30, 2018 were 8% of total oil, gas and NGL sales compared to 9% for the same period of 2017. The decrease in the percentage of taxes of total oil, gas and NGL sales was due to increased production in Texas which has a lower tax rate than in other states in which we operate. 

 

General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, decreased to $6.5 million for the nine months ended September 30, 2018 compared to $8.2 million for the same period of 2017. The decrease was primarily due to one-time discretionary bonuses paid in the third quarter of 2017.  G&A expense per Boe, excluding stock-based compensation, was $2.48 for the quarter ended September 30, 2018 compared to $4.34 for the same period of 2017. The decrease per Boe was primarily due to lower G&A expense and 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 nine months ended September 30, 2018 stock-based compensation expense was $1.9 million compared to $2.5 million for the same period of 2017. The decrease was primarily due to the forfeiture of stock awards due to the resignation of certain officers during 2018.

 

 

Depreciation, Depletion and Amortization (“DD&A”) Expense. DD&A expense for the nine months ended September 30, 2018 increased to $29.8 million from $17.7 million for the same period of 2017. The increase was primarily due to increased production for the nine months ended September 30, 2018 as compared to the same period of 2017 as well as increased future development costs included in our internally prepared June 30, 2018 reserve report, and an increase in the full cost pool due to acquisitions and capital expenditures. DD&A expense per Boe for the nine months ended September 30, 2018 was $11.41 compared to $9.35 in 2017. The increase was primarily the result of higher future development costs.

 

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 September 30, 2018, and September 30, 2017, 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 nine months ended September 30, 2018 increased to $5.0 million compared to $1.9 million for the same period of 2017. The increase in interest expense in 2018 was due to higher levels of debt during the nine months ended September 30, 2018 as compared to the same period in 2017 as well as higher interest rates in 2018 as compared to 2017. The average interest rate during the nine months ended September 30, 2018 was 5.3% compared to 3.9% 

 

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. 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 September 30, 2018, and NYMEX-based fixed price swaps, basis differential swaps and collar contracts as of September 30, 2017. The net estimated value of our commodity derivative contracts was a net liability of approximately $39.6 million as of September 30, 2018. 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 nine months ended September 30, 2018, we recognized a loss on our commodity derivative contracts of $41.2 million, consisting of a loss on closed contracts of $16.6 million and a loss of $24.6 million related to open contracts. For the nine months ended September 30, 2017, we recognized a gain on our commodity derivative contracts of $10.4 million, consisting of a gain of $3.4 million on closed contracts and a gain of $7.0 million related to open contracts.

 

 

Income Tax Expense. For the nine months ended September 30, 2018 and 2017 there was no income tax expense recognized as a result of our NOL carryforwards.

 

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,  including our planned capital expenditures, for the remainder of 2018 and for one year from the date the financial statements are issued.

 

Capital Expenditures. Capital expenditures for the nine months ended September 30, 2018 and 2017 were $127.7 million and $91.4 million, respectively, excluding dispositions.

 

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

 

		Nine Months Ended September 30,
		2018				2017
		(In thousands)
Expenditure category:
Exploration/Development		$	90,274			$	90,985
Acquisitions			36,404				-
Facilities and other			1,052				378
Total		$	127,730			$	91,363

 

During the nine months ended September 30, 2018 and 2017, our expenditures were primarily for development of our existing properties and the acquisition of leasehold positions. Expenditures during the nine months ended September 30, 2018 of $127.7 million, $124.6 net of proceeds from property sales of $3.1 million, included approximately $36.4 million for the acquisition of mineral acres in the Permian Basin region. Our capital expenditure budget for 2018 is approximately $140.0 million to be funded by cash flows from operations and borrowings under our credit facility. The 2018 capital expenditure budget is subject to change depending upon a number of factors, including the availability of sufficient capital resources including under our credit facility, 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 results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations. 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 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.

