ABRAXAS PETROLEUM CORPORATION The following is a discussion and analysis of our financial condition, results of operations, liquidity and capital resources and should be read in conjunction with our consolidated financial statements and the notes thereto, included in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto as of and for the year endedDecember 31, 2019 and the related Management's Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in our Annual Report on Form 10-K for the year endedDecember 31, 2019 filed with theSEC onJune 26, 2020 . Please see "Forward Looking Information" above.
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 endedDecember 31, 2019 , except for the adoption of Accounting Standards Update 2016-13, Financial Instruments - Credit Losses which was effectiveJanuary 1, 2020 . See "Recently Issued Accounting Standards" for more information. General
We are an independent energy company primarily engaged in the
acquisition, development and production of oil and gas in
of producing properties, principally through the development of shale or tight
oil reservoirs in areas known to be productive of oil and gas utilizing new
technologies such as modern log analysis and reservoir modeling techniques as
well as 3-D seismic surveys and horizontal drilling and stage fracturing. As a
result of these activities, we believe that we have a number of development
opportunities on our properties.
COVID-19 Overview
In the first quarter of 2020, a new strain of coronavirus ("COVID-19") emerged,
creating a global health emergency that has been classified by the World Health
Organization as a pandemic. As a result of the COVID-19 pandemic, consumer
demand for both oil and gas has decreased as a direct result of travel
restrictions placed by governments in an effort to curtail the spread of
COVID-19. In addition, in March 2020 , members of OPEC failed to agree on
production levels, which has caused an increased supply and has led to a
substantial decrease in oil prices and an increasingly volatile market. OPEC
agreed to cut global petroleum output but did not go far enough to offset the
impact of COVID-19 on demand. As a result of this decrease in demand and
increase in supply, the price of oil and gas has decreased, which has affected
the liquidity. On one hand, the Company's commodity hedges protect its cash
flows from such price decline but, on the other hand, if oil or natural gas
prices remain depressed or continue to decline the Company will be required to
record oil and gas property write-downs.
In early March 2020 , global oil and natural gas prices declined sharply, have
since been volatile, and may decline again. The Company expects ongoing oil and
gas price volatility over the short term. The full impact of the coronavirus and
the decrease in oil prices continues to evolve as of the date of this report. As
such, it is uncertain as to the full magnitude that will have on the Company.
Management is actively monitoring the global situation and the impact on the
Company's future operations, financial position and liquidity in fiscal year
2020. In response to the price volatility, the Company has taken action to
reduce general and administrative costs, we began shutting in production in
mid-March 2020 and have subsequently started restoring production in mid-June
and into the third quarter., we have also suspended our capital expenditures
indefinitely.
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 are expected to continue to be
volatile. 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 2020 will impact the amount of cash
generated from operating activities, which will in turn impact our financial
position.
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During the six months endedJune 30, 2020 , the NYMEX future price for oil averaged$37.26 per Bbl as compared to$57.20 per Bbl in the same period of 2019. During the six months endedJune 30, 2020 , the NYMEX future spot price for gas averaged$1.81 per MMBtu compared to$2.69 per MMBtu in the same period of 2019. Prices closed on six months endedJune 30, 2020 at$39.27 per Bbl of oil and$1.75 per MMBtu of gas, compared to closing onJune 30, 2019 at$58.47 per Bbl of oil and$2.31 per MMBtu of gas. OnAugust 6, 2020 prices closed at$41.95 per Bbl of oil and$2.17 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.
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 six month
periods ended
Oil - NYMEX Gas - NYMEX
2020 2019 2020 2019
Average realized price (1) $ 37.59 $ 52.04 $ 0.11 $ 0.92
Average NYMEX price 37.26 57.20 1.81 2.69
Differential $ 0.33 $ (5.16 ) $ (1.70 ) $ (1.77 ) (1) Excludes the impact of derivative activities.
