LONESTAR RESOURCES US INC. The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements (the "Unaudited Condensed Consolidated Financial Statements") and Notes to Unaudited Condensed Consolidated Financial Statements included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year endedDecember 31, 2020 , as supplemented by our amendment on Form 10-K/A filed with theSEC onApril 30, 2021 (the "Form 10-K"), along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. 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 the 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 than our forward-looking statements. Certain prior-period financial statements are not comparable to our current-period 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 is an independent oil and natural gas company focused on the exploration, development and production of unconventional oil, natural gas liquids and natural gas in theEagle Ford Shale play in South Texas.Penn Virginia Merger OnJuly 12, 2021 , Penn Virginia Corporation ("Penn Virginia") and Lonestar announced that they entered into a definitive merger agreement, or (the "Merger Agreement"), pursuant to which Penn Virginia will acquire Lonestar in an all-stock transaction. Under the terms of the Merger Agreement, Lonestar's shareholders will receive 0.51 shares of Penn Virginia for each of the Company's shares. The transaction is expected to close in the second half of 2021, subject to the satisfaction of customary closing conditions, including obtaining the requisite shareholder and regulatory approvals. The transaction has been unanimously approved by the Boards of Directors of both companies. Consummation of the merger is subject to satisfaction of customary conditions. The Merger Agreement contains certain termination rights for both Lonestar and Penn Virginia, including, among others, if the merger is not completed byNovember 26, 2021 . On a termination of the Merger Agreement under certain circumstances, Penn Virginia may be required to pay Lonestar a termination fee of$6 million , or Lonestar may be required to pay Penn Virginia a termination fee of$3 million . 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 were 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. 17 --------------------------------------------------------------------------------
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); •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); and •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 Accounting Standards Codification ("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 During the first half and throughearly-August 2021 , the oil and natural gas industry has experienced continued improvement in commodity prices as compared to the same period in 2020, primarily resulting from (i) improvements in oil demand as the impact from COVID-19 has begun to abate (although, as ofearly-August 2021 , theCOVID-19 Delta variant was showing significant spread globally causing uncertainty regarding future economic impacts) and (ii) actions taken by theOrganization of Petroleum Exporting Countries ,Russia and certain other oil-exporting countries ("OPEC+") to reduce the worldwide supply of oil through coordinated production cuts. As a result, West Texas Intermediate ("WTI") oil prices have increased from$48.52 per barrel atDecember 31, 2020 to as high as$73.95 per barrel inlate-July 2021 . Prices for natural gas and NGLs were also much higher during the first half and throughearly-August 2021 than they were for the same period in 2020. While oil prices have continued to improve in 2021, the general outlook for the oil and natural gas industry for the remainder of the year remains uncertain, and we can provide no assurances as to when or to what extent economic disruptions resulting from COVID-19 and the corresponding decreases in oil demand may impact the Company. 18 -------------------------------------------------------------------------------- Operational Highlights for the Second Quarter of 2021 As a result of Lonestar filing for bankruptcy and emerging from bankruptcy onNovember 30, 2020 , our financial results are broken out between the Predecessor periods (the three and six months endedJune 30, 2020 ) and the Successor periods (the three and six months endedJune 30, 2021 ). For the three months endedJune 30, 2020 (Predecessor), we recognized a net loss of$42.9 million attributable to common shareholders, and for the three months endedJune 30, 2021 (Successor), we recognized a net loss of$17.8 million . Operational highlights for the second quarter of 2021 included the following: •Brought four gross wells online during the quarter and an additional three drilled-but-uncompleted wells at our Hawkeye properties; •Increased production by 14% from the first quarter of 2021; •Continued to focus on reduced operating