 

 

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:

 

 

		Nine Months Ended September 30,
		2018				2017
		(In thousands)
Net cash provided by operating activities		$	66,704			$	22,259
Net cash used in investing activities			(129,847	)			(56,216	)
Net cash provided by financing activities			61,525				34,776
		$	(1,618	)		$	819

 

Operating activities for the nine months ended September 30, 2018 provided $66.7 million in cash compared to providing $22.3 million in the same period of 2017. Operating income, excluding the impact of derivative losses, and net changes in operating assets and liabilities accounted for most of these funds. Investing activities used $129.8 million during the nine months ended September 30, 2018 for the development of our existing properties and leasehold acquisitions. Cash expenditures for the nine months ended September 30, 2018 included a decrease  in the accounts payable balance related to capital expenditures of $3.8 million, and a decrease in our asset retirement obligation liability of $1.4 million, resulting in actual capital expenditures , net of dispositions, incurred during the period of $124.6  million. Investing activities used $56.2 million during the nine months ended September 30, 2017, as capital expenditures of $71.5 million were offset by proceeds from property sales of $15.3 million. Cash expenditures of $71.5 million for the nine months ended September 30, 2017, exclude an increase in accounts payable of $16.5 million and $3.3 million attributable to properties acquired by issuance of common stock, resulting in actual  capital expenditures, net of dispositions, of   $91.4 million for the nine months ended September 30, 2017. Financing activities provided $61.5 million for the nine months ended September 30, 2018 compared to $34.8 million for the same period of 2017. Funds provided during the nine months ended September 30, 2018 were primarily borrowings under our credit facility, offset by payments of borrowings under our credit facility. Funds provided during the nine months ended September 30, 2017 were primarily proceeds from the issuance of common stock in January 2017 and borrowings under our credit facility, offset by payments of 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 and further decreases in commodity prices 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 will 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 67% of our total estimated proved reserves on a Boe basis at December 31, 2017 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.

 

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of September 30, 2018:

 

		Payments due in the twelve month periods ended:
Contractual Obligations (In thousands)		Total				September 30,  2019				September 30, 2020-2021				September 30, 2022-2023				Thereafter
Long-term debt (1)		$	149,423			$	264			$	146,568			$	2,591			$	-
Interest on long-term debt (2)			21,220				7,756				13,257				207				-
Lease obligations (3)			2				2				-				-				-
Total		$	170,645			$	8,022			$	159,825			$	2,798			$	-

___________________________

(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 on office space in Dickinson, North Dakota, which expires on October 31, 2018.

 

We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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:

 

		September 30, 2018				December 31, 2017
		(In thousands)
Senior secured credit facility		$	146,000			$	84,000
Real estate lien note			3,423				3,616
			149,423				87,616
Less current maturities			(264	)			(262	)
		$	149,159			$	87,354

 

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 September 30, 2018, $146.0 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 September 30, 2018, the Company had a borrowing base of $200.0 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 September 30, 2018, the interest rate on the credit facility was approximately 5.2% assuming LIBOR borrowings.

 

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 the Company and its subsidiary guarantors’ material property and assets. The collateral is required to include properties comprising at least 90% of the PV-10 of the Company's proven reserves. The Company has also granted its 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, 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 September 30, 2018, the Company was in compliance with all of these financial covenants. As of September 30, 2018, as defined in the credit agreement, the interest coverage ratio was 14.6 to 1.00, the total debt to EBITDAX ratio was 1.79 to 1.00, and our current ratio was 1.37 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 September 30, 2018, we were in compliance with all of the terms of our credit facility.

 

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 September 30, 2018, and December 31, 2017, $3.4 million and $3.6 million, respectively was 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 76% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates at June 30, 2018) from October 1, 2018 through December 31, 2018, 75% for 2019 and 75% for 2020.

 

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.

 

 

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 nine months ended September 30, 2018, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $11.3 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 September 30, 2018, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately $39.6 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 September 30, 2018, we had $146.0 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 September 30, 2018, the interest rate on the credit facility was approximately 5.2% assuming LIBOR borrowings. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.5 million on an annual basis, based on our outstanding indebtedness as of September 30, 2018.

 

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 nine months ended September 30, 2018 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

 

 

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 September 30, 2018, 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, 2017, 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

 

 

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	November 9, 2018		By: /s/Robert L.G. Watson
			ROBERT L.G. WATSON,
			President and Principal Executive Officer

 

 

Date	November 9, 2018		By: /s/Steven P. Harris
			STEVEN P. HARRIS
			Vice President and Principal Financial Officer

 

 

Date	November 9, 2018		By: /s/G. William Krog, Jr.
			G. WILLIAM KROG, JR.,
			Vice President and Principal Accounting Officer

 

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