LONESTAR RESOURCES US INC. The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Information. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements. Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh start accounting. References to "Successor" relate to the financial position and results of operations of the reorganized Company subsequent toNovember 30, 2020 . References to "Predecessor" relate to the financial position and results of operations of the Company prior to, and including,November 30, 2020 . Overview Lonestar Resources US Inc.is an independent exploration and production company with 79.2 MMBOE of estimated proved oil and natural gas reserves as ofDecember 31, 2020 , of which 74% is oil and NGLs. Our operations are focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in theEagle Ford Shale (the "Eagle Ford") play inSouth Texas . Emergence from Voluntary Reorganization under Chapter 11 OnSeptember 30, 2020 (the "Petition Date"),Lonestar Resources US Inc. , along with certain of its wholly-owned subsidiariesLonestar Resources Intermediate Inc. ,LNR America Inc. ,Lonestar Resources America Inc. ,Amadeus Petroleum Inc. ,Albany Services, L.L.C. ,T-N-T Engineering, Inc. ,Lonestar Resources Inc. ,Lonestar Operating, LLC ,Poplar Energy, LLC ,Eagleford Gas, LLC ,Eagleford Gas 2, LLC,Eagleford Gas 3, LLC,Eagleford Gas 4, LLC,Eagleford Gas 5, LLC,Eagleford Gas 6, LLC,Eagleford Gas 7, LLC,Eagleford Gas 8, LLC,Eagleford Gas 10, LLC,Eagleford Gas 11, LLC,Lonestar BR Disposal LLC , andLa Salle Eagle Ford Gathering Line LLC (collectively, the "Debtors") commenced voluntary cases (the "Chapter 11 Cases") under chapter 11 of title 11 of the United States Code (the "Bankruptcy Code") in theUnited States Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court "). The Chapter 11 Cases are being administered jointly under the caption In reLonestar Resources US Inc. , et al. Case No. 20-34805 (DRJ). Wholly-owned subsidiary,Boland Building, LLC , was not a Debtor and was not included in the Chapter 11 Cases. In addition, on the Petition Date, the Debtors filed their Joint Prepackaged Plan of Reorganization with theBankruptcy Court (the "Plan"). OnNovember 12, 2020 , theBankruptcy Court entered its confirmation order (the "Confirmation Order") approving and confirming the Plan. OnNovember 30, 2020 , (the "Effective Date") the Plan became effective and was implemented in accordance with its terms.
On the Effective Date, the Company consummated the following reorganization transactions in accordance with the Plan:
•Adopted an amended and restated its certificate of incorporation and bylaws, which reserved for issuance 90,000,000 shares of common stock, par value$0.001 per share, (the "New Common Stock") and 10,000,000 shares of preferred stock, par value$0.001 per share; •Appointed a new board of directors to replace the Predecessor's directors, consisting of four new independent members:Richard Burnett ,Gary D. Packer , Andrei Verona andEric Long , and one continuing member:Frank D. Bracken , III, Lonestar's Chief Executive Officer; •Provided for the following settlement of claims and interests in the Predecessor as follows: •Holders of Prepetition RBL Claims received distributions of: ?Cash in the amount of all accrued and unpaid interest; ?A first-out senior secured revolving credit facility with total aggregate commitments of$225 million ; ?A second-out senior secured term loan credit facility in an amount equal to$60 million ; ?555,555 Tranche 1 warrants and 555,555 Tranche 2 warrants, reflecting up to a 10% ownership stake in the Successor company's equity interests; •Holders of Prepetition Notes Claims received distributions of a pro rata share of 96% of 10,000,149 shares of New Common Stock issued on the Effective Date, subject to dilution by a to-be-adopted management incentive plan (the "MIP") and the new warrants); •Holders of Predecessor preferred equity interests received distributions of a pro rata share of 3% of the New Common Stock in the Successor company (subject to dilution by the MIP and the new warrants); and 56 -------------------------------------------------------------------------------- •Holders of Predecessor Class A common stock received distributions of a pro rata share of 1% of the New Common Stock in the Successor company (subject to dilution by the MIP and new warrants). •General unsecured creditors were paid in full in cash. Fresh Start Accounting Upon emergence from bankruptcy, the Company qualified for and adopted Fresh Start Accounting in accordance with ASC 852, which resulted in the Company becoming a new entity for financial reporting purposes because (1) the holders of the then existing voting shares of the Predecessor received less than 50 percent of the voting shares of the Successor upon emergence and (2) the reorganization value of the Company's assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims. All conditions required for the adoption of fresh-start accounting were met when the Plan became effective, onNovember 30, 2020 . The implementation of the Plan and the application of fresh-start accounting materially changed the carrying amounts and classifications reported in the Company's consolidated financial statements and resulted in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the financial statements on or prior to the effective date are not comparable with financial statements after the Effective Date. Upon the application of fresh-start accounting, the Company allocated the reorganization value to its individual assets and liabilities in conformity with ASC 805, Business Combinations ("ASC 805"). The amount of deferred income taxes recorded was determined in accordance with ASC 740, Income Taxes. Reorganization value represents the fair value of theSuccessor Company's assets before considering liabilities. The Effective Date fair values of the Company's assets and liabilities differ materially from their previously recorded values as reflected on the historical balance sheets. Market Developments and Response to Commodity Price Declines In January andFebruary 2020 , NYMEX WTI oil prices averaged in the mid-$50s per Bbl range before a precipitous decline in oil prices that began in earlyMarch 2020 due to the combination of the COVID-19 coronavirus ("COVID-19") pandemic and the failure of the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. While oil prices have improved from the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time.