AtJune 30, 2020 , our derivative contracts consisted of NYMEX-based fixed price swaps and NYMEX basis differential 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 differential 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 99% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates atJune 30, 2020 ) fromJuly 1 through December 31, 2020 , 106% in 2021, 113%. in 2022, 84% in 2023 and 104% in 2024 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 six months endedJune 30, 2020 , we realized a gain of$59.8 million , consisting of a gain of$11.2 million on closed contracts and a gain of$48.6 million related to open contracts. For the six months endedJune 30, 2019 , we realized a loss of$23.4 million consisting of a loss of$2.8 million on closed contracts and a loss of$20.6 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
Oil - WTI
Contract Periods Daily Volume (Bbl) Swap Price (per Bbl)
Fixed Swaps
2020 July - December 3,546 $ 55.06
2021 January - December 2,889 $ 57.62
2022 January - December 2,412 $ 50.60
2023 January - December 1,498 $ 50.60
2024 January - December 1,589 $ 50.60
Basis Swaps
2020 July - December 4,000 $ 2.98
At
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 ofDecember 31, 2019 , our average annual estimated decline rate for our net proved developed producing reserves is 41%; 19%; 15%; 12% and 11% in 2020, 2021, 2022, 2023 and 2024, respectively, 8% 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. In addition, the 1L Amendment limits capex to$3.0 million over any four consecutive quarters beginning with the quarter endingJune 30, 2020 . This limit is effective until the First Lien Credit Facility is paid down to$50.0 million , which will further limit our ability to replace production volumes. The decline in oil prices that occurred inMarch 2020 , due to COVID-19, has resulted in the suspension of our 2020 drilling program as well as shutting in production for some period of time. Both of these measures will impact our production volumes going forward. 27
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We had capital expenditures during the six months endedJune 30, 2020 of$6.1 million related to our exploration and development activities, net of changes in capital expenditures in accounts payable and changes in the asset retirement obligation balance. Our capital expenditure budget for 2020 has been suspended indefinitely. Management and the board of directors are also considering additional operating and overhead cost efficiencies that could be realized in connection with the 2020 budget. The amendments to our credit facilities, described in the "Liquidity and Capital Resources" section below, limit our capital expenditures to$3.0 million in any four consecutive quarters, beginning with the quarter endedJune 30, 2020 . Our capital expenditures will 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 and
six months ended
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Total production (MBoe) 156 871 773 1,850
Average daily production (Boepd) 1,718 9,572 4,247 10,219
% Oil 60 % 69 % 60 % 69 %
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 six months
ended June 30, 2020 , and 2019, by our major operating regions:
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Oil production (MBbls)
Rocky Mountain 59 321 239 766
Permian/Delaware Basin 35 280 227 469
South Texas - 17 - 36
Total 94 618 466 1,271
Gas production (MMcf)
Rocky Mountain 135 496 635 1,100
Permian/Delaware Basin 70 316 315 768
South Texas - 87 - 182
Total 205 899 950 2,050
NGL production (MBbls)
Rocky Mountain 22 71 112 168
Permian/Delaware Basin 6 32 37 69
South Texas - - - -
Total 28 103 149 237
Total production (MBoe) (1) 156 871 773 1,850
Average sales price per Bbl of
oil (2)
Rocky Mountain $ 23.69 $ 54.66 $ 35.53 $ 49.06
Permian/Delaware Basin 16.20 55.49 39.95 52.48
South Texas - 63.08 - 59.74
Composite 20.92 55.25 37.59 52.04
Average sales price per Mcf of
gas (2)
Rocky Mountain $ 0.02 $ 0.42 $ 0.12 $ 1.58
Permian/Delaware Basin 0.29 0.08 0.11 0.40
South Texas - 2.02 - 2.24
Composite 0.11 0.45 0.11 0.92
Average sales price per Bbl of
NGL
Rocky Mountain $ (0.43 ) $ 3.33 $ 0.80 $ 5.79
Permian/Delaware Basin 2.09 0.87 0.28 5
South Texas - 0.00 - 15.41
Composite 0.10 2.57 0.68 5.57
Average sales price per Boe (2)
22.92 $ 37.48
Average cost of production per
Boe produced (3)
Rocky Mountain $ 10.50 $ 6.51 $ 7.08 $ 5.02
Permian/Delaware Basin 35.52 12.28 16.26 13.87
South Texas - 18.03 16.60 18.55
Composite 18.93 9.33 10.85 8.61
(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, 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 asset sales or financing on terms acceptable to us, if at all. As ofJune 30, 2020 , our borrowing base was$102.0 million . Our credit facilities were amended inJune 2020 . The borrowing base under our First Lien Credit Facility was reduced to the then outstanding balance of$102.0 million , resulting in no additional availability. Additionally, any excess cash, as defined in the FirstLien Credit Facility, will be applied to the outstanding balance on a monthly basis, and the borrowing base will be reduced to the new outstanding balance. As a result, with the exception of$3.0 million of funds available for working capital purposes, we expect to have limited available capital. Borrowings and Interest. AtJune 30, 2020 , we had a total of$102.0 million outstanding under our First Lien Credit Facility,$104.0 million under our SecondLien Credit facility and total indebtedness of$208.8 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. Although as noted above, under the terms of the 2L Amendment, interest under the 2nd Lien Notes is now paid-in-kind. 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. AtDecember 31, 2019 , we operated properties accounting for virtually all 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. However, the amendments to our FirstLien Credit Facility and SecondLien Credit facility place severe restrictions on our future capital expenditures and we have suspended any planned drilling activity for 2020 indefinitely. 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 we will have any significant exploration and development activities in the near term or that they 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 will decline. Approximately 38% of our estimated proved reserves on a Boe basis atJune 30, 2020 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 will be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition are expected to be adversely affected. 29
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Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Operating revenue (1):
Oil sales $ 1,970 $ 34,146 $ 17,505 $ 66,127
Gas sales 22 408 108 1,881
NGL sales 3 265 100 1,321
Other (2 ) 1 6 5
Total operating revenues $ 1,993 $ 34,820 $ 17,719 $ 69,334
Operating (loss) income $ (61,474 ) $ 8,935 $ (91,255 ) $ 15,643
Oil sales (MBbls) 94 618 466 1,271
Gas sales (MMcf) 206 899 950 2,050
NGL sales (MBbls) 28 103 149 237
Oil equivalents (MBoe) 156 871 773 1,850
Average oil sales price (per
Bbl)(1) $ 20.92 $ 55.25 $ 37.59 $ 52.04
Average gas sales price (per
Mcf)(1) $ 0.11 $ 0.45 $ 0.11 $ 0.92
Average NGL sales price (per
Bbl) $ 0.10 $ 2.57 $ 0.67 $ 5.57
Average oil equivalent sales
price (Boe) (1) $ 12.76 $ 39.98 $ 22.92 $ 37.48
___________________
(1) Revenue and average sales prices are before the impact of hedging
activities.