expenses. Lease operating expenses were$3.65 per BOE for the quarter while gas gathering, processing and transportation came in at$1.65 per BOE; and •Continued to build our commodities hedge portfolio to protect our operations from downside price risk. As ofAugust 9, 2021 , we had oil hedges covering 5,525 Bbls per day for the remainder of 2021, 3,060 Bbls per day for 2022 and 2,360 Bbls per day for 2023. In addition, on that date, we had natural gas hedges covering 19,365 MMBtu per day of natural gas for the remainder of 2021, 13,745 MMBtu per day for 2022 and 8,743 MMBtu per day for the first half of 2023. The primary drivers of our financial net loss for the three months endedJune 30, 2021 (Successor) included: •Revenues totaling$46.0 million , comprised of 11,855 BOE per day of production during the quarter with$42.66 per BOE of realized sales price before any hedging effects, and •Losses on our commodity hedges of$39.9 million for the quarter, comprised of$10.8 million of realized losses and$29.1 million of unrealized losses. The following reflects some of the primary drivers for our change in operating results between the second quarter of 2021 and the comparative period in 2020: •Oil and natural gas revenues increased by$28.8 million (167%), due to a 199% increase in commodity prices partially offset by a 33% decrease in production. During the second quarter of 2020, we had a significant amount of production shut-in due to historically low commodity prices; •Lease operating expenses slightly decreased by$0.1 million (2%), primarily due to lower production volumes in the current quarter; •Commodity derivative expense increased by$18.8 million ($39.9 million of expense during the second quarter of 2021 compared to$21.1 million of income during the second quarter of 2020); and •Interest expense decreased significantly between the periods as a result of the extinguishment of the Predecessor 11.25% Senior Notes (discussed further below) on the Effective Date. Depreciation, depletion and amortization ("DD&A") expense was also significantly lower between the periods as a result of the fresh start accounting (discussed above), which also occurred on the Effective Date. 19 -------------------------------------------------------------------------------- RESULTS OF OPERATIONS Certain of our operating results and statistics for the three and six months endedJune 30, 2021 and 2020 are summarized below: Successor Predecessor Successor Predecessor Three Months Six Months In thousands, except per share and unit Ended June 30, Three Months Ended Ended June 30, Six Months Ended data 2021 June 30, 2020 2021 June 30, 2020 Operating results Net loss attributable to common stockholders$ (17,817) $ (42,901) $ (24,139) $ (155,950) Net loss per common share - basic(1) (1.77) (1.70) (2.40) (6.20) Net loss per common share - diluted(1) (1.77) (1.70) (2.40) (6.20) Net cash provided by operating activities 25,514 16,576 27,397 30,411 Revenues Oil$ 36,369 $ 11,976$ 64,234 $ 41,986 NGLs 4,940 1,762 9,239 4,362 Natural gas 4,718 3,482 12,365 7,902 Total revenues$ 46,027 $ 17,220$ 85,838 $ 54,250 Total production volumes by product Oil (Bbls) 566,379 579,179 1,066,377 1,237,680 NGLs (Bbls) 219,247 267,462 414,935 570,933 Natural gas (Mcf) 1,759,213 2,203,209 3,188,404 4,313,625 Total barrels of oil equivalent (6:1) 1,078,828 1,213,843 2,012,713 2,527,551 Daily production volumes by product Oil (Bbls/d) 6,224 6,365 5,859 6,800 NGLs (Bbls/d) 2,409 2,939 2,280 3,137 Natural gas (Mcf/d) 19,332 24,211 17,519 23,701 Total barrels of oil equivalent (BOE/d) 11,855 13,339 11,059 13,888 Average realized prices Oil ($ per Bbl)$ 64.21 $ 20.16$ 60.24 $ 33.92 NGLs ($ per Bbl) 22.53 6.59 22.27 7.64 Natural gas ($ per Mcf) 2.68 1.58 3.88 1.83 Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE) 42.66 14.19 42.65 21.46 Total oil equivalent, including the effect from commodity derivatives ($ per BOE) 32.65 31.22 34.59 32.88 Operating and other expenses Lease operating$ 3,933 $ 4,028$ 8,379 $ 11,667 Gas gathering, processing and transportation 1,520 875 3,062 3,025 Production and ad valorem taxes 2,497 1,721 4,917 4,091 Depreciation, depletion and amortization 5,860 16,575 11,169 40,929 General and administrative 5,962 5,981 9,939 8,856 Interest expense 4,323 10,512 8,430 22,122 Operating and other expenses per BOE Lease operating$ 3.65 $ 3.32$ 4.16 $ 4.62 Gas gathering, processing and transportation 1.41 0.72 1.52 1.20 Production and ad valorem taxes 2.31 1.42 2.44 1.62 Depreciation, depletion and amortization 5.43 13.65 5.55 16.19 General and administrative 5.53 4.93 4.94 3.50 Interest expense 4.01 8.66 4.19 8.75
(1) Basic and diluted earnings per share are calculated using the two-class method. See Footnote 1. Basis of Presentation in the Notes to Unaudited Condensed Consolidated Financial Statements included in Item 1.