The precipitous decline in oil prices that began in the latter part of the first quarter of 2020 caused us to reassess our original plans for 2020, and as a result the Company adopted the following operational and financial measures:
1.Reduced 2020 capital spending; 2.Deferred the remainder of our 2020 drilling program through the end of the year; 3.Implemented cost-reduction measures including negotiating reduced rates for water disposal, chemicals, rentals, and workovers; 4.Shut in or stored approximately 4,700 BOE per day of production during late-April and all ofMay 2020 , primarily at our oil-rich fields in our CentralEagle Ford Area ; and 5.Rebuilt our hedge portfolio startingOctober 2020 in anticipation of the Company's emergence from the Chapter 11 Proceedings. As ofMarch 29, 2021 (Successor), we had oil derivative contracts in place for 2021 covering approximately 5,255 Bbls/d at an average price of$45.17 per Bbl. In addition, we currently have oil derivative contracts in place for 2022 consisting of 3,062 Bbls/d at an average price of$47.03 per Bbl. As ofMarch 29, 2021 (Successor), we also had derivative contracts to hedge our 2021 natural gas production covering 13,251 MMBtu/d at a weighted average price of$3.02 per MMBtu. In addition, we currently have natural gas derivative contracts in place for 2022 consisting of 6,233 MMBtu/d at a weighted average price of$2.77 per MMBtu. We believe that these hedges help mitigate our exposure to oil and natural gas price volatility. 57 -------------------------------------------------------------------------------- 2020 Operational Highlights As a result of Lonestar filing for bankruptcy and emerging from bankruptcy onNovember 30, 2020 , our financial results are broken out between the Predecessor (the eleven months endedNovember 30, 2020 ) and the Successor period (the month endedDecember 31, 2020 ). For the Predecessor period, we recognized a net loss of$126.4 million attributable to common shareholders, and for the Successor period, we recognized a net loss of$0.7 million . The primary drivers of our financial net loss for the Predecessor period included the following: •Impairment of oil and gas properties of$199.9 million , of which$199.0 million was proved and$0.9 million was unproved. These impairments resulted from removing PUDs and probable reserves from future development plans due to the continued depressed commodity prices and the uncertainly of Company's liquidity situation at the time. •Reorganization items, net, resulted in an$73.5 million gain due to a gain on settlements of liabilities subject to compromise of$181.8 million , primarily representing the net impact of approximately$284.6 million of debt and accrued interest elimination, partially offset by fresh start accounting adjustments of$93.3 million and professional fees of$11.8 million . On a comparative basis, we recognized net loss of$111.6 million , or$4.48 per diluted share, during 2019. The following reflects some of the primary drivers for our change in operating results between full-year 2020 and 2019: •Oil and natural gas revenues decreased by$78.8 million (40%), with 25% of the decrease due to lower commodity prices and 15% due to lower production; •Lease operating expenses decreased by$10.1 million (32%), primarily due to cost reduction measures in light of the low oil price environment; •Commodity derivative expense decreased by$94.6 million ($63.7 million of income during 2020 compared to$30.9 million of expense during 2019), resulting from a$27.9 million increase in cash receipts upon settlement and an incremental$66.7 million decrease in noncash fair value losses between periods, and •Impairment of oil and gas properties totaled$199.9 million during 2020 compared to$48.4 million during 2019. See Operating Results - Impairment ofOil and Gas Properties below for further details. Pirate Divestiture OnMarch 22, 2019 , we completed the divestiture of our Pirate assets inWilson County for$12.3 million , before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres, six producing wells, held seven proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d. We recognized a loss of$33.5 million during the first quarter of 2019 (Predecessor) in conjunction with the sale of the assets. 58 -------------------------------------------------------------------------------- Operating Results Certain of our operating results and statistics for each of the last two years are summarized below: Successor Predecessor Eleven months Year Ended Month Ended Ended November December 31, In thousands, except per share and unit data December 31, 2020 30, 2020 2019 Operating results Net loss attributable to common stockholders $ (716)$ (126,376) $ (111,563) Net loss income per common share -- basic(1) (0.07) (5.00) (4.48) Net loss income per common share -- diluted(1) (0.07) (5.00) (4.48) Net cash provided by operating activities 12,987 88,236 80,322 Operating revenues Oil $ 8,112$ 80,244 $ 157,873 NGLs 1,083 9,982 15,668 Natural gas 1,706 15,100 21,611 Total operating revenues$ 10,901 $ 105,326 $ 195,152 Total production volumes by product Oil (Bbls) 188,322 2,268,715 2,692,020 NGLs (Bbls) 88,385 1,061,515 1,368,340 Natural gas (Mcf) 552,341 7,643,360 8,896,561 Total barrels of oil equivalent (6:1) 368,764 4,604,123 5,543,120 Daily production volumes by product Oil (Bbls/d) 6,075 6,772 7,375 NGLs (Bbls/d) 2,851 3,169 3,749 Natural gas (Mcf/d) 17,817 22,816 24,374 Total barrels of oil equivalent (BOE/d) 11,896 13,744 15,187 Average realized prices Oil ($ per Bbl) $ 43.08$ 35.37 $ 58.64 NGLs ($ per Bbl) 12.25 9.40 11.45 Natural gas ($ per Mcf) 3.09 1.98 2.43 Total oil equivalent, excluding the effect from hedging ($ per BOE) 29.56 22.88 35.21 Total oil equivalent, including the effect from hedging ($ per BOE) 27.55 38.16 34.15 Operating and other expenses Lease operating $ 1,418$ 20,435 $ 31,925 Gas gathering, processing and transportation 461 6,182 4,656 Production and ad valorem taxes 667 6,508 11,169 Depreciation, depletion and amortization 2,093 70,122 88,618 General and administrative 1,505 28,444 16,489 Interest expense 1,476 35,411 43,879 Operating and other expenses per BOE Lease operating and gas gathering $ 3.85$ 4.44 5.76 Gas gathering, processing and transportation 1.25 1.34 0.84 Production and ad valorem taxes 1.81 1.41 2.01 Depreciation, depletion and amortization 5.68 15.23 15.99 General and administrative 4.08 6.18 2.97 Interest expense 4.00 7.69 7.92
(1) Basic and diluted earnings per share are calculated using the two-class method for the Predecessor periods. See Footnote 1. Basis of Presentation in the Notes to Consolidated Financial Statements included in Item 8.
