Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 there to as of and for the year ended December 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 ended December 31, 2019 filed with the SEC on June 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 ended December 31, 2019, except for the adoption of Accounting Standards Update 2016-13, Financial Instruments - Credit Losses which was effective January 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 the United States. Historically, we have grown through the acquisition and subsequent development 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:
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•
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commodity prices and the effectiveness of our hedging arrangements;
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•
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the level of total sales volumes of oil and gas;
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•
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the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
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•
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the level of and interest rates on borrowings; and
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•
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the level and success of exploration and development activity.
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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.
During the three months ended March 31, 2020, the NYMEX future price for oil averaged $46.29 per Bbl as compared to $54.91 per Bbl in the same period of 2019. During the three months ended March 31, 2020, the NYMEX future spot price for gas averaged $1.87 per MMBtu compared to $2.87 per MMBtu in the same period of 2019. Prices closed on three months ended March 31, 2020 at $20.48 per Bbl of oil and $1.64 per MMBtu of gas, compared to closing on March 31, 2019 at $60.14 per Bbl of oil and $2.66 per MMBtu of gas. On June 22, 2020 prices closed at $40.73 per Bbl of oil and $1.66 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:
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•
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basis differentials which are dependent on actual delivery location;
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•
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adjustments for BTU content;
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•
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quality of the hydrocarbons; and
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•
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gathering, processing and transportation costs.
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The following table sets forth our average differentials for the three months ended March 31, 2020, and 2019:
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Oil - NYMEX
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Gas - NYMEX
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2020
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|
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2019
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|
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2020
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|
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2019
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Average realized price (1)
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$
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41.82
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|
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$
|
49.00
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|
|
$
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0.11
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|
|
$
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1.28
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Average NYMEX price
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|
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46.29
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|
|
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54.91
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|
|
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1.87
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|
|
|
2.87
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Differential
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$
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(4.47
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)
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$
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(5.91
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)
|
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$
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(1.76
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)
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$
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(1.59
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)
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(1) Excludes the impact of derivative activities.
At March 31, 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 124% of the estimated oil production from our net proved developed producing reserves (based on reserve estimates at March 31, 2020) from April 1 through December 31, 2020, 91% in 2021, 97%. in 2022, 73% in 2023 and 89% 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 three months ended March 31, 2020, we realized a gain of $75.7 million, consisting of a gain of $2.5 million on closed contracts and a gain of $73.2 million related to open contracts. For the three months ended March 31, 2019, we realized a loss of $29.1 million consisting of a loss of $1.0 million on closed contracts and a loss of $28.1 million related to open contracts. We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules.
The following table sets forth our derivative contracts at March 31, 2020:
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Oil - WTI
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Contract Periods
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Daily Volume (Bbl)
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Swap Price (per Bbl)
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Fixed Swaps
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|
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2020 April - December
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3,729
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$
|
55.10
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2021 January - December
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2,889
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|
|
$
|
57.62
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2022 January - December
|
|
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2,412
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|
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$
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50.60
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2023 January - December
|
|
|
1,498
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$
|
50.60
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2024 January - December
|
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1,589
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|
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$
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50.60
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|
|
|
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|
|
|
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Basis Swaps
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|
|
|
|
|
|
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2020 April - December
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4,000
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$
|
2.98
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|
|
|
|
|
|
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At March 31, 2020, the aggregate fair market value of our commodity derivative contracts was a net asset of approximately $70.0 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, 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 for the next 12 months, which will further limit our ability to replace production volumes The decline in oil prices that occurred in March 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.