20
--------------------------------------------------------------------------------Production
The table below summarizes our production volumes for the three and six months
ended
Successor Predecessor Successor Predecessor
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Oil (Bbls/d) 6,224 6,365 5,859 6,800
NGLs (Bbls/d) 2,409 2,939 2,280 3,137
Natural gas (Mcf/d) 19,332 24,211 17,519 23,701
Total (BOE/d) 11,855 13,339 11,059 13,888
Total production during the second quarter of 2021 averaged 11,855 BOE per day,
a decrease of 11%, or 1,484 BOE per day, compared to the same period in 2020.
This decrease was primarily driven by slower development of our Eagle Ford
acreage starting in the second half of 2020 as a result of lower commodity
pricing and the Company conserving liquidity during its restructuring, partially
offset by the shutting in of a significant amount of production (which effected
average daily production for the quarter by approximately 1,700 BOE per day) in
our oil-rich Central Eagle Ford region during late April through the end of May
2020 both in response to lower commodity prices at the time. Total production
during the first six months of 2021 averaged 11,059 BOE per day, a decrease of
20%, or 2,829 BOE per day, compared to the same period in 2020.
Our production during the second quarter of 2021 was 73% oil and NGLs, compared
to 70% during the second quarter of 2020.
Oil, Natural Gas Liquid and Natural Gas Revenues
The table below summarizes our production revenues for the three and six months
ended June 30, 2021 and 2020:
Successor Predecessor Successor Predecessor
Three Months
Ended June Three Months Ended Six Months Ended Six Months Ended
In thousands 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Oil $ 36,369 $ 11,976 $ 64,234 $ 41,986
NGLs 4,940 1,762 9,239 4,362
Natural gas 4,718 3,482 12,365 7,902
Total revenues $ 46,027 $ 17,220 $ 85,838 $ 54,250
Our oil, NGL and natural gas revenues during the three months ended June 30,
2021 increased $28.8 million , or 167%, compared to those revenues for the same
period in 2020. For the six months ended June 30, 2020 , our oil, NGL and natural
gas revenues increased $31.6 million , or 58%, compared to the same period in
2020. The changes in our oil, NGL and natural gas revenues are due to changes in
production quantities and commodity prices (excluding any impact of our
commodity derivative contracts), as reflected in the following table:
Three Months Ended June 30, 2021 vs 2020 Six Months Ended June 30, 2021 vs 2020
(Decrease) Percentage (Decrease) Percentage
Increase in (Decrease) Increase Increase in (Decrease) Increase
In thousands Revenues in Revenues Revenues in Revenues
Change in oil, NGL and natural gas
revenues due to:
Decrease in production $ (1,916) (11) % $ (11,050) (20) %
Increase in commodity prices 30,723 177 % 42,638 79 %
Total change in oil, NGL and natural gas
revenues $ 28,807 166 % $ 31,588 58 %
21-------------------------------------------------------------------------------- Excluding the impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three and six months endedJune 30, 2021 and 2020: Successor Predecessor Successor Predecessor Three Months Ended Three Months Ended Six Months Ended Six Months Ended June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Average net realized price Oil ($/Bbl) $ 64.21 $ 20.16$ 60.24 $ 33.92 NGLs ($/Bbls) 22.53 6.59 22.27 7.64 Natural gas ($/Mcf) 2.68 1.58 3.88 1.83 Total ($/BOE) 42.66 14.19 42.65 21.46 Average NYMEX differentials Oil per Bbl $ (1.85) $ (7.17)$ (1.71) $ (3.09) Natural gas per Mcf (0.26) (0.13) 0.66 0.02 Variations in our average NYMEX oil differential are generally caused by variations of certain of the pricing components included in our pricing formulae, which are industry standards. The significant improvement in our oil differential between the second quarter of 2021 and 2020 reflects overall stabilization in the market, which was experiencing historical upheaval last year in light of the effects of the COVID-19 pandemic and OPEC+ production decisions. Variations in 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 variations are seldom more than$0.20 per MMBtu above or below NYMEX price. The natural gas differential for the six months endedJune 30, 2021 (Successor) includes the benefit of abnormally high realizations achieved inFebruary 2021 resulting from higher gas residue prices during Winter Storm Uri. Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be large, these differentials are seldom more than a dollar above or below NYMEX price. Commodity Derivative Contracts We utilize oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future production and to provide more certainty to our future cash flows. These contracts have historically consisted of fixed-price swaps, collars and basis swaps. The following table summarizes the net cash (payments) receipts on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the three and six months endedJune 30, 2021 and 2020: Three Months Ended June 30, Six Months Ended June 30, 2021 2020 2021 2020 In thousands, except price Net realized Net realized Net realized Net realized impact settlements Price impact settlements Price impact settlements Price impact settlements Price impact (Payments) receipts on settlements of oil derivatives$ (8,542) $ (8.01) $ 21,400 $ 36.95 $ (11,963) $ (21.12) $ 21,261 $ 17.18 Receipts on settlements of natural gas derivatives 58 0.02 1,491 0.68 714 0.41 2,455 0.57 Total net commodity derivative settlements$ (8,484) $ 22,891 $ (11,249) $ 23,716 22
