The following discussion and analysis of the financial condition and results of operations ofRanger Oil Corporation and its consolidated subsidiaries ("Ranger," "Ranger Oil ," the "Company," "we," "us" or "our") should be read in conjunction with our condensed consolidated financial statements and notes thereto included in Part I, Item 1, "Financial Statements." All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain statistics for the prior period have been reclassified to conform to the current period presentation. References to "quarters" represent the three months endedSeptember 30, 2021 or 2020, as applicable. Overview and Executive Summary We are an independent oil and gas company focused on the onshore development and production of crude oil, natural gas liquids ("NGLs"), and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in theEagle Ford Shale inSouth Texas . Recent Developments Acquisition ofLonestar Resources OnOctober 5, 2021 , the Company acquired Lonestar Resources US Inc., aDelaware corporation ("Lonestar"), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries ofRanger Oil (the "Merger"). Lonestar's oil and gas properties are located in theEagle Ford Shale inSouth Texas . In accordance with the terms of the Merger, Lonestar shareholders received 0.51 shares ofPenn Virginia Corporation ("Penn Virginia") common stock for each share of Lonestar common stock held immediately prior to the effective time of the Merger. Based on the closing price of Penn Virginia common stock onOctober 5, 2021 of$30.19 , the total value of Penn Virginia common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately$173.6 million . Following the completion of the Merger, the Company changed its name from Penn Virginia toRanger Oil Corporation , and its Class A common stock ("Class A Common Stock") began trading on the Nasdaq under the ticker symbol "ROCC" onOctober 18, 2021 . As the Merger was completed after the quarterly period endedSeptember 30, 2021 , our results exclude Lonestar's financial information and operating results for all periods presented and discussed herein. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information. Financing Updates 9.25% Senior Notes due 2026 OnAugust 10, 2021 , our indirect, wholly-owned subsidiaryPenn Virginia Escrow LLC (the "Escrow Issuer") completed an offering of$400 million aggregate principal amount of senior unsecured notes due 2026 (the "9.25% Senior Notes due 2026"). These notes bear interest at 9.25% and were sold at 99.018% of par. Debt Repayments In connection with the consummation of the Merger, the net proceeds from the offering of$400 million aggregate principal amount of 9.25% Senior Notes due 2026 and certain additional funds totaling$411.5 million were released from escrow onOctober 5, 2021 . Obligations under the 9.25% Senior Notes due 2026 were assumed by Holdings, as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee our credit agreement (the "Credit Facility"). The net proceeds from the 9.25% Senior Notes due 2026 were used to repay and discharge$249.8 million of Lonestar's long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of$146.2 million was used to repay the Second Lien Credit Agreement, dated as ofSeptember 29, 2017 (the "Second Lien Facility") including a prepayment premium and accrued interest and related expenses. Increased Borrowing Base of Credit Facility Upon closing of the Merger, our borrowing base under the Credit Facility increased to$600 million with aggregate elected commitments of$400 million . See Note 7 and Note 14 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information on our debt. Hedging Update 26
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Immediately following the Merger, we paid approximately$50 million to restructure certain of Lonestar's derivatives, which was funded by borrowings under our Credit Facility. We have reset the majority of the swaps to reflect current market pricing. 27
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Recapitalization of the Company's Common Stock OnOctober 6, 2021 , the Company effected a recapitalization (the "Recapitalization"), pursuant to which (i) the Company's common stock was renamed and reclassified as Class A common stock, (ii) the authorized number of shares of capital stock of the Company was increased to 145,000,000 shares, (iii) 30,000,000 shares of Class B common stock, par value of$0.01 per share ("Class B Common Stock"), a new class of capital stock of the Company, was authorized, (iv) all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information.Strategic Investment by Juniper InJanuary 2021 , we consummated the Juniper Transactions whereby affiliates of Juniper contributed$150 million in cash and certain oil and gas assets inLavaca andFayette Counties inTexas to us in exchange for equity that entitles Juniper to both vote and share in any dividend on the same basis as 22,548,998 shares of common stock (after post-closing adjustments). For additional information regarding the Juniper Transactions, see Note 3 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements." Industry Environment and Recent Operating and Financial Highlights Commodity Price and Other Economic Conditions As an oil and gas development and production company, we are exposed to a number of risks and uncertainties that are inherent to our industry. In addition to such industry-specific risks, the global public health crisis associated with the novel coronavirus ("COVID-19") continues to create uncertainty for global economic activity. Over the past 18 months, the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy beginning inMarch 2020 , which directly impacted our industry and the Company. Most recently, however, increased mobility and other factors has resulted in increased oil demand and commodity prices. In addition, there remains a