Comparison of Three Months Ended
Operating Revenue. During the three months endedJune 30, 2020 , operating revenue decreased to$2.0 million from$34.8 million for the same period of 2019. The decrease in revenue was primarily due to lower sales volumes as well as lower commodity prices during the three months endedJune 30, 2020 as compared to the same period of 2019. Lower sales volumes were the result of our decision to shut-in a significant amount of our production in mid-March as a result of the drastic price drop in early March due predominantly to the COVID 19 pandemic as well as geopolitical issues impacting supply and demand. Lower sales volumes for all products had a negative impact of$29.0 million and lower realized commodity prices for all products had a negative impact of$3.8 million on operating revenue for the three months endedJune 30, 2020 . Oil sales volumes decreased to 94 MBbl during the three months endedJune 30, 2020 from 618 MBbl for the same period of 2019. The decrease in oil sales volume was primarily due to wells being shut in for most of the second quarter due to severely depressed prices.as discussed below. Gas sales volumes decreased to 206 MMcf for the three months endedJune 30, 2020 from 899 MMcf for the same period of 2019. Overall production of oil and gas was down, primarily as a result of the COVID-19 virus and other geopolitical issues affecting the supply and demand for oil and natural gas, and accordingly, so were the prices we received. We made the decision to begin shutting in wells in mid-March. The majority of our oil production was shut in from mid-March through mid-June, when prices had partially recovered. We began bringing wells back on production in mid-June, and had a significant amount of our oil production back on line in July. The decrease in gas production was primarily due to shut in wells as discussed above. Additionally, we have had a number of dry gas wells in westTexas shut in since approximatelyApril 2019 due to negative gas prices. Lease Operating Expenses ("LOE"). LOE for the three months endedJune 30, 2020 decreased to$3.1 million from$8.1 million for the same period of 2019. The decrease in LOE was primarily due to the disposition of our southTexas properties during the fourth quarter of 2019 and lower non-recurring LOE in 2020 as compared to 2019. Additionally, during the first half of 2020, we purchased certain production equipment that we had previously been renting and brought electrical power into most of ourWest Texas locations eliminating the need for generator rentals. We also reduced our work force inNorth Dakota inMay 2020 , and eliminated substantially all field overtime. LOE per Boe for the three months endedJune 30, 2020 was$19.56 compared to$9.26 for the same period of 2019. The increase per Boe was due primarily to our intentional reduction in sales volumes, offset by lower total costs for the three months endedJune 30, 2020 as compared to the same period of 2019. Due to management's decision to shut in substantially all production for most of the second quarter, management believes the absolute decrease in cost is more relevant than the cost per BOE. Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months endedJune 30, 2020 decreased to$0.6 million from$2.9 million for the same period of 2019. Production and ad valorem taxes for the three months endedJune 30, 2020 were 28% of total oil, gas and NGL sales as compared to 9% for the same period of 2019. The increase in the percentage of revenue is primarily due to ad valorem taxes that are not impacted by production tax rates. 30
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General and Administrative ("G&A") Expense. G&A expenses, excluding stock-based
compensation, was decreased to $1.6 million for the three months ended June 30,
2020 as compared to $2.2 million in the same period of 2019. The reduction in
total G&A expense was primarily due to a reduction in personnel in the corporate
office, as well as reductions in salaries. Officer salaries were reduced by 20%
effective March 1, 2020 , and our CEO took an additional 20% reduction in salary
effective April 1, 2020 . G&A per Boe, excluding stock-based compensation,
was $10.18 for the quarter ended June 30, 2020 compared to $2.51 for the same
period of 2019. The increase per Boe was primarily due to lower
sales volumes. Due to management's decision to shut in substantially all
production for most of the second quarter, management believes the absolute
decrease in cost is more relevant than the cost per BOE.
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 our 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 June 30, 2020 , stock-based compensation
expense was $0.4 million compared to $0.5 million for the same period of
2019. The decrease was primarily due to the cancellation, forfeiture of
restricted stock and performance based restricted stock.
Depreciation, Depletion and Amortization ("DD&A") Expense. DD&A expense,
excluding accretion of future site development, for the three months ended June
30, 2020 decreased to $2.7 million from $12.1 million for the same period of
2019. The decrease was primarily due to lower future development cost included
in the June 30, 2020 internal reserve report, as well as lower production
volumes during the three months ended June 30, 2020 as compared to the same
period of 2019. DD&A expense per Boe for the three months ended June 30,
2020 was $16.95 compared to $13.87 in the same period of 2019. The increase in
DD&A expense per Boe was primarily due to a lower full cost pool as the result
of the impairment incurred as of December 31, 2019 and June 30, 2020 .
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 June 30,
2020 our net capitalized costs of oil and gas properties exceeded the cost
ceiling of our estimated proved reserves, resulting in the recognition of an
impairment of $54.9 million for the three months ended June 30, 2020 . As
of June 30, 2019 , 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. The decline in commodity prices, due to
COVID-19, may result in our proved reserves being revised downward, requiring
further write-down of the carrying value of our oil and gas properties during the remainder of 2020.