-------------------------------------------------------------------------------- Our realized net loss on commodity derivative contracts was$10.8 million and$16.2 million for the three and six months endedJune 30, 2021 (Successor), respectively, compared to net realized gain of$20.5 million and$28.7 million for the three and six months endedJune 30, 2020 (Predecessor), respectively. We realized an average loss of$10.01 and$8.06 per BOE on our oil and natural gas swaps during the three and six months endedJune 30, 2021 (Successor), respectively, as compared to an average gain of$17.03 and$11.42 per BOE for the three and six months endedJune 30, 2020 (Predecessor), respectively. In order to provide a level of price protection to a portion of our oil production and to meet certain hedging requirements under our Successor Credit Facility (as defined below), we have hedged a portion of our estimated oil and natural gas production in 2021, 2022 and 2023 using NYMEX fixed-price swaps. See Note 2, Commodity Price Risk Activities, to the consolidated financial statements for additional details of our outstanding commodity derivative contracts as ofJune 30, 2021 for additional discussion. The following table summarizes our oil and natural gas derivative contracts as ofAugust 9, 2021 : Q3 2021 Q4 2021 1H 2022 2H 2022 1H 2023 2H 2023 Oil - WTI Volumes Hedged (Bbls/d) 5,650 5,400 3,124 3,000 2,450 2,275 Swap Price$ 46.62 $ 46.03 $ 47.32 $
46.73
Natural Gas -Henry Hub Volumes Hedged (Mcf/d) 18,030 20,700 14,986 12,500 8,743 - Swap Price$ 3.03 $ 3.52 $ 3.19 $ 3.00 $ 3.02 $ - Production Expenses The table below presents detail of production expenses for the three and six months endedJune 30, 2021 and 2020: Successor Predecessor Successor Predecessor Three Months Ended Three Months Ended Six Months Ended Six Months Ended In thousands, except expense per BOE June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020 Production expenses Lease operating $ 3,933 $ 4,028$ 8,379 $ 11,667 Gas gathering, processing and transportation 1,520 875 3,062 3,025 Production and ad valorem taxes 2,497 1,721 4,917 4,091 Depreciation, depletion and amortization 5,860 16,575 11,169 40,929 Production expenses per BOE Lease operating $ 3.65 $ 3.32 $ 4.16 $ 4.62 Gas gathering, processing and transportation 1.41 0.72 1.52 1.20 Production and ad valorem taxes 2.31 1.42 2.44 1.62 Depreciation, depletion and amortization 5.43 13.65 5.55 16.19 Lease Operating and Gas Gathering, Processing and Transportation 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. 23 -------------------------------------------------------------------------------- Total lease operating expense was$3.9 million and$8.4 million , or$3.65 and$4.16 per BOE, for the three and six months endedJune 30, 2021 (Successor), respectively, compared to$4.0 million and$11.7 million , or$3.32 and$4.62 per BOE, during the Predecessor's same respective periods in 2020. Total gas gathering, processing and transportation expense was$1.5 million and$3.1 million , or$1.41 and$1.52 per BOE for the three and six months endedJune 30, 2021 (Successor), respectively, compared to$0.8 million and$3.0 million , or$0.72 and$1.20 per BOE, during the Predecessor's same respective periods in 2020. The slight decrease in lease operating expense on an absolute-dollar basis were primarily due lower production in the current quarter. Production and Ad Valorem Taxes Production 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
the three and six months ended
Successor Predecessor Successor Predecessor
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
In thousands June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Production taxes $ 1,826 $ 729 $ 3,580 $ 2,055
Ad valorem taxes 671 992 1,337 2,036
Total production and ad valorem tax
expense $ 2,497 $ 1,721 $ 4,917 $ 4,091
Total production taxes were $1.8 million and $3.6 million , or $1.69 and $1.78
per BOE, for the three and six months ended June 30, 2021 (Successor),
respectively, compared to $0.7 million and $2.1 million , or $0.60 and $0.81 per
BOE, during the Predecessor's same respective periods in 2020. Total ad valorem
taxes were $0.7 million and $1.4 million , or $0.62 and $0.66 per BOE for the
three and six months ended June 30, 2021 (Successor), respectively, compared to
$1.0 million and $2.0 million , or $0.82 and $0.81 per BOE, during the
Predecessor's same respective periods in 2020. Higher production taxes in the
current periods are due to higher associated commodity prices.