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The table below summarizes our daily production volumes for the years ended 2020 and 2019, and for each of the quarters of 2020:
2020 Quarters Year ended December 31,
Q1 Q2 Q3 Q4 2020 2019 Change
Oil (Bbls/d) 7,236 6,365 7,190 6,064 6,713 7,375 (9) %
NGLs (Bbls/d) 3,335 2,939 3,325 2,968 3,142 3,749 (16) %
Natural Gas (Mcf/d) 23,191 24,211 23,424 18,773 22,393 24,374 (8) %
Total (BOE/d) 14,436 13,339 14,419 12,161 13,587 15,187 (11) %
Total production during 2020 averaged 13,587 BOE/d, a decrease of 11% compared
to 2019. The annual decrease was primarily driven by curtailment of production
during the second quarter of 2020 due to depressed commodity prices, as
discussed above, and deferment of the drilling program in the third quarter of
2020 due to continued depressed commodity prices and preservation of liquidity
while the Company went through reorganization.
Our production during 2020 was 73% oil and NGLs, approximately the same
allocation as 2019.
Oil, NGL and Natural Gas Revenues
The table below summarizes our production revenues for 2020 and 2019:
Successor Predecessor
One Month
Ended Eleven Months Year Ended
December 31, Ended November December 31,
In thousands 2020 30, 2020 2019
Oil $ 8,112 $ 80,244 $ 157,873
NGLs 1,083 9,982 15,668
Natural Gas 1,706 15,100 21,611
Total operating revenues $ 10,901 $ 105,326 $ 195,152 The changes in our oil, NGL and natural gas revenues are due to production quantities and commodity prices, as reflected in the following table (excluding any impact of our commodity derivative contracts):
Year
ended
Percentage change in
In thousands Change in revenues revenues
Change in oil, NGL and natural gas revenues due to:
Decrease in production $ (20,078) (25) %
Decrease in commodity prices (58,816) (15) %
Total operating revenues $ (78,894) (40) %
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Excluding the impact of our commodity derivative contracts, our net realized
commodity prices and NYMEX differentials were as follows during 2020 and 2019:
Successor Predecessor
Eleven Months Year Ended
Month Ended Ended November December 31,
December 31, 2020 30, 2020 2019
Average net realized prices:
Oil ($/Bbl) $ 43.08 $ 35.37 $ 58.64
NGLs ($/Bbls) 12.25 9.40 11.45
Natural gas ($/Mcf) 3.09 1.98 2.43
Total ($/BOE) 29.56 22.88 35.21
Average NYMEX differentials
Oil per Bbl $ (4.01) $ (3.33) $ 1.61
Natural gas per Mcf (0.01) 0.50 (0.14)
Our average NYMEX oil differential decreased compared to 2019 due to the pricing
components of MEH and CMA/Roll being approximately $4.38 , or 86%, lower on
average in 2019 compared to 2020.
Our natural gas NYMEX differentials are generally caused by movement in the
NYMEX natural gas prices during the month, as most of our natural gas is sold on
an index price that is set near the first of each month. While the percentage
change in NYMEX natural gas differentials can be large, these differentials are
seldom more than a dollar above or below NYMEX price.
Commodity Derivative Contracts
We utilize oil and natural gas derivative contracts to provide an economic hedge
of our exposure to commodity price risk associated with anticipated future
production and to provide more certainty to our future cash flows. These
contracts have historically consisted of fixed-price swaps, collars and basis
swaps.
The following table summarizes the net cash payments on the Company's commodity
derivatives for 2020 and 2019:
Successor Predecessor
Month Ended Eleven Months Year Ended
December 31, Ended November December 31,
In thousands 2020 30, 2020 2019
Receipts (payments) on settlements of oil
derivatives $ - $ 72,580 $ (5,902)
(Payments) receipts on settlements of natural
gas derivatives - (3,189) 2,352
Total net commodity derivative receipts
(payments) $ - $ 69,391 $ (3,550)
61-------------------------------------------------------------------------------- In order to provide a level of price protection to a portion of our oil production and to meet certain hedging requirements under our Successor senior secured bank credit facility, we have hedged a portion of our estimated oil and natural gas production in 2021 and 2022 using NYMEX fixed-price swaps. See Note 12, Commodity Price Risk Activities, to the consolidated financial statements for additional details of our outstanding commodity derivative contracts as ofDecember 31, 2020 below for additional discussion. In addition, the following table summarizes our oil derivative contracts as ofMarch 24, 2021 : Q1 2021 Q2 2021 Q3 2021 Q4 2021 1H 2022 2H 2022 Oil - WTI Volumes Hedged (Bbls/d) 4,822 6,150 5,150 4,900 3,124 3,000 Swap Price$ 43.98 $ 46.66 $ 45.11 $
44.53
Natural Gas -Henry Hub Volumes Hedged (Mcf/d) 13,500 12,400 16,400 10,700 7,486 5,000 Swap Price$ 3.23 $ 2.88 $ 2.93 $ 3.05 $ 2.82 $ 2.70 On an accrual basis, our realized gain on derivative hedging instruments was$69.6 million , or$14.00 per BOE, for the combined Predecessor and Successor periods included within the year endedDecember 31, 2020 , compared to a realized loss of$5.9 million , or$5.07 per BOE, during 2019. Included in the 2020 amount is$33.2 million , net ($39.9 million in oil hedges and negative$6.7 million in natural gas hedges, gross), which was realized upon termination of our hedging portfolio inSeptember 2020 (Predecessor) prior to the commencement of the Chapter 11 Proceedings. Production Expenses The table below presents detail of production expenses for 2020 and 2019: Successor Predecessor Eleven Months Year Ended Month Ended Ended November December 31, In thousands, except expense per BOE: December 31, 2020 30, 2020 2019 Production expenses: Lease operating$ 1,418 $ 20,435 $ 31,925 Gas gathering, processing and transportation 461 6,182 4,656 Production and ad valorem taxes 667 6,508 11,169 Depreciation, depletion and amortization 2,093 70,122 88,618 Production expenses per BOE: Lease operating $ 3.85$ 4.44 $ 5.76 Gas gathering, processing and transportation 1.25 1.34 0.84 Production and ad valorem taxes 1.81 1.41 2.01 Depreciation, depletion and amortization 5.68 15.23 15.99 Lease Operating and Gas Gathering Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and ad valorem taxes. 