We had capital expenditures during the three months ended March 31, 2020 of $4.6 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 operating and overhead cost efficiencies that could be realized in connection with the 2020 capital budget. The amendments to our credit faclities 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 ended June 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 months ended March 31, 2020, and 2019:
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|
Three Months Ended March 31,
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2020
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|
|
2019
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Total production (MBoe)
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|
617
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|
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|
979
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|
Average daily production (Boepd)
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6,776
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10,874
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% Oil
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60
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%
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67
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%
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The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and the average cost of production per Boe of production sold, for the three months ended March 31, 2020, and 2019, by our major operating regions:
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Three Months Ended March 31,
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2020
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2019
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Oil production (MBbls)
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|
|
|
|
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Rocky Mountain
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179
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|
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444
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|
Permian/Delaware Basin
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192
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|
|
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189
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South Texas
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|
|
-
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|
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|
20
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Total
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371
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|
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|
653
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Gas production (MMcf)
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|
|
|
|
|
|
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|
Rocky Mountain
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|
|
499
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|
|
|
604
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|
Permian/Delaware Basin
|
|
|
245
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|
|
|
452
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|
South Texas
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|
|
-
|
|
|
|
95
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|
Total
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|
|
744
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|
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|
1,151
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NGL production (MBbls)
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|
|
|
|
|
|
|
|
Rocky Mountain
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|
|
90
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|
|
|
98
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|
Permian/Delaware Basin
|
|
|
31
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|
|
|
36
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South Texas
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|
|
-
|
|
|
|
-
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Total
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121
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|
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|
134
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Total production (MBoe) (1)
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|
|
617
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|
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|
979
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|
Average sales price per Bbl of oil (2)
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|
|
|
|
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Rocky Mountain
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|
$
|
39.20
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|
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$
|
49.06
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Permian/Delaware Basin
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|
|
44.26
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|
|
|
48.01
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|
South Texas
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|
|
-
|
|
|
|
56.99
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|
Composite
|
|
|
41.82
|
|
|
|
49.00
|
|
Average sales price per Mcf of gas (2)
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|
|
|
|
|
|
|
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Rocky Mountain
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|
$
|
0.14
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|
|
$
|
1.58
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|
Permian/Delaware Basin
|
|
|
0.06
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|
|
|
0.64
|
|
South Texas
|
|
|
-
|
|
|
|
2.44
|
|
Composite
|
|
|
0.11
|
|
|
|
1.28
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|
Average sales price per Bbl of NGL
|
|
|
|
|
|
|
|
|
Rocky Mountain
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|
$
|
1.10
|
|
|
$
|
7.59
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|
Permian/Delaware Basin
|
|
|
0.06
|
|
|
|
8.60
|
|
South Texas
|
|
|
-
|
|
|
|
15.42
|
|
Composite
|
|
|
0.80
|
|
|
|
7.87
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|
Average sales price per Boe (2)
|
|
$
|
25.49
|
|
|
$
|
35.26
|
|
Average cost of production per Boe produced (3)
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
$
|
6.06
|
|
|
$
|
3.92
|
|
Permian/Delaware Basin
|
|
|
12.42
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|
|
|
15.81
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|
South Texas
|
|
|
9
|
|
|
|
14.80
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|
Composite
|
|
|
6.29
|
|
|
|
7.96
|
|
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(1)
|
Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.
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(2)
|
Before the impact of hedging activities.
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(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 of March 31, 2020, our borrowing base was $135.0 million with $33.0 million of availability under our credit facility. Our credit facilities were amended in June 2020 as described in Note 10 to the unaudited condensed consolidated financial statements included in this Quarterly Report. 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 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. 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. At March 31, 2020, we had a total of $102.0 million outstanding under our First Lien Credit Facility, $100.0 million under our Second Lien Credit facility and total indebtedness of $204.8 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. At December 31, 2019, 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. However, the amendments to our First Lien Credit Facility and Second Lien Credit facility, as described in Note 10 to our unaudited condensed consolidated financial statements 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 28% of our estimated proved reserves on a Boe basis at March 31, 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.
Results of Operations
Selected Operating Data. The following table sets forth operating data from continuing operations for the periods presented.
|
|
Three Months Ended March 31,
|
|
|
|
2020
|
|
|
2019
|
|
Operating revenue (1):
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
15,535
|
|
|
$
|
31,981
|
|
Gas sales
|
|
|
86
|
|
|
|
1,473
|
|
NGL sales
|
|
|
97
|
|
|
|
1,056
|
|
Other
|
|
|
8
|
|
|
|
4
|
|
Total operating revenues
|
|
$
|
15,726
|
|
|
$
|
34,514
|
|
Operating (loss) income
|
|
$
|
(29,781
|
)
|
|
$
|
6,708
|
|
Oil sales (MBbls)
|
|
|
371
|
|
|
|
653
|
|
Gas sales (MMcf)
|
|
|
744
|
|
|
|
1,151
|
|
NGL sales (MBbls)
|
|
|
121
|
|
|
|
134
|
|
Oil equivalents (MBoe)
|
|
|
617
|
|
|
|
979
|
|
Average oil sales price (per Bbl)(1)
|
|
$
|
41.82
|
|
|
$
|
49.00
|
|
Average gas sales price (per Mcf)(1)
|
|
$
|
0.11
|
|
|
$
|
1.28
|
|
Average NGL sales price (per Bbl)
|
|
$
|
0.80
|
|
|
$
|
7.87
|
|
Average oil equivalent sales price (Boe) (1)
|
|
$
|
25.49
|
|
|
$
|
35.26
|
|
___________________
|
(1)
|
Revenue and average sales prices are before the impact of hedging activities.