Depreciation, Depletion and Amortization
The table below provides detail of our depreciation, depletion and amortization
("DD&A") expense for the three and six months ended June 30, 2021 and 2020.
Successor Predecessor Successor Predecessor
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
In thousands June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Depletion of proved oil and gas
properties $ 5,339 $ 15,925 $ 10,072 $ 39,607
Depreciation of other property and
equipment 301 383 638 746
Accretion of asset retirement
obligations 220 267 459 576
Total DD&A expense $ 5,860 $ 16,575 $ 11,169 $ 40,929
Capitalized costs attributed to our proved properties are subject to
depreciation and depletion calculated using the unit-of-production method. 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 three to five years.
24
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Total DD&A expense was $5.9 million and $11.2 million , or $5.43 and $5.55 per
BOE, for the three and six months ended June 30, 2021 (Successor), respectively,
compared to $16.6 million and $40.9 million , or $13.65 and $16.19 per BOE,
during the Predecessor's same respective periods in 2020. The decreases in the
current periods are attributable to 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 .
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 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. There were no material changes to our key cash flow
assumptions and no triggering events since December 31, 2020 ; therefore, no
impairment was identified during the second quarter of 2021.
General and Administrative
Total general and administrative ("G&A") expense was $6.0 million and $9.9
million , or $5.53 and $4.94 per BOE, for the three and six months ended June 30,
2021 (Successor), respectively, compared to $6.0 million and $8.9 million , or
$4.93 and $3.50 per BOE, for the three and six months ended June 30, 2020
(Predecessor), respectively. G&A includes approximately $1.2 million of
professional fees residual to the Company's restructuring in 2020, including
legal, consulting and accounting fees incurred as part of the Company's
fresh-start accounting process for the six months ended June 30, 2021
(Successor). G&A for the three months ended June 30, 2021 (Successor) includes
stock-based compensation expense of $1.4 million attributable to our management
incentive plan implemented in April 2021 . G&A for the three and six months ended
June 30, 2020 (Predecessor) includes stock-based compensation gains of $1.8
million . On the Effective Date, all of the Predecessor's stock-based
compensation plans were cancelled.
Interest Expense
The table below provides detail of the interest expense for our various
long-term obligations for the three and six months ended June 30, 2021 and 2020:
Successor Predecessor Successor Predecessor
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
In thousands June 30, 2021 June 30, 2020 June 30, 2021 June 30, 2020
Interest expense on Successor Credit
Facility $ 3,130 $ - $ 6,032 $ -
Interest expense on Successor Term
Loan Facility 718 - 1,441 -
Interest expense on Predecessor 11.25%
Senior Notes - 7,031 - 14,062
Interest expense on Predecessor Credit
Facility - 2,664 - 6,356
Other interest expense 83 211 172 329
Total cash interest expense (1) $ 3,931 $ 9,906 $ 7,645 $ 20,747
Amortization of debt issuance costs
and discounts 392 606 785 1,375
Total interest expense $ 4,323 $ 10,512 $ 8,430 $ 22,122
Per BOE:
Total cash interest expense $ 3.64 $ 8.16 $ 3.80 $ 8.21
Total interest expense 4.01 8.66 4.19 8.75
(1) Cash interest is presented on an accrual basis.