62 -------------------------------------------------------------------------------- Total lease operating expense was$21.9 million , or$4.39 per BOE, for the combined Predecessor and Successor periods included within the year endedDecember 31, 2020 , compared to$31.9 million , or$5.76 per BOE, during 2019. Total gas gathering, processing and transportation expense was$6.6 million , or$1.34 per BOE for the combined Predecessor and Successor periods included within the year endedDecember 31, 2020 , compared to$4.7 million , or$0.84 per BOE, during 2019. The decreases in lease operating expense on an absolute-dollar basis and per-BOE basis were primarily due to lower expenses across all expense categories, as we implemented cost reduction measures which included shutting down compressors, negotiating reductions with vendors and curtailing workovers in response to the significant decline in oil prices in 2020. Gas gathering, processing and transportation expense remained relatively constant between years as the Company prioritized maintaining its natural gas production through 2020. Natural gas prices did not drop to the extent oil prices did during the second and third quarter when the Company shut in a significant a significant amount of its production, primarily from its oil-rich wells in theCentral Region . Production and Ad Valorem Taxes Production and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties. The following table provides detail of our production and ad valorem taxes for 2020 and 2019: Successor Predecessor Eleven Months Year Ended Month Ended Ended November December 31, In thousands December 31, 2020 30, 2020 2019 Production taxes $ 440$ 4,015 $ 8,098 Ad valorem taxes 227 2,493 3,071 Total production and ad valorem tax expense $ 667
Production and ad valorem tax expense per BOE Production taxes $ 1.19 $ 0.87$ 0.90 Ad valorem taxes 0.62 0.54 0.55 Total production and ad valorem tax expense per BOE $ 1.81
$ 1.41
Total production and ad valorem tax expense was$7.2 million , or$1.44 per BOE, for the combined Predecessor and Successor periods included within the year endedDecember 31, 2020 , compared to$11.2 million , or$1.44 per BOE, during 2019. The decrease between periods was primarily due to the decrease in production taxes resulting from lower oil and natural gas revenues and production levels. 63 --------------------------------------------------------------------------------
Depreciation, Depletion, and Amortization ("DD&A") The table below provides detail of our DD&A expense for 2020 and 2019:
Successor Predecessor
Eleven Months Year Ended
Month Ended Ended November December 31,
In thousands December 31, 2020 30, 2020 2019
DD&A of proved oil and gas properties $ 1,889 $ 67,591 $ 86,867
Depreciation of other property and equipment 136 1,442 1,451
Accretion of asset retirement obligations 68 1,089 300
Total DD&A $ 2,093 $ 70,122 $ 88,618
DD&A per BOE
DD&A of proved oil and gas properties $ 5.12 $ 14.68 $ 15.68
Depreciation of other property and equipment 0.37 0.31 0.26
Accretion of asset retirement obligations 0.18 0.24 0.05
Total DD&A per BOE $ 5.67 $ 15.23 $ 15.99
Capitalized costs attributed to our proved properties are subject to
depreciation and depletion. Depreciation and depletion of the cost of oil and
natural gas properties is calculated using the unit-of-production method
aggregating properties on a field basis. For leasehold acquisition costs and the
cost to acquire proved properties, the reserve base used to calculate
depreciation and depletion is the sum of proved developed reserves and proved
undeveloped reserves. For well costs, the reserve base used to calculate
depletion and depreciation is proved developed reserves only. Other property and
equipment are carried at cost, and depreciation is calculated using the
straight-line method over the estimated useful lives of the assets, ranging from
3 to 5 years.
Total DD&A expense was $72.2 million , or $14.52 per BOE, for the combined
Predecessor and Successor periods included within the year ended December 31,
2020 , compared to $88.6 million , or $15.99 per BOE, during 2019. The combined
Predecessor and Successor period decreases in oil and natural gas properties
depletion and other property and equipment depreciation was primarily due to
impairment charges we incurred during the first quarter of 2020 (Predecessor)
after removing PUDs (see below, as well as lower depletable costs due to the
step down in book value resulting from fresh start accounting.
Based upon fresh start accounting, oil and gas properties were recorded at fair
value as of November 30, 2020 . See Note 3, Fresh Start Accounting, to the
consolidated financial statements for further discussion.
Impairment of Oil and Gas Properties
We evaluate impairment of proved and unproved oil and gas properties on a region
basis. On this basis, certain regions may be impaired because they are not
expected to recover their entire carrying value from future net cash flows.
During the fourth quarter of 2019 (Predecessor), we recorded impairment charges
totaling approximately $48.4 million for our East Region properties in Brazos
County , $33.9 million of which related to proved properties and $14.5 million
which related to unproved properties. These impairments resulted from recent
well results as well as a deterioration of commodity prices and the operating
environment in the Region.
During the first quarter of 2020 (Predecessor), we recorded impairment charges
totaling approximately $199.9 million across various Eagle Ford properties, of
which $199.0 million was proved and $0.9 million was unproved. These impairments
resulted from removing PUDs and probable reserves from future development plans
due to the continued depressed commodity prices and the uncertainly of Company's
liquidity situation at the time.
Upon emergence from bankruptcy, the Company adopted fresh start accounting which
resulted in our long-lived assets being recorded at their estimated fair values
at the Effective Date (see Note 3, Fresh Start Accounting, to the consolidated
financial statements for additional information). There were no material changes
to our key cash flow assumptions and no triggering events since the Company's
assets were revalued in fresh start accounting as of November 30, 2020 ;
therefore, no impairment was identified in December 2020 .