|
Comparison of Three Months Ended March 31, 2020 to Three Months Ended March 31, 2019
Operating Revenue. During the three months ended March 31, 2020, operating revenue decreased to $15.7 million from $34.5 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 three months ended March 31, 2020 as compared to the same period of 2019. Lower realized commodity prices for all products had a negative impact of $5.0 million on operating revenue, lower sales volumes for all products negatively impacted revenue by $13.9 million for the three months ended March 31, 2020.
Oil sales volumes decreased to 371 MBbl during the three months ended March 31, 2020 from 653 MBbl for the same period of 2019. The decrease in oil sales volume was primarily due to wells being shut in for frac protect, natural field declines and property sales, offset by new wells brought on line since the first quarter of 2019. New wells brought on line since the first quarter of 2019 contributed 114 MBbl for the three months ended March 31, 2020. Gas sales volumes decreased to 744 MMcf for the three months ended March 31, 2020 from 1,151 MMcf for the same period of 2019. The decrease in gas production was primarily due to field declines and continued pipeline constraints in West Texas and North Dakota, additionally, we have shut in a number of dry gas wells in west Texas due to negative gas prices, partially offset by new wells brought on line since the first quarter of 2019 which contributed 147 MMcf for the three months ended March 31, 2020. NGL sales volumes decreased to 121 MBbl for the three months ended March 31, 2020 from 134 MBbl for the same period of 2019. The decrease in NGL sales was primarily due to decreased gas volumes.
Lease Operating Expenses (“LOE”). LOE for the three months ended March 31, 2020 decreased to $5.3 million from $7.7 million for the same period in 2019. The decrease in LOE was primarily due to the disposition of our south Texas properties during the fourth quarter of 2019, and lower non-recurring LOE in 2020 as compared to 2019. LOE per Boe for the three months ended March 31, 2020 was $8.57 compared to $7.90 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 three months ended March 31, 2020 as compared to the same period of 2019.
Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended March 31, 2020 decreased to $1.5 million from $3.1 million for the same period of 2019. Production and ad valorem taxes for the three months ended March 31, 2020 were 10% 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 from North Dakota which has a higher tax rate.
General and Administrative (“G&A”) Expense. G&A expenses, excluding stock-based compensation, was decreased to $2.2 million for the three months ended March 31, 2020 as compared to $2.4 in 2019. G&A expense per Boe, excluding stock-based compensation, was $3.60 for the quarter ended March 31, 2020 compared to $2.41 for the same period of 2019. The increase per Boe was primarily due to lower 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 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 March 31, 2020, stock-based compensation expense was $0.2 million compared to $0.4 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 March 31, 2020 decreased to $9.2 million from $13.5 million for the same period of 2019. The decrease was primarily due to lower future development cost included in the March 31, 2020 internal reserve report, as well as lower production volumes during the three months ended March 31, 2020 as compared to the same period of 2019. DD&A expense per Boe for the three months ended March 31, 2020 was $14.88 compared to $13.76 in 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.
Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of March 31, 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 $26.7 million. As of March 31, 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 continued decline in commodity prices since March 31, 2020, due to COVID-19, will 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 ended March 31, 2020 increased to $4.4 million compared to $3.0 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 ended March 31, 2020 as compared to the same period in 2019, as well as higher overall interest rates in 2020 as compared to 2019. For the three months ended March 31, 2020 the interest rate on our first lien credit facility averaged 4.7% as compared to 5.9% for the same period of 2019. For the three months ended March 31, 2020 the interest rate on our second lien credit facility averaged 10.8%. We anticipate higher interest rates and increased interest expense in the future as a result of the amendments to our credit facilities.