Interest Expense. Interest expense for the three months endedJune 30, 2020 increased to$5.1 million compared to$2.8 million for the same period of 2019. The increase in interest expense in 2020 was due to higher levels of debt during the three months endedJune 30, 2020 as compared to the same period of 2019, as well as higher overall interest rates in 2020 as compared to 2019. For the three months endedJune 30, 2020 the interest rate on our first lien credit facility averaged 3.8% as compared to 5.9% for the same period of 2019. For the three months endedJune 30, 2020 the interest rate on our second lien credit facility averaged 15.8%. We anticipate higher interest rates and increased interest expense in the future as a result of the amendments to our credit facilities. Approximately$4.1 million in interest expense on our Second Lien Credit Facility was paid in kind. 31
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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 ofJune 30, 2020 , andJune 30, 2019 . The net estimated value of our commodity derivative contracts was a net asset of approximately$43.9 million as ofJune 30, 2020 . 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 endedJune 30, 2020 , we recognized a loss on our commodity derivative contracts of$15.9 million , consisting of a gain on closed contracts of$8.7 million and a loss of$24.6 million related to open contracts. For the three months endedJune 30, 2019 , we recognized a gain on our commodity derivative contracts of$5.6 million , consisting of a loss of$1.9 million on closed contracts and a gain of$7.5 million related to open contracts. Income Tax Expense. For the three months endedJune 30, 2020 andJune 30, 2019 there was no income tax expense recognized due to our NOL carryforwards. The Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act"), that was enactedMarch 27, 2020 , includes income tax provisions that allow net operating losses (NOL's) to be carried back, allows interest expense to be deducted up to a higher percentage of adjusted taxable income, and modifies tax depreciation of qualified improvement property, among other provisions. These provisions did not have a material impact on the Company.
Comparison of Six Months Ended
Operating Revenue. During the six months endedJune 30, 2020 , operating revenue decreased to$17.7 million from$69.3 million for the same period of 2019. The decrease in revenue was primarily due to lower commodity prices as well as lower sales volumes during the six months endedJune 30, 2020 as compared to the same period of 2019. Lower realized commodity prices for all products had a negative impact of$9.5 million on operating revenue, lower sales volumes for all products negatively impacted revenue by$42.1 million for the six months endedJune 30, 2020 . Oil sales volumes decreased to 466 MBbl during the six months endedJune 30, 2020 from 1,271 MBbl for the same period of 2019. Overall production of oil and gas was down, primarily as a result of the COVID-19 virus and other geopolitical issues affecting the supply and demand for oil and natural gas, and accordingly the prices we received. We made the decision to begin shutting in wells in mid-March. The majority of our oil production was shut in from mid-March through mid-June, when prices had recovered somewhat. We began bringing wells back on production in mid-June, and had a significant amount of our oil production back on line in July. The decrease in gas production was primarily due to shut in wells as discussed above. Additionally, we have had a number of dry gas wells in westTexas shut in since approximatelyApril 2019 due to negative gas prices. Lease Operating Expenses ("LOE"). LOE for the six months endedJune 30, 2020 decreased to$8.3 million from$15.8 million for the same period of 2019. The decrease in LOE was primarily due to the disposition of our southTexas properties during the fourth quarter of 2019, and lower non-recurring LOE in 2020 as compared to the same period of 2019. LOE per Boe for the six months endedJune 30, 2020 was$10.80 compared to$8.54 for the same period of 2019. The increase per Boe was due to primarily to lower sales volumes, offset by lower total costs for the six months endedJune 30, 2020 as compared to the same period of 2019. Due to management's decision to shut in substantially all production for most of the second quarter, management believes the absolute decrease in cost is more relevant than the cost per BOE. Production and Ad Valorem Taxes. Production and ad valorem taxes for the six months endedJune 30, 2020 decreased to$2.1 million from$6.0 million for the same period of 2019. Production and ad valorem taxes for the six months endedJune 30, 2020 were 11% of total oil, gas and NGL sales as compared to 9% for the same period of 2019. The increase in the percentage of revenue is due to more revenue coming fromNorth Dakota which has a higher tax rate. 32
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General and Administrative ("G&A") Expense. G&A expenses, excluding stock-based
compensation, was decreased to $3.8 million for the six months ended June 30,
2020 as compared to $4.5 million during the same period of 2019. G&A expense
per Boe, excluding stock-based compensation, was $4.93 for the quarter ended
June 30, 2020 compared to $2.45 for the same period of 2019. The increase per
Boe was primarily due to lower sales volumes. Due to management's decision to
shut in substantially all production for most of the second quarter, management
believes the absolute decrease in cost is more relevant than the cost per BOE.
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 our common stock have been granted
and are valued at the date of grant and expense is recognized over their vesting
period. For the six months ended June 30, 2020 , stock-based compensation expense
was $0.6 million compared to $0.9 million for the same period of 2019. The
decrease was primarily due to the cancellation, forfeiture of restricted stock
and performance based restricted stock.