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Loss on Sale of Oil and Gas Properties
On March 22, 2019 , we completed the divestiture of our Pirate assets in Wilson
County for $12.3 million , before closing adjustments, to a private third-party.
The assets were comprised of 3,400 net undeveloped acres, six producing wells,
held seven proved undeveloped locations as of the closing date, and were
producing approximately 200 BOE/d. We recognized a loss of $33.5 million during
the first quarter of 2019 (Predecessor) in conjunction with the sale of the
assets.
General and Administrative Expense
Total general and administrative ("G&A") expense was $30.0 million , or $6.04 per
BOE, for the combined Predecessor and Successor periods included within the year
ended December 31, 2020 , compared to $16.5 million , or $2.97 per BOE, during
2019. These increases primarily reflect professional fees incurred related to
our restructuring efforts prior to the Petition Date and subsequent to the
Effective Date.
Stock-based compensation included in G&A was a gain of $1.8 million in 2020 for
the eleven months ended November 30, 2020 , versus an expense of $2.5 million in
2019. On the Effective Date, all of the Predecessor's stock-based compensation
plans were cancelled and the Successor Company did not implement any new
stock-based compensation plans prior to December 31, 2020 .
Interest Expense
The table below provides detail of the interest expense from our various
long-term obligations for 2020 and 2019:
Successor Predecessor
Eleven Months Year Ended
Month Ended Ended November December 31,
In thousands December 31, 2020 30, 2020 2019
Interest expense on Successor Credit Facility $ 984 $ - $ -
Interest expense on Successor Term Loan Facility 344 - -
Interest expense on Predecessor Credit Facility
(1) - 11,599 12,449
Interest expense on Predecessor 11.25% Senior
Notes - 21,094 28,125
Other interest expense 17 622 677
Total cash interest expense(2) $ 1,345 $ 33,315 $ 41,251
Amortization of debt issuance costs and
discounts(3) 131 2,096 2,628
Total interest expense $ 1,476 $ 35,411 $ 43,879
Per BOE:
Total cash interest expense(2) $ 3.65 $ 7.24 $ 7.44
Total interest expense 4.00 7.69 7.92
(1) The contractual interest expense on the 11.25% Senior Notes is in excess of
recorded interest expense by $4.7 million from the Petition Date until the
Effective Date and was not included as interest expense on the Consolidated
Statements of Operations for the Predecessor period because the Company
discontinued accruing interest on the 11.25% Senior Notes subsequent to the
Petition Date in accordance with ASC 852.
(2) Cash interest is presented on an accrual basis.
(3) Remaining discounts for the Predecessor 11.25% Senior Notes were
written-off to "Reorganization items, net" in the Consolidated Statements of
Operations on the Petition Date.
Cash interest was $34.7 million , or $6.97 per BOE, for the combined Predecessor
and Successor periods included within the year ended December 31, 2020 , compared
to $41.3 million , or $6.97 per BOE, during 2019. The decrease between periods
was primarily due to a decrease in the average debt principal outstanding, with
the Successor period reflecting the full extinguishment of all outstanding
obligations under the 11.25% Senior Secured Notes on the Effective Date,
pursuant to the terms of the Plan, relieving approximately $250 million of debt
by issuing equity in the Successor period to the holders of that debt.
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See Note 10. Long-Term Debt in Notes to the Consolidated Financial Statements
included in Item 8. Financial Statements for additional information about our
long-term debt and interest expense.
Reorganization Items, Net
Reorganization items represent (i) expenses incurred during the Chapter 11
restructuring starting on the Petition Date as a direct result of the Plan, (ii)
gains or losses from liabilities settled, and (iii) fresh start accounting
adjustments and are recorded in "Reorganization items, net" in our Consolidated
Statements of Operations. Professional service provider charges associated with
our restructuring that were incurred before the Petition Date and after the
Effective Date are recorded as general and administrative expenses in our
Consolidated Statements of Operations.
The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
Period from
September 30,
2020 through
November 30,
In thousands 2020
Unamortized debt issuance costs and discounts $ (3,243)
Professional fees and other (11,847)
Fresh start valuation adjustments
(93,282)
Gain on settlement of liabilities subject to compromise
181,843
Total reorganization items, net$ 73,471 Income Taxes The table below provides further detail of our income tax benefit for 2020 and 2019: Successor Predecessor Year Ended Month Ended Eleven Months Ended December 31,
In thousands, except per-BOE amounts and tax rates
November 30, 2020 2019 Current income tax benefit $ -$ (3,748) $ (1,055) Deferred income tax benefit - (931) (11,440) Total income tax benefit $ -$ (4,679) $ (12,495) Average income tax benefit per BOE $ -$ (1.02) $ (2.25) Effective tax rate - % (3.8) % (10.8) % Total net deferred tax liability on balance sheet at period end $ - $ -$ 931 We have evaluated the impact of the Plan, including the change in control, resulting from our emergence from bankruptcy. The cancellation of debt income ("CODI") realized upon emergence is excludable from income and resulted in a partial elimination of our available federal net operating loss carryforwards and tax credit carryforwards, as well as a partial reduction in tax basis in assets, in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 (the "Code"). The reduction in the Company's tax attributes for excludable CODI did not occur until the last day of the Company's tax year,December 31, 2020 . The final tax impacts of the bankruptcy emergence, as well as the Plan's overall effect on the Company's tax attributes which were refined based on the Company's final financial position atDecember 31, 2020 as required under the Code. 66 -------------------------------------------------------------------------------- As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in fresh start accounting, the Successor is in a net deferred tax asset position atDecember 31, 2020 . We evaluated our deferred tax assets in light of all available evidence as of the balance sheet date, including the tax impacts of the Chapter 11 Proceedings and the partial reduction of net operating losses and tax credits and partial reduction of tax basis in assets (collectively "tax attributes"). Given our cumulative loss position and the continued low oil price environment, we recorded a total valuation allowance of$37.5 million on our underlying deferred tax assets as ofDecember 31, 2020 . For the Successor period, the