Loss (Gain) on Derivative Contracts. Derivative gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place at period end. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps and basis differential swaps as of March 31, 2020, and March 31, 2019. The net estimated value of our commodity derivative contracts was a net asset of approximately $70.0 million as of March 31, 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 ended March 31, 2020, we recognized a gain on our commodity derivative contracts of $75.7 million, consisting of a gain on closed contracts of $2.5 million and a gain of $73.2 million related to open contracts. For the three months ended March 31, 2019, we recognized a loss on our commodity derivative contracts of $29.1 million, consisting of a loss of $1.0 million on closed contracts and a loss of $28.1 million related to open contracts.
Income Tax Expense. For the three months ended March 31, 2020 and March 31, 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.
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:
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•
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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.
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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 will incur additional impairments in 2020, which could include writing off 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 March 31, 2020, our current assets $46.8 million exceeded our current liabilities of $29.7 million resulting in a working capital surplus of $17.1 million. This compares to a working capital deficit of $28.6 million at December 31, 2019. Current assets as of March 31, 2020 primarily consisted of accounts receivable of $11.5 million, current amount of our derivative asset of $34.0 million and other current assets of $1.3 million. Current liabilities at March 31, 2020 primarily consisted of trade payables of $14.6 million, revenues due third parties of $8.1 million, current maturities of long-term debt of $0.3 million, the current amount of our derivative liability of $0.8 million and accrued expenses and other of $5.6 million.
Capital Expenditures. Capital expenditures for the three months ended March 31, 2020, and 2019 were $4.6 million and $30.0 million, respectively.
The table below sets forth the components of these capital expenditures:
|
|
Three Months Ended March 31,
|
|
|
|
2020
|
|
|
2019
|
|
|
|
(In thousands)
|
|
Expenditure category:
|
|
|
|
|
|
|
|
|
Exploration/Development
|
|
$
|
4,625
|
|
|
$
|
29,935
|
|
Acquisitions
|
|
|
-
|
|
|
|
-
|
|
Facilities and other
|
|
|
10
|
|
|
|
40
|
|
Total
|
|
$
|
4,635
|
|
|
$
|
29,975
|
|
During the three months ended March 31, 2020 and 2019 our capital expenditures were primarily for development of our existing properties. Cash basis capital expenditures for the three months ended March 31, 2020 of $9.5 million includes $4.9 million for a decrease in capital expenditures in accounts payable, resulting in net accrual basis capital expenditures of $4.6 million. As described in Note 10 to the unaudited condensed consolidated financial statements included in this Quarterly Report, 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.
Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
|
|
Three Months Ended March 31,
|
|
|
|
2020
|
|
|
2019
|
|
|
|
(In thousands)
|
|
Net cash provided by operating activities
|
|
$
|
3,652
|
|
|
$
|
28,195
|
|
Net cash used in investing activities
|
|
|
(9,549
|
)
|
|
|
(27,016
|
)
|
Net cash provided by (used in) financing activities
|
|
|
5,897
|
|
|
|
(721
|
)
|
Total
|
|
$
|
-
|
|
|
$
|
458
|
|
Operating activities for the three months ended March 31, 2020 provided $3.7 million in cash compared to providing $28.2 million in the same period of 2019. Higher 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 $9.5 million during the three months ended March 31, 2020 primarily for the development of our existing properties, investing activities also included a reduction in accounts payable related to capital expenditures of $4.9 million. Investing activities used $27.0 million during the three months ended March 31, 2019 primarily for the development of our existing properties. Financing activities provided $5.9 million for the three months ended March 31, 2020 compared to using $0.7 million for the same period of 2019. Funds provided during the three months ended March 31, 2020 and 2019, were primarily net proceeds from borrowings under our credit facility. Funds used for the three months ended March 31, 2019 were primarily due to a net reduction in 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 March 31, 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:
Below is a schedule of the future payments that we are obligated to make based on agreements in place as of March 31, 2020:
|
|
Payments due in twelve month periods ending:
|
|
Contractual Obligations
|
|
Total
|
|
|
March 31, 2021
|
|
|
March 31, 2022-2023
|
|
|
March 31, 2024-2025
|
|
|
Thereafter
|
|
Long-term debt (1)
|
|
$
|
204,799
|
|
|
$
|
284
|
|
|
$
|
202,391
|
|
|
$
|
2,124
|
|
|
$
|
-
|
|
Interest on long-term debt (2)
|
|
|
37,719
|
|
|
|
15,168
|
|
|
|
22,520
|
|
|
|
31
|
|
|
|
-
|
|
Lease obligations
|
|
|
360
|
|
|
|
102
|
|
|
|
97
|
|
|
|
59
|
|
|
|
102
|
|
Total
|
|
$
|
242,878
|
|
|
$
|
15,554
|
|
|
$
|
225,008
|
|
|
$
|
2,214
|
|
|
$
|
102
|
|
|
(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. Refer to Note 10. "Subsequent Events" for new debt agreements entered into subsequent to quarter end.