25
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Total cash interest expense was $3.9 million and $7.6 million , or $3.64 and
$3.80 per BOE, for the three and six months ended June 30, 2021 (Successor),
respectively, compared to $9.9 million and $20.7 million , or $8.16 and $8.21 per
BOE, during the Predecessor's same respective periods in 2020. 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.
See Note 6. Long-Term Debt in Notes to the Unaudited Condensed Consolidated
Financial Statements for additional information about our long-term debt and
interest expense.
Income Taxes
The following table provides further detail of our income taxes for the three
and six months ended June 30, 2021 and 2020:
Successor Predecessor Successor Predecessor
Three Months
In thousands, except per-BOE amounts Ended June 30, Three Months Ended Six Months Ended Six Months Ended
and tax rates 2021 June 30, 2020 June 30, 2021 June 30, 2020 Current income tax benefit (expense) $ - $ 4,332 $ (160)$ 4,756 Deferred income tax benefit - - - 931 Total income tax benefit (expense) $ - $ 4,332 $ (160)$ 5,687 Average income tax benefit (expense) per BOE $ - $ 3.57$ (0.08) $ 2.25 Effective tax rate - % 9.6 % (0.7) % 15.8 % 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 atJune 30, 2021 . 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, we recorded a total valuation allowance of$42.5 million on our underlying deferred tax assets as ofJune 30, 2021 . For the three and six months endedJune 30, 2021 (Successor), 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 atJune 30, 2020 (Predecessor) primarily due to tax consequences of the impairment of our proved properties during the first quarter of 2020; as a result, we recorded a full valuation allowance of$40.1 million atJune 30, 2020 due to uncertainties regarding the future realization of our deferred tax assets. 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 three and six months endedJune 30, 2021 (Successor) and 2020 (Predecessor). 26 -------------------------------------------------------------------------------- CAPITAL 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 (as defined below). 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 Predecessor Credit Facility (as defined below) 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. Currently, our availability under the Successor Credit Facility is$15.0 million and we are required to make two more quarterly pay-downs on our Successor Term Loan which will total an additional$10.0 million by the end of 2021. Cash flows for the six months endedJune 30, 2021 and 2020 are presented below: Successor Predecessor Six Months ended Six Months Ended In thousands June 30, 2021 June 30, 2020 Net cash provided by (used in): Operating activities $ 27,397$ 30,411 Investing activities (22,777) (72,337) Financing activities (10,121) 40,048 Net change in cash $ (5,501)$ (1,878) Net Cash Provided by Operating Activities Net cash provided by operating activities was$27.4 million for six months endedJune 30, 2021 (Successor), compared to$30.4 million for the six months endedJune 30, 2020 (Predecessor). The lower current year amount is primarily due to a$36.4 million negative swing in cash hedge settlements between the two periods, largely offset by higher production revenues in the current period as discussed above.Net Cash Used in Investing Activities Net cash used in investing activities was$22.8 million for the six months endedJune 30, 2021 (Successor), compared to$72.3 million for the six months endedJune 30, 2020 (Predecessor). This decrease is primarily due to lower drilling and development costs in the current period, as we did not resume our one-rig drilling program untilFebruary 2021 versus the two-rig program we were running throughout the Predecessor period.Net Cash Used in Financing Activities Net cash used by financing activities was$10.1 million for the six months endedJune 30, 2021 (Successor), compared to$40.0 million provided by financing activities for the six months endedJune 30, 2020 (Predecessor). This decrease primarily resulted from no borrowings on the credit line offset by the quarterly$5.0 million pay-downs we made on our Successor Term Loan in 2021. 27 --------------------------------------------------------------------------------
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 and theMay 1 redetermination was completed inAugust 2021 , which also reaffirmed the$225 million borrowing base. 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. 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 5.5% for the three and six months endedJune 30, 2021 . The undrawn portion of the aggregate lender commitments under the Successor Credit Facility is subject to a commitment fee of 1.0%. As ofJune 30, 2021 , the Successor was in compliance with all debt covenants under the Successor Credit Facilities. First Amendment EffectiveAugust 6, 2021 , we entered into the First Amendment and Borrowing Base Agreement (the "First Amendment"), which reaffirmed the$225 million borrowing base for the Successor Credit Facility pursuant to the scheduledMay 1 redetermination and amended certain required swap agreements.