income tax benefit associated with the Successor's pre-tax book loss was substantially offset by a change in valuation allowance. Our deferred tax assets exceeded our deferred tax liabilities atDecember 31, 2019 (Predecessor) primarily due to tax consequences of the impairment of ourBrazos properties during the fourth quarter; as a result, we established a valuation allowance against most of the deferred tax assets during the fourth quarter of 2019. With the exception of a$0.6 million deferred tax asset retained for existing refundable AMT credit carryovers we retained a full valuation allowance of$8.9 million atDecember 31, 2019 due to uncertainties regarding the future realization of our deferred tax assets. This deferred tax asset is included in the net deferred tax liability atDecember 31, 2019 , which also includes deferred tax liabilities of$1.5 million for State taxes. See Note 11. Income Taxes in Notes to the Consolidated Financial Statements included in Item 8. Financial Statements for additional information about our income taxes. CAPITOL RESOURCES AND LIQUIDITY Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our Successor Credit Facility. Our most significant cash outlays relate to our development capital expenditures and current period operating expenses. The Company's primary needs for cash are for capital expenditures, acquisitions of oil and natural gas properties, payments of contractual obligations and working capital obligations. We have historically financed our business through cash flows from operations, borrowings under our Credit Facility and the issuance of bonds and equity offerings. As circumstances warrant, we may access the capital markets and issue equity or debt from time to time on an opportunistic basis in a continued effort to optimize our balance sheet and to fund our operations and capital expenditures in the future, dependent upon market conditions and available pricing. Uses of such proceeds may include repayment of our debt, development or acquisition of additional acreage or proved properties, and general corporate purposes. There can be no assurance that future funding transactions will be available on favorable terms, or at all, and we therefore cannot guarantee the outcome of any such transactions. Cash flows for 2020 and 2019 are presented below: Successor Predecessor Eleven Months Year Ended Month Ended Ended November December 31, In thousands December 31, 2020 30, 2020 2019 Net cash provided by (used in): Operating activities$ 12,987 $ 88,236 $ 80,322 Investing activities (305) (92,432) (146,292) Financing activities (5,021) 19,844 63,752 Net change in cash, cash equivalents and $ 7,661 restricted cash$ 15,648 $ (2,218) Net Cash Provided by Operating Activities Net cash provided by operating activities was$101.2 million for the combined Successor and Predecessor periods included with the year endedDecember 31, 2020 , compared to$80.3 million during 2019. Realized commodity derivative gains throughout the Predecessor period in 2020 in addition to the liquidation of our open commodity derivatives inSeptember 2020 , contributed to the increase between periods. 67 --------------------------------------------------------------------------------Net Cash Used in Investing Activities Net cash used in investing activities was$92.7 million for the combined Successor and Predecessor periods included with the year endedDecember 31, 2020 , compared to$146.3 million during 2019. This decrease is primarily due to lower drilling and development costs in 2020 due to curtailment of our drilling program starting in the second quarter of 2020 in response to lower commodity prices and liquidity conservation in anticipation of restructuring. Net Cash Provided by Financing Activities Net cash provided by financing activities was$14.8 million for the combined Successor and Predecessor periods included with the year endedDecember 31, 2020 , compared to$63.8 million during 2019. This decrease primarily results from lower borrowings from our Predecessor Credit Facility during 2020. Currently, our availability under the Successor Credit Facility is$15.0 million and we are required to make quarterly paydowns on our Successor Term Loan Facility which will total$20.0 million annually in 2021. Debt Successor Senior Secured Credit Agreements On the Effective Date, the Successor, through its subsidiaryLonestar Resources America Inc. , entered into a new first-out senior secured revolving credit facility withCitibank, N.A ., as administrative agent, and the other lenders from time to time party thereto (the "Successor Credit Facility") and a second-out senior secured term loan credit facility (the "Successor Term Loan Facility" and, together with the Successor Credit Facility, the "Successor Credit Agreements") by amending and restating the Company's existing credit agreement (as so amended and restated, the "Predecessor Credit Facility"). The Successor Credit Facility provides for revolving loans in an aggregate amount of up to$225 million , subject to borrowing base capacity. Letters of credit are available up to the lesser of (a)$2.5 million and (b) the aggregate unused amount of commitments under the Successor Credit Facility then in effect. On the Effective Date,Lonestar Resources America Inc. borrowed$60.0 million in term loans under the Successor Term Loan Facility. The Successor Credit Agreements will mature onNovember 30, 2023 . The term loans under the Successor Term Loan Facility amortize on a quarterly basis in an amount equal to$5.0 million , payable on the last day of March, June, September and December of each year. The Successor's obligations under the Successor Credit Agreements are guaranteed by all of the Successor's direct and indirect subsidiaries (subject to certain permitted exceptions) and will be secured by a lien on substantially all of the Successor's,Lonestar Resources America Inc.'s and the guarantors' assets (subject to certain exceptions). Borrowings and letters of credit under the Successor Credit Facility are limited by borrowing base calculations set forth therein. The initial borrowing base is$225 million , subject to redetermination. The borrowing base will be redetermined semiannually on or aroundMay 1 andNovember 1 of each year, with one interim "wildcard" redetermination available between scheduled redeterminations. The first wildcard redetermination occurred onFebruary 1, 2021 , which reaffirmed the initial borrowing base of$225 million . The Successor Credit Agreements contain customary covenants, including, but not limited to, restrictions on the Successor's ability and that of its subsidiaries to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets, make acquisitions, loans, advances or investments, pay dividends, sell or otherwise transfer assets, or enter into transactions with affiliates.