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|
(2)
|
Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.
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We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At March 31, 2020, our reserve for these obligations totaled $7.4 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.
Off-Balance Sheet Arrangements. At March 31, 2020, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.
Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At March 31, 2020, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.
Paycheck Protection Program Loan
On May 4, 2020, the Company entered into an unsecured loan with the U.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 Coronavirus Aid, Relief, and Economic Security Act (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, 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 75% 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:
|
|
March 31, 2020
|
|
|
December 31, 2019
|
|
First Lien Credit Facility
|
|
$
|
101,778
|
|
|
$
|
95,778
|
|
Second Lien Credit Facility
|
|
|
100,000
|
|
|
|
100,000
|
|
Real estate lien note
|
|
|
3,021
|
|
|
|
3,091
|
|
|
|
|
204,799
|
|
|
|
198,869
|
|
Less current maturities
|
|
|
(284
|
)
|
|
|
(280
|
)
|
|
|
|
204,515
|
|
|
|
198,589
|
|
Deferred financing fees, net
|
|
|
(5,434
|
)
|
|
|
(5,871
|
)
|
Total long-term debt, net of deferred financing fees
|
|
$
|
199,081
|
|
|
$
|
192,718
|
|
Waiver and Amendment No. 10 to Third Amended and Restated Agreement
On June 25, 2020, the Company and its subsidiary guarantors entered into the Waiver and Amendment No. 10 to Credit Agreement (the “1L Amendment”) with Société Générale, as administrative agent and lender, and the lenders party thereto, pursuant to which the parties agreed to, among other things, (i) waive the Company’s events of default with respect to its First Lien Credit Facility as a result of the Borrower’s failure to (A) deliver audited financial statements for the fiscal year ended December 31, 2019 not later than 90 days after the end of such fiscal year in violation of the First Lien Credit Facility and the Second Lien Credit Facility, (B) deliver a consolidated unaudited balance sheet and unaudited financial statements for the fiscal quarter ended March 31, 2020 not later than 45 days after the end of such fiscal quarter in violation of the First Lien Credit Facility and not later than 60 days after the end of such fiscal quarter in violation of the Second Lien Credit Facility and (C) prevent existing hedge agreements from exceeding the maximum coverage permitted pursuant to the First Lien Credit Facility and (D) failure to comply with the minimum Asset Coverage Ratio requirement with respect to the fiscal quarter ended March 31, 2020 coverage permitted pursuant to the First Lien Credit Facility and (ii) amend certain covenants and payment provisions of the First Lien Credit Facility.
Due to the unprecedented conditions surrounding the outbreak and spread of the COVID-19 pandemic, the recent decline in oil prices, and related geopolitical developments, the Company failed to (i) file its Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, (ii) file this Quarterly Report on Form 10-Q for the period ended March 31, 2020 no later than 45 days after the end of such fiscal quarter and (iii) prevent existing hedge agreements from exceeding the maximum coverage permitted pursuant to the First Lien Credit Facility, which resulted in violations of certain covenants under the First Lien Credit Facility (as in effect prior to the 1L Amendment). Subject to the terms and conditions of the 1L Amendment, Société Générale and each of the other lenders permanently waived such events of default and agreed not to charge default interest with respect to such defaults.