Depreciation, Depletion and Amortization ("DD&A") Expense. DD&A expense,
excluding accretion of future site development, for the six months ended June
30, 2020 decreased to $11.8 million from $25.5 million for the same period of
2019. The decrease was primarily due to lower future development cost included
in the June 30, 2020 internal reserve report, as well as lower production
volumes during the six months ended June 30, 2020 as compared to the same period
of 2019. DD&A expense per Boe for the six months ended June 30,
2020 was $15.30 compared to $13.81 in the same period of 2019. The increase in
DD&A expense per Boe was primarily due to a lower full cost pool as the result
of the impairment incurred as of December 31, 2019 and June 30, 2020 .
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 June 30,
2020 our net capitalized costs of oil and gas properties exceeded the cost
ceiling of our estimated proved reserves, resulting in the recognition of an
impairment of $81.6 million . As of June 30, 2019 , 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. The decline in commodity prices due to
COVID-19 and geopolitical issues affecting supply and demand, may result in
our proved reserves being revised downward, requiring further write-down of the
carrying value of our oil and gas properties during the remainder of 2020.
Interest Expense. Interest expense for the six months ended June 30,
2020 increased to $9.9 million compared to $5.7 million for the same period of
2019. The increase in interest expense in 2020 was due to higher levels of debt
during the six months ended June 30, 2020 , as compared to the same period in
2019, as well as higher overall interest rates in 2020 as compared to 2019. For
the six months ended June 30, 2020 the interest rate on our First Lien Credit
Facility averaged 4.3% as compared to 6.0% for the same period of 2019. For the
six months ended June 30, 2020 the interest rate on our Second Lien Credit
Facility averaged 14.1%.We anticipate higher interest rates and increased
interest expense in the future as a result of the amendments to our credit
facilities. For the six months ended June 30, 2020 , approximately $4.1 million
of the interest paid on the Second Lien Credit Facility was paid in kind.
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 June 30, 2020 ,
and June 30, 2019 . The net estimated value of our commodity derivative contracts
was a net asset of approximately $43.9 million as of June 30, 2020 . 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 six months ended June 30,
2020 , we recognized a gain on our commodity derivative contracts
of $59.8 million , consisting of a gain on closed contracts of $11.2 million and
a gain of $48.6 million related to open contracts. For the six months ended June
30, 2019 , we recognized a loss on our commodity derivative contracts
of $23.4 million , consisting of a loss of $2.8 million on closed contracts and a
loss of $20.6 million related to open contracts.
Income Tax Expense. For the six months ended June 30, 2020 and June 30, 2019
there was no income tax expense recognized due to our NOL carryforwards. The
CARES Act, that was enacted March 27, 2020 includes income tax provisions that
allow net operating losses (NOL's) to be carried back, allows interest expense
to be deducted up to a higher percentage of adjusted taxable income, and
modifies tax depreciation of qualified improvement property, among other
provisions. These provisions did not have a material impact on the Company.
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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. In January 2019 , we announced that we had engaged Petrie Partners to
assist us in identifying and assessing our options for our Bakken properties. In
October 2019 we announced that we had broadened the engagement of Petrie
Partners to include a more thorough review of our business and strategic plans,
competitive positioning and potential alternative transactions that might
further enhance shareholder value. Petrie's expanded mandate to assess options
for Abraxas is a broad one, which might include sales of assets, merger or
acquisition transactions, additional financing alternatives or other strategic
transactions. Due to the drastic decrease in oil prices that began in early
March 2020 as a result of the OPEC price war and the COVID-19 pandemic, we have
suspended capital expenditures for 2020. Subsequently, further negotiations in
April 2020 between members of OPEC and Russia led to an agreement to reduce
production volumes in an effort to stabilize global oil prices. While prices
have recovered from the lows in March 2020 , they remain at depressed levels. If
oil prices remain at depressed levels we may incur additional impairments in
2020, which could include impairment of our proved undeveloped reserves.
Our principal sources of capital are cash flows from operations, proceeds from
the sale of properties, and if an opportunity presents itself, the sale of debt
or equity securities, although we may not be able to sell properties or complete
any financings on terms acceptable to us, if at all. We believe that our cash
flow from these sources going forward, will be adequate to fund our operations.
In June 2020 , the borrowing base on our First Lien Credit Facility was reduced
to the then outstanding balance of $102.0 million , with no further availability.
Additionally, any excess cash, as defined in the First Lien Credit Facility,
will be applied to the outstanding balance on a monthly basis, and the borrowing
base will be reduced to the new outstanding balance. We have shut in production
in mid-March resulting in future cash flows being driven by hedge settlements,
and our ability to successfully implement cost reductions and
restart production, which began in mid-June 2020 and will continue in the third
quarter of 2020.
-
Working Capital (Deficit). At June 30, 2020 , our current assets $31.4 million
exceeded our current liabilities of $25.2 million resulting in a working capital
surplus of $6.2 million . This compares to a working capital deficit
of $28.6 million at December 31, 2019 . Current assets as of June 30,
2020 primarily consisted of accounts receivable of $10.3 million , current
portion of our derivative asset of $20.1 million and other current assets
of $1.0 million . Current liabilities at June 30, 2020 primarily consisted of
trade payables of $10.2 million , revenues due third parties of $3.3 million ,
current maturities of long-term debt of $0.3 million , the current portion of our
derivative liability of $2.6 million and accrued expenses and other of
$8.7 million .