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. 28 --------------------------------------------------------------------------------
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. Capital Expenditures The table below summarizes our cash capital expenditures incurred for the six months endedJune 30, 2021 : In thousands Six Months EndedJune 30 ,
2021
Acquisition of oil and gas properties $
1,612
Development of oil and gas properties
21,489
Purchases of other property and equipment
13
Total capital expenditures $
23,114
For the six months endedJune 30, 2021 , our capital expenditures were funded with cash flow from operations. As noted above, cash payments for capital expenditures were lower this quarter as we ran one drilling rig this period starting inFebruary 2021 versus running two rigs throughout the first half of 2020. 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. In addition, pursuant to the Merger Agreement with Penn Virginia discussed above, certain capital expenditures which exceed the capital budget approved by the Lonestar Board of Directors, asset sales and acquisitions must be approved by Penn Virginia prior to being incurred going forward. Critical Accounting Policies and Estimates The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We analyze our estimates and judgments, including those related to oil, NGLs and natural gas revenues, oil and natural gas properties, impairment of long-lived assets, fair value of derivative instruments, asset and retirement obligations and income taxes, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary from our estimates. The policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management are summarized in the Management's Discussion and Analysis of Financial Condition and Results of Operations section of our Form 10-K. As ofJune 30, 2021 , there were no significant changes to any of our critical accounting policies and estimates. Cautionary Note Regarding Forward-looking Statements This Quarterly Report on Form 10-Q statement contains forward-looking statements that are subject to a number of known and unknown risks, uncertainties, and other important factors, many of which are beyond our control. We intend such forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 29 -------------------------------------------------------------------------------- These forward-looking statements include, among others, statements regarding: •our growth strategies; •our ability to explore for and develop oil and gas resources successfully and economically; •our drilling and completion techniques; •our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; •our estimates regarding timing and levels of production; •changes in working capital requirements, reserves, and acreage; •commodity price risk management activities and the impact on our average realized prices; •anticipated trends in our business and industry; •availability of pipeline connections and water disposal on economic terms; •effects of competition on us; •our future results of operations; •profitability of drilling locations; •our reputation as an operator and our relationships and contacts in the market; •our liquidity, our ability to continue as a going concern and our ability to finance our exploration and development activities, including accessibility of borrowings under our senior secured credit facility, our borrowing base, and the result of any borrowing base redetermination; •our ability to maintain compliance with covenants and ratios under our senior secured credit facility; •our planned expenditures, prospects and capital expenditure plan; •future market conditions in the oil and gas industry; •our ability to make, integrate and develop acquisitions and realize any expected benefits or effects of completed acquisitions; •the benefits, effects, availability of and results of new and existing joint ventures and sales transactions; •our ability to maintain a sound financial position; •receipt of receivables, drilling carry and proceeds from sales; •our ability to complete planned transactions on desirable terms; •the impact of governmental regulation, taxes, market changes and world events; and •global or national health concerns, including health epidemics such as the ongoing coronavirus outbreak beginning in early 2020. 30 -------------------------------------------------------------------------------- All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A. Risk Factors, Item 8. Financial Statements and Supplementary Data and elsewhere in our Form 10-K, and Part I. Financial Information, Item 1A. Risk Factors and elsewhere in this Quarterly Report on Form 10-Q. These important factors include risks related to: • variations in the market demand for, and prices of, crude oil, NGLs and natural gas; • proved reserves or lack thereof; • estimates of crude oil, NGLs and natural gas data; • the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing to fund our operations; • borrowing capacity under our credit facility; • general economic and business conditions; • failure to realize expected value creation from property acquisitions; • uncertainties about our ability to find, develop or acquire additional oil and natural gas resources; • uncertainties with regard to our drilling schedules; • the expiration of leases on our undeveloped leasehold assets; • our dependence upon several significant customers for the sale of most of our crude oil, natural gas and NGL production; • counterparty credit risks; • competition within the crude oil and natural gas industry; • technology risks; • the geographic concentration of our operations; • drilling results; • potential financial losses or earnings reductions from our commodity price risk management programs; • potential adoption of new governmental regulations; • our ability to satisfy future cash obligations and environmental costs; and • the other factors set forth under Risk Factors in Item 1A of Part I of our Form 10-K. The forward-looking statements relate only to events or information as of the date on which the statements are made in this Quarterly Report on Form 10-Q. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events. 31
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