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 the Company, (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 before December 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 ended June 30, 2020 and calculated on an annualized basis for the 1, 2 and 3 quarter periods ending on June 30, 2020, September 30, 2020 and December 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 $50.0 million, (4) no default exists under the First Lien Credit Facility and (5) and all representations and warranties in the First Lien 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 ending June 30, 2020, $8.25 million for the four fiscal quarter period ending September 30, 2020, $6.9 million for the four fiscal quarter period ending December 31, 2020, and $6.5 million for the fiscal quarter from March 31, 2021 through December 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.
Waiver and Second Amendment to Term Loan Credit Agreement
On June 25, 2020, the Company and its subsidiary guarantors entered into the Waiver and Second Amendment to Term Loan Credit Agreement (the “2L Amendment”) with Angelo Gordon Energy Servicer, LLC, as administrative agent and issuing lender, and the lenders party there to, pursuant to which the parties agreed to, among other things, waive the Company’s designated events of default with respect to its Second Lien Credit Facility and amend certain covenants and payment provisions of the Second Lien Credit Facility.
As noted previously, the Company failed to file its Annual Report on Form 10-K for the period ended December 31, 2019 no later than 90 days after the end of such fiscal year, which resulted in violations of certain covenants under the Second Lien Credit Facility (as in effect prior to the 2L Amendment). Additionally, the Company failed to maintain the hedges required to be maintained pursuant to the Second Lien Credit Facility with respect to the fiscal quarter ended March 31, 2020, which resulted in a violation of the Company’s covenant under the Second Lien Credit Facility (as in effect prior to the 2L Amendment) to maintain certain required hedges. An additional Event of Default has occurred as a result of the Borrower’s failure to comply with the minimum Asset Coverage Ratio requirement with respect to the fiscal quarter ended March 31, 2020. Subject to the terms and conditions of the Second Lien Credit Facility, Angelo Gordon Energy Servicer, LLC and each of the other lenders permanently waived such events of default and agreed not to charge default interest with respect to such defaults.
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 the Company, (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 between September 30, 2021 to December 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 on September 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 by Angelo 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 ending June 30, 2020, $8.25 million for the four fiscal quarter period ending September 30, 2020, $6.5 million for fiscal quarter period from March 31, 2021 through December 31, 2021 and $5.0 million thereafter.
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•
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transfer or sell assets;
|
|
•
|
create liens on assets;
|
|
•
|
pay dividends of 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.
Fee Letter
On June 25, 2020, the Company, in connection with the 2L Amendment and to induce Angelo Gordon Energy Servicer, LLC and the lenders to enter into the 2L Amendment, entered into the Fee Letter (the “Fee Letter”) with Angelo Gordon Energy Servicer, LLC, pursuant to which the Company will (i) pay $10.0 million exit fee to Angelo Gordon Energy Servicer, LLC and the lenders upon maturity of the obligations under the Second Lien Credit Facility or the earlier acceleration or payment in full; (ii) grant warrants having an exercise price of $0.01 in an amount equal to 19.9% of the fully diluted common equity of the Company to Angelo Gordon Energy Servicer, LLC and the lenders; (iii) negotiate and provide an alternative financial arrangement that would afford Angelo Gordon Energy Servicer, LLC and the lenders an economic benefit equivalent in value to the warrants if the warrants cannot be issued on terms satisfactory to Angelo Gordon Energy Servicer, LLC; and (iv) protect the lenders by taking such reasonable steps as necessary to grant the lenders either (a) the right to appoint one member to the Company’s Board of Directors or (b) Board observation rights reasonably satisfactory to the administrative agent.
Future compliance with the covenants under the First Lien Credit Facility and Second Lien Credit Facility is reliant upon the Company’s ability to successfully implement cost reductions, control capital expenditures and restart production that has been shut in. In the event of a future covenant violation, the Company would attempt to obtain waivers or amendments of the related agreements; however, it is uncertain if such waivers or amendments could be obtained on acceptable terms or at all. In the event we default under the First Lien Credit Facility or Second Lien Credit Facility, amounts outstanding would become due and payable at the option of the lenders.
Real Estate Lien Note
We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The note was modified on June 20, 2018 to a fixed rate of 4.9% and is payable in monthly installments of $35,672. The maturity date of the note is July 20, 2023. As of March 31, 2020 and December 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 124% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates at March 31, 2020) from April through December 31, 2020, 91% for 2021 97% for 2022; 73% for 2023; and 89% 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.