Capital Expenditures. Capital expenditures for the six months ended
The table below sets forth the components of these capital expenditures:
Six Months Ended June 30,
2020 2019
(In thousands)
Expenditure category:
Exploration/Development $ 5,969 $ 63,916
Acquisitions - -
Facilities and other 134 94
Total $ 6,103 $ 64,010
During the six months ended June 30, 2020 and 2019 our capital expenditures were
primarily for development of our existing properties. Cash basis capital
expenditures for the six months ended June 30, 2020 of $10.6 million includes
$4.5 million for a decrease in capital expenditures in accounts payable,
resulting in net accrual basis capital expenditures of $6.1 million . As
previously described our amended credit facilities limit capital expenditures to
$3.0 million for any four consecutive quarters beginning with the quarter ending
June 30, 2020 . Based on our capital expenditure limits, the Company will 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:
Six Months Ended June 30,
2020 2019
(In thousands)
Net cash provided by operating activities
(10,581 ) (46,772 )
Net cash provided by financing activities 5,089 3,206
Total $ - $ (867 )
Operating activities for the six months ended June 30, 2020 provided $5.5
million in cash compared to providing $42.7 million in the same period of 2019.
Lower net income offset by higher unrealized gains on derivatives and changes in
operating assets and liabilities accounted for most of these funds. Investing
activities used $10.6 million during the six months ended June 30, 2020
primarily for the development of our existing properties, investing activities
also included a reduction in accounts payable related to capital expenditures of
$4.5 million . Investing activities used $46.8 million during the six months
ended June 30, 2019 primarily for the development of our existing
properties. Financing activities provided $5.1 million for the six months ended
June 30, 2020 compared to providing $3.2 million for the same period of 2019.
Funds provided during the six months ended June 30, 2020 and 2019, were
primarily net proceeds from borrowings under our credit facility.
Future Capital Resources.
Our principal sources of capital going forward, for 2020 and beyond, are cash
flows from operations, proceeds from the sale of properties, monetizing of
derivative instruments and if an opportunity presents itself, the sale of debt
or equity securities, although we may not be able to complete the sale of
properties or financing on terms acceptable to us, if at all.
Cash from operating activities is dependent upon commodity prices and production
volumes. A decrease in commodity prices from current levels would likely reduce
our cash flows from operations. 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 the risk that no commercially productive oil and
gas reservoirs will be found. If our proved reserves decline in the future, our
production will also decline and, consequently, our cash flows from
operations will decline. The risk of not finding commercially productive
reservoirs will be compounded by the fact that 28% of our total estimated proved
reserves on a Boe basis at June 30, 2020 were classified as undeveloped, in
addition, under the amendments to our credit facilities, we have limited capital
available to develop these reserves. We believe that given our limited capital
expenditure for the remainder of 2020, and our hedge gains that will
mitigate the decline in commodity pricing, we have adequate liquidity for the
short term. However, should commodity prices remain at the current depressed
levels or further decline, it is uncertain that we will have the resources to
develop our undeveloped reserves, which will lead to material impairments in
2020 and going forward.
Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements:
• Long-term debt, and • Operating leases.
Below is a schedule of the future payments that we are obligated to make based
on agreements in place as of
Payments due in twelve month periods ending:
Contractual Obligations Total
$ 208,765 $ 288$ 206,432 $ 2,045 $ - Interest on long-term debt (2) 7,441 3,906 3,530 5 - Paid in kind interest on long-term debt (3) 43,583$ 16,385 $ 27,198 $ - $ - Lease obligations 332 89 94 50 99 Total$ 260,121 $ 20,668 $ 237,254 $ 2,100 $ 99 (1) These amounts represent the balances outstanding under our credit
facilities and the real estate lien note. These payments assume that we will
not borrow additional funds.
(2) Interest expense assumes the balances of our First Lien Credit Facility and
Real Estate
interest rates.
Represents interest expense paid in kind on our Second Lien Credit Facility,
(3) accrued interest is added to the outstanding balance and is payable at
maturity.
We maintain a reserve for costs associated with future site restoration related
to the retirement of tangible long-lived assets. At June 30, 2020 , our reserve
for these obligations totaled $7.6 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.
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Off-Balance Sheet Arrangements. AtJune 30, 2020 , we had no existing off-balance sheet arrangements, as defined underSEC 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
Paycheck Protection Program Loan
OnMay 4, 2020 , the Company entered into an unsecured loan with theU.S. Small Business Administration (the "SBA") in the amount of$1.4 million under the Paycheck Protection Program (the "PPP Loan") with an interest rate of 1.0% and maturity date two years from the effective date of the PPP Loan. The Paycheck Protection Program was established under the CARES Act and is administered by the SBA. Payments are required to be made in seventeen monthly installments of principal and interest, with the first payment being due on the date that is seven months after the date of the PPP Loan. Under the CARES Act, as amended by the Paycheck Protection Program Flexibility Act of 2020, the PPP Loan is eligible for forgiveness for the portion of the PPP Loan proceeds used for payroll costs and other designated operating expenses, provided at least 60% of the PPP Loan's proceeds are used for payroll costs and the Company meets all necessary criteria for forgiveness. Receipt of these funds requires the Company to, in good faith, certify that the PPP Loan was necessary to support ongoing operations of the Company during the economic uncertainty created by the COVID-19 pandemic. This certification further requires the Company to take into account current business activity and the ability to access other sources of liquidity sufficient to support ongoing operations in a manner that is not significantly detrimental to the business. Additionally, the SBA provides no assurance that the Company will obtain forgiveness of the PPP Loan in whole or in part. Long-Term Indebtedness.