The Successor Credit Facility contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and •A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of at least 0.95 times for the three months endedDecember 31, 2020 and 1.0 times each fiscal quarter thereafter. The current ratio excludes current derivative assets and liabilities, as well as the current amounts due under the Successor Term Loan Facility, from the ratio. 68 -------------------------------------------------------------------------------- Borrowings under the Successor Credit Agreements bear interest at a floating rate at the Successor's option, which can be either an adjusted Eurodollar rate (the Adjusted LIBOR, subject to a 1% floor) plus an applicable margin of 4.50% per annum or a base rate determined under the Successor Credit Facility (the "ABR", subject to a 2% floor) plus an applicable margin of 3.50% per annum. The weighted average interest rate on borrowings under the Successor Credit Agreements was 5.8% for the month endedDecember 31, 2020 (Successor). The undrawn portion of the aggregate lender commitments under the Successor Credit Facility is subject to a commitment fee of 1.0%. As ofDecember 31, 2020 , the Successor was in compliance with all debt covenants under the Successor Credit Facilities. Predecessor Senior Secured Bank Credit Facility FromJuly 2015 throughNovember 30, 2020 , the Predecessor maintained a senior secured revolving credit facility withCitibank, N.A ., as administrative agent, and other lenders party thereto. All of the Predecessor Credit Facility was refinanced by the Successor Credit Agreements on the Effective Date. Extinguishment of Predecessor 11.25% Senior Notes
On the Effective Date, the Predecessor's 11.25% Senior Notes due 2023 (the "11.25% Senior Notes") were fully extinguished by issuing equity in the Successor to the holders of that debt.
Debt Issuance Costs The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. AtDecember 31, 2020 (Successor) and 2019 (Predecessor), the Company had approximately$4.6 million and$0.8 million , respectively, of debt issuance costs associated with the Successor Credit Facility and Predecessor Credit Facility, respectively, remaining that are being amortized over the lives of the respective debt which are recorded as Other Non-Current Assets in the accompanying unaudited condensed consolidated balance sheets. Capital Expenditures Historical capital expenditures The table below summarizes our cash capital expenditures incurred for 2020: Successor Predecessor Month Ended December Eleven Months Ended In thousands 31, 2020 November 30, 2020 Acquisition of oil and gas properties $ 53 $ 2,902 Development of oil and gas properties 247 100,437 Purchases of other property and equipment 5 1,007 Total capital expenditures, net $ 305 $ 104,346 For the year endedDecember 31, 2020 , our capital expenditures were funded with$101.2 million of cash flow from operations, with additional funds provided by borrowings on our Predecessor Credit Facility. 2021 Capital Spending Capital spending levels are highly dependent on revenues, liquidity and our commitment to repay debt. We are currently expect expenditures, including acquisitions, of$45 million to$55 million . This program, as it currently stands, will allow for the drilling of 10 gross wells, all of which will be in our Eagle Ford position inSouth Texas . As previously noted, our 2021 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital that we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated wells, our drilling results, other opportunities that may become available to us and our ability to obtain capital. 69 -------------------------------------------------------------------------------- Off-Balance Sheet Arrangements We have operating leases relating to office space and other minor equipment leases. AtDecember 31, 2020 (Successor), we had a total of$0.4 million of letters of credit outstanding under our Successor Credit Facility. From time-to-time, we enter into other off-balance sheet arrangements and transactions that give rise to off-balance sheet obligations, including non-operated drilling commitments, termination obligations under rig contracts, frac spread contracts, firm transportation, gathering, processing and disposal commitments, and contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices. See Note 15. Commitments and Contingencies in Notes to Consolidated Financial Statements in Item 8. Financial Statements for more information. 70 -------------------------------------------------------------------------------- Critical Accounting Policies and Estimates The preparation of financial statements in accordance with generally accepted accounting principles requires that we select certain accounting policies and make certain estimates and judgments regarding the application of those policies. Our significant accounting policies are included in Note 1. Basis of Presentation, of the Notes to Consolidated Financial Statements in Item 8. Financial Statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements. Fresh Start Accounting Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Topic 852, Reorganizations, which on the Effective Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. Fresh start accounting requires that new fair values be established for the Company's assets, liabilities and equity as of the date of emergence from bankruptcy,November 30, 2020 . The Effective Date fair values of the Successor's assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and required a number of estimates and judgments to be made. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, financial projections, enterprise value and equity value, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially. Among the most material of these judgments and estimates that were made were the following: •Reorganization Value - The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company's identifiable tangible and intangible assets and liabilities based on their fair values. The value of the reconstituted entity (i.e., Successor) was based on management projections and the valuation models as determined by the Plan of Reorganization. We determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. •Oil and Natural Gas Properties - The fair value of our oil and natural gas properties was determined based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Effective Date. The fair value analysis was based on the Company's estimated future production rates of proved and probable reserves as prepared by the Company's internal reserves group. Discounted cash flow models were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenue estimates were based upon estimated future production rates and forward strip oil and natural gas prices and other factors. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property's produced assets. 71 -------------------------------------------------------------------------------- Estimates of Reserve Quantities Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. All reserve reports prepared by the independent third-party reserve engineers are reviewed by our senior management team, including the Chief Executive Officer and Senior Vice President-Operations. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods.Oil and Natural Gas Properties We use the successful efforts method of accounting to account for our oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Our policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive. Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For well costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors. It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the joint operating agreement that joint interest owners in a property adopt. As an operator, we record these advance payments in other current liabilities and relieve this account when the actual expenditure is billed by us in the monthly joint interest billing statement. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized. On the sale or retirement of a partial unit of a proved property, a pro-rata portion of the cost and related accumulated depreciation, depletion and amortization may be eliminated from the property accounts if the field depletion rate is significantly altered. 72 -------------------------------------------------------------------------------- Impairment of Long-Lived Assets The carrying value of proved oil and gas properties and other related property and equipment are periodically evaluated under the provisions of Accounting Standards Codification ("ASC") 360, Property, Plant, and Equipment. ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management's estimate of undiscounted future cash flows and an asset's fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates. The Company evaluates impairment of proved and unproved oil and gas properties on a region-level basis. On this basis, certain regions may be impaired because they are not expected to recover their entire carrying value from future net cash flows. Given current market conditions, it is reasonably possible that the Company's estimate of undiscounted future net cash flows may change in the future resulting in the need to impair the carrying value of its oil and natural gas properties. During the fourth quarter of 2019 (Predecessor), we recorded impairment charges totaling approximately$48.4 million for ourEast Region properties inBrazos County ,$33.9 million of which related to proved properties and$14.5 million which related to unproved properties. These impairments resulted from recent well results as well as a deterioration of commodity prices and the operating environment in the Region. During the first quarter of 2020 (Predecessor), we recorded impairment charges totaling approximately$199.9 million across various Eagle Ford properties, of which$199.0 million was proved and$0.9 million was unproved. These impairments resulted from removing PUDs and probable reserves from future development plans due to the continued depressed commodity prices and the uncertainly of Company's liquidity situation at the time. Derivative Financial Instruments We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our board directors. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the statement of operations. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. Asset Retirement Obligations We account for asset retirement obligations ("AROs") under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statement of operations. The estimation of future costs associated with the dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirement, technological advances and other factors that are difficult to predict. 73 -------------------------------------------------------------------------------- There are many variables in estimating AROs. We primarily use the remaining estimated useful life from the year-end independent third-party reserve reports in estimating when abandonment could be expected for each property based on field or industry practices. We expect to see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free-rate is one of the variables used on a quarterly basis. Our technical team has developed a standard cost estimate based on the historical costs, industry quotes and depth of wells. Unless we expect a well's plugging cost to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of an inflation factor and a discount factor, could differ from actual results. Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized. Taxable income (which is materially impacted by volatility in commodity prices), can result in our recording of a valuation allowance against our deferred tax assets. We would record this valuation allowance when our judgment is that our existingU.S. federal net operating loss carryforwards are not, on a more-likely-than-not basis, recoverable in future years. We will continue to evaluate the need for a valuation allowance based on current and expected earnings and other factors and adjust it accordingly. OnMarch 27, 2020 ,Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") to provide certain taxpayer relief as a result of the COVID-19 pandemic. The CARES Act included several favorable provisions that impacted income taxes, primarily the modified rules on the deductibility of business interest expense for 2019 and 2020, a five-year carryback period for net operating losses generated after 2017 and before 2021, and the acceleration of refundable alternative minimum tax credits. The CARES Act did not materially impact our effective tax rate for the eleven months endedNovember 30, 2020 (Predecessor) and month endedDecember 31, 2020 (Successor). We evaluate uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. Recently Issued Accounting Pronouncements See Note 1. Basis of Presentation of the Notes to Consolidated Financial Statements in Item 8. Financial Statements for discussion of the recent accounting pronouncements. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. We are exposed to a variety of financial market risks including interest rate, commodity prices and liquidity risk. Our risk management focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. We utilize derivative financial instruments to hedge certain risk exposures. Our financial instruments consist mainly of deposits with banks, short-term investments, accounts receivable, derivative financial instruments, our Senior Secured Credit Facility, bonds and payables. The main purpose of non-derivative financial instruments is to raise finance for our operations. Financial risk management is carried out by our management. Our board of directors sets financial risk management policies and procedures to which our management is required to adhere. Our management identifies and evaluates financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by our board of directors. 74 -------------------------------------------------------------------------------- Commodity Price Risk As a result of our operations, we are exposed to commodity price risk arising from fluctuations in the prices of crude oil, NGLs and natural gas. The demand for, and prices of, crude oil, NGLs and natural gas are dependent on a variety of factors, including supply and demand, weather conditions, the price and availability of alternative fuels, actions taken by governments and international cartels and global economic and political developments. The following table shows the fair value of our derivative contracts and the hypothetical result from a 10% change in commodity prices as ofDecember 31, 2020 (Successor). We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks could be mitigated by price changes in the underlying physical commodity:
Hypothetical Fair Value
10% Increase In 10% Decrease In
(in thousands) Fair Value Commodity Price Commodity Price
Swaps $ (6,675) $ 5,791 $ (19,140)
We sell our oil and natural gas on market using NYMEX market spot rates reduced
for basis differentials in the basins from which we produce. We use swap
contracts to manage our commodity price risk exposure. Our primary commodity
risk management objectives are to protect returns on our drilling and completion
activity as well as reduce volatility in our cash flows. Management makes
recommendations on hedging that are approved by the board of directors before
implementation. We enter into hedges for oil using NYMEX futures or
over-the-counter derivative financial instruments with only certain
well-capitalized counterparties which have been approved by our board of
directors.
The result of oil market prices exceeding our swap prices or collar ceilings
requires us to make payment for the settlement of our hedge derivatives, if owed
by us, generally up to three business days before we receive market price cash
payments from our customers. This could have a material adverse effect on our
cash flows for the period between hedge settlement and payment for revenues
earned.
Interest Rate Risk
As of December 31, 2020 (Successor), we had $264.6 million outstanding under the
Successor Credit Agreements, which are subject to floating market rates of
interest. Borrowings under the Credit Facility bear interest at a fluctuating
rate that is tied to an adjusted base rate or LIBOR, at our option. Any increase
in this interest rate can have an adverse impact on our results of operations
and cash flow. Based on borrowings outstanding at December 31, 2020 (Successor),
a 100-basis-point change in interest rates would change our annualized interest
expense by approximately $2.5 million .
In connection with our hedging activity, we have exposure to financial
institutions in the form of derivative transactions. The counterparties on our
derivative instruments currently in place have investment-grade credit ratings.
We expect that any future derivative transactions we enter into will be with
these counterparties or our lenders under our Successor Credit Agreements that
will carry an investment-grade credit rating.
We are also subject to credit risk due to concentration of our oil and natural
gas receivables with certain significant customers. The inability or failure of
our significant customers to meet their obligations to us or their insolvency or
liquidation may adversely affect our financial results. We review the credit
rating, payment history and financial resources of our customers, but we do not
require our customers to post collateral.
Item 8. Financial Statements and Supplementary Data.
The financial statements and supplementary information required by this Item
appears starting on page F-1 of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
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