Long-term debt consisted of the following:
June 30, 2020 December 31, 2019
First Lien Credit Facility $ 101,778 $ 95,778
Second Lien Credit Facility 104,034 100,000
Real estate lien note 2,952 3,091
208,764 198,869
Less current maturities (288 ) (280 )
208,476 198,589
Deferred financing fees, net (5,405 ) (5,871 )
Total long-term debt, net of deferred financing fees
192,718
First Lien Credit Facility
The Company has a senior secured First Lien Credit Facility with Société
Générale, as administrative agent and issuing lender, and certain other
lenders. As of
Outstanding amounts under the First Lien Credit Facility accrues interest at a rate per annum equal to (a)(i) for borrowings that we elect to accrue interest at the reference rate 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) daily one-month LIBOR plus, in each case, 1.5%-2.5%, depending on the utilization of the borrowing base, and (ii) for borrowings that we elect to accrue interest at the Eurodollar rate, LIBOR plus 2.5%-3.5% depending on the utilization of the borrowing base and (b) at any time an event of default exists, 3.0% plus the amounts set forth above. AtJune 30, 2020 , the interest rate on the First Lien Credit Facility was approximately 3.7%. Subject to earlier termination rights and events of default, the stated maturity date of the First Lien Credit Facility isMay 16, 2022 . Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. The Company is permitted to terminate the First Lien Credit Facility and is able, from time to time, to permanently reduce the lenders' aggregate commitment under the First Lien Credit Facility in compliance with certain notice and dollar increment requirements. Each of the Company's subsidiaries has guaranteed our obligations under the First Lien Credit Facility on a senior secured basis. Obligations under the First Lien 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. As ofMarch 31, 2020 , the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's proven reserves and 95% of the PV-9 of the Company's PDP reserves. The First Lien Credit Facility was amended onJune 25, 2020 (the "1L Amendment"). Under the First Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The 1L Amendment modified certain provisions of the First Lien Credit Facility, including (i) the addition of monthly mandatory prepayments from excess cash (defined as available cash minus certain cash set-asides and a$3.0 million working capital reserve) with corresponding reductions to the borrowing base; (ii) the elimination of scheduled redeterminations (which were previously made every six months) and interim redeterminations (which were previously made at the request of the lenders no more than once in the six month period between scheduled redeterminations) of the borrowing base; (iii) the replacement of total debt leverage ratio and minimum asset ratio covenants with a first lien debt leverage ratio covenant (comparing the outstanding debt of the First Lien Credit Facility to the consolidated EBITDAX of the Company and requiring that the ratio not exceed 2.75 to 1.00 as of the last day of each fiscal quarter) and a minimum first lien asset coverage ratio covenant (comparing the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of theCompany, (B) the PV-9 of the Company's hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as "drilled uncompleted" (up to 20% of the sum of (A), (B) and (C)) to the outstanding debt of the First Lien Credit Facility and requiring that the ratio exceed 1.15 to 1.00 as of the last day of each fiscal quarter ending on or beforeDecember 31, 2020 , and 1.25 to 1.00 for fiscal quarters ending thereafter); (iv) the elimination of current ratio and interest coverage ratio covenants; (v) additional restrictions on (A) capital expenditures (limiting capital expenditures to$3.0 million in any four fiscal quarter period (commencing with the four fiscal quarter period endedJune 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending onJune 30, 2020 ,September 30, 2020 andDecember 31, 2020 , respectively, subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt and capital expenditures made when (1) the first lien asset coverage ratio is at least 1.60 to 1.00, (2) the Company is in compliance with the first lien leverage ratio, (3) the amounts outstanding under the First Lien Credit Facility are less than$50.0 million , (4) no default exists under the FirstLien Credit Facility and (5) and all representations and warranties in the FirstLien Credit Facility and the related credit documents are true and correct in all material respects), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to$7.5 million , undisputed accounts payable outstanding for more than 60 days to$2.0 million and undisputed accounts payable outstanding for more than 90 days to$1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to$9.0 million for the four fiscal quarter period endingJune 30, 2020 ,$8.25 million for the four fiscal quarter period endingSeptember 30, 2020 ,$6.9 million for the four fiscal quarter period endingDecember 31, 2020 , and$6.5 million for the fiscal quarter fromMarch 31, 2021 throughDecember 31, 2021 and$5.0 million thereafter; in all cases, general and administrative expense excludes up to$1.0 million in certain legal and professional fees; and (vi) permission for up to an additional$25.0 million in structurally subordinated debt to finance capital expenditures. Under the 1L Amendment, the borrowing base was adjusted from$135.0 million to$102.0 million . The borrowing base will be reduced by any mandatory prepayments from excess cash flow (in an amount equal to such prepayment) and upon the disposition of the Company's oil and gas properties. 36
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As of
The First Lien 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;
• pay dividends or make other distributions on capital stock or make
other restricted payments;
• 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 First Lien 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. Second Lien Credit Facility
On
The SecondLien Credit facility was amended onJune 25, 2020 . The Second Lien Credit Facility has a maximum commitment of$100.0 million . OnNovember 13, 2019 ,$95.0 million of the net proceeds obtained from the SecondLien Credit Facility were used to permanently reduce the borrowings outstanding on the First Lien Credit Facility. As ofJune 30, 2020 , the outstanding balance on the Second Lien Credit Facility was$104.0 million . The stated maturity date of the Second Lien Credit Facility isNovember 13, 2022 . Prior to the latest amendments to the Second Lien Credit Facility, accrued interest was payable quarterly on reference rate loans and at the end of each three-month interest period on Eurodollar loans. We are permitted to prepay the loans in whole or in part, in compliance with certain notice and dollar increment requirements, and , if such prepayment is made prior toNovember 13, 2020 , subject to payment of a Make Whole Amount, where applicable. "Make Whole Amount" is defined as, the sum of the interest payments (calculated on the basis of the interest rate as of the date of the relevant prepayment without discount) that would have accrued and been paid from the date of prepayment toNovember 13, 2020 on the principal amount of such prepaid loans, whether such prepayments are optional, mandatory or as a result of acceleration. Each of our subsidiaries has guaranteed our obligations under the Second Lien Credit Facility. Obligations under the Second Lien Credit Facility are secured by a first priority perfected security interest, subject to certain permitted liens, including those securing the indebtedness under the FirstLien Credit Facility to the extent permitted by the Intercreditor Agreement, of even date with the Second Lien Credit Facility, among us, our subsidiaries,Angelo Gordon Energy Servicer, LLC and Société Générale, in all of our subsidiary guarantors' material property and assets. As ofJune 30, 2020 , the collateral is required to include properties comprising at least 90% of the PV-9 of the Company's our proven reserves and 95% of the PV-9 of the Company's PDP reserves. 37
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The Second Lien Credit Facility was amended onJune 25, 2020 (the "2L Amendment"). Under the Second Lien Credit Facility, the Company is subject to customary covenants, including financial covenants and reporting covenants. The 2L Amendment modifies certain provisions of the Second Lien Credit Facility, including (i) a requirement that, while the obligations under the First Lien Credit Facility are outstanding, scheduled payments of accrued interest under the Second Lien Credit Facility will be paid in the form of capitalized interest; (ii) an increase in the interest rate by 200bps for interest payable in cash and 500bps for interest payable in kind; (iii) modification of the minimum asset ratio covenant to be the sum of, without duplication, (A) the PV-15 of producing and developed proven reserves of theCompany, (B) the PV-9 of the Company's hydrocarbon hedge agreements and (C) the PV-15 of proved reserves of the Company classified as "drilled uncompleted" (up to 20% of the sum of (A), (B) and (C)) to the total outstanding debt of the Company and requiring that the ratio not exceed 1.45 to 1.00 as of the last day of each fiscal quarter ending betweenSeptember 30, 2021 toDecember 31, 2021 , and 1.55 to 1.00 for fiscal quarters ending thereafter); (iv) modification of the total leverage ratio covenant to set the first test date to occur onSeptember 30, 2021 ; (v) modification of the current ratio to eliminate the exclusion of certain valuation accounts associated with hedge contracts from current assets and from current liabilities, (vi) additional restrictions on (A) capital expenditures (limiting capital expenditures to those expenditures set forth in a plan of development approved byAngelo Gordon Energy Servicer, LLC , subject to certain exceptions, including capital expenditures financed with the proceeds of newly permitted, structurally subordinated debt), (B) outstanding accounts payable (limiting all outstanding and undisputed accounts payable to$7.5 million , undisputed accounts payable outstanding for more than 60 days to$2.0 million and undisputed accounts payable outstanding for more than 90 days to$1.0 million and (C) general and administrative expenses (limiting cash general and administrative expenses the Company may make or become legally obligated to make in any four fiscal quarter period to$9.0 million for the four fiscal quarter period endingJune 30, 2020 ,$8.25 million for the four fiscal quarter period endingSeptember 30, 2020 ,$6.5 million for fiscal quarter period fromMarch 31, 2021 throughDecember 31, 2021 and$5.0 million thereafter.
As of
The Second Lien 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;
• pay dividends or make other distributions on capital stock or make other
restricted payments;
• 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 Second Lien Credit Facility also contains customary events of default,
including nonpayment of principal or interest, violation of covenants, cross
default and cross acceleration to certain other indebtedness, bankruptcy and
material judgments and liabilities.
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Table of Contents Real EstateLien 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 onJune 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of$35,672 . The maturity date of the note isJuly 20, 2023 . As ofJune 30, 2020 andDecember 31, 2019 ,$3.0 million and$3.1 million , respectively, were outstanding on the note.
See Note 4 to the consolidated financial statements "Long-Term Debt" for a description of our long-term debt prior to these amendments.
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 99% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates atJune 30, 2020 ) from July throughDecember 31, 2020 , 106% for 2021 113% for 2022; 84% for 2023; and 104% for 2024. 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. 39
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