high level of uncertainty regarding the volatility of energy supply and demand as theOrganization of the Petroleum Exporting Countries ("OPEC") andRussia (together withOPEC , collectively "OPEC+") reached an agreement inJuly 2021 to increase production over this past quarter. In earlyOctober 2021 , OPEC+ reconfirmed the agreement to boost output during the fourth quarter 2021. Higher energy prices may add to inflationary pressures, which could lead to increased service costs and a slowdown in the economic recovery. Our crude oil production is sold at a premium or deduct differential to the prevailing NYMEX West Texas Intermediate ("NYMEX WTI") price. The differential reflects adjustments for location, quality and transportation and gathering costs, as applicable. In 2021, we sell all of our crude oil volumes under Magellan East Houston ("MEH") pricing, whereas historically our crude oil volumes sold were largely priced using either Light Louisiana Sweet ("LLS"), or MEH grade differentials. While both LLS and MEH have historically been at a premium to NYMEX WTI, LLS has had a more favorable differential than MEH. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and demand relationships in that region or locality. Similar to crude oil, our natural gas production price has a premium or deduct differential to the prevailing NYMEX Henry Hub ("NYMEX HH") price primarily due to differential adjustments for the location and the energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual interaction of supply and demand. A summary of these pricing differentials is provided in the discussion of "Results of Operations - Realized Differentials" that follows. In addition to the volatility of commodity prices, we are subject to inflationary and other factors that could result in higher costs for products, materials and services that we utilize in both our capital projects and with respect to our operating expenses. Where possible, we have taken certain actions with vendors and other service providers to secure products and services at fixed prices and to pay for certain materials and services in advance in order to lock in favorable costs. 28
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Capital Expenditures, Development Progress and Production We currently operate two drilling rigs and during the three and nine months endedSeptember 30, 2021 , incurred capital expenditures of approximately$60.0 million and$182.8 million , respectively, substantially all of which was directed to drilling and completion projects. During the third quarter 2021, a total of 10 gross (9.2 net) wells were drilled, completed and turned in line. As ofOctober 29, 2021 , we turned an additional two gross (1.9 net) wells in line and three gross (2.2 net) wells were completing and seven gross (6.2 net) wells were in progress. Following the Lonestar acquisition onOctober 5, 2021 , we had approximately 174,600 gross (142,600 net) acres in the Eagle Ford, net of expirations, of which approximately 93% is held by production. Total sales volume for the third quarter 2021 was 2,344 thousand barrels of oil equivalent ("Mboe"), or 25,483 barrels of oil equivalent ("boe") per day, with approximately 80%, or 1,879 thousand barrels of oil ("Mbbls"), of sales volume from crude oil, 11% from NGLs and 9% from natural gas. 29
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Commodity Hedging Program As ofOctober 29, 2021 , we have hedged a portion of our estimated future crude oil and natural gas production fromOctober 1, 2021 through the first quarter of 2024. The following table summarizes our net hedge positions for the periods presented: 4Q21 1Q22 2Q22 3Q22 4Q22 1Q23 2Q23 3Q23 4Q23 1Q24 2Q24 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 6,215 3,250 3,000 3,000 3,000 2,500 2,400 2,807 2,657 462 308 Weighted Average Swap Price ($/bbl)$ 72.76 $ 75.16 $ 74.12 $ 73.01 $ 69.20 $ 54.40 $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75 NYMEX WTI Collars Average Volume Per Day (bbl) 16,304 15,417 12,775 7,745 6,114 2,917 2,885 Weighted Average Purchased Put Price ($/bbl)$ 51.40 $ 55.14 $ 52.90 $ 47.37 $ 45.33 $ 40.00 $ 40.00 Weighted Average Sold Call Price ($/bbl)$ 62.23 $ 68.26 $ 71.14 $ 64.60 $ 60.87 $ 50.00 $ 50.00 NYMEX WTI Purchased Puts Average Volume Per Day (bbl) 3,261 Weighted Average Purchased Put Price ($/bbl)$ 55.00 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 11,957 10,000 9,890 3,261 3,261 Weighted Average Swap Price ($/bbl)$ 0.17 $ 0.79 $ 0.79 $ 1.12 $ 1.12 NYMEX HH Swaps Average Volume Per Day (MMBtu) 20,700 17,500 12,500 12,500 12,500 10,000 7,500 Weighted Average Swap Price ($/MMBtu)$ 3.530 $ 3.857 $ 3.342 $ 3.360 $ 3.408 $ 3.346 $ 3.325 NYMEX HH Collars Average Volume Per Day (MMBtu) 9,783 3,333 13,187 13,043 13,043 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price($/MMBtu)$ 2.607 $ 4.150 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price ($/MMBtu)$ 3.117 $ 5.750 $ 3.220 $ 3.220 $ 3.220 $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000 NYMEX HH Sold Puts Average Volume Per Day (MMBtu) 6,522 Weighted Average Sold Put Price ($/MMBtu)$ 2.000 OPIS Mt Belv Ethane Swaps Average Volume per Day (gal) 28,022 27,717 27,717 98,901 34,239 34,239 34,615 Weighted Average Fixed Price ($/gal)$ 0.2500 $ 0.2500 $ 0.2500 $ 0.2288 $ 0.2275 $ 0.2275 $ 0.2275 30
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Results of Operations The following table sets forth certain historical summary operating and financial statistics for the periods presented:
Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, 2021 2021 2020 2021 2020 Total sales volume (Mboe) 1 2,344 2,261 2,235 6,453 6,909 Average daily sales volume (boe/d) 1 25,483 24,844 24,295 23,638 25,214 Crude oil sales volume (Mbbl) 1 1,879 1,831 1,691 5,179 5,291 Crude oil sold as a percent of total 1 80 % 81 % 76 % 80 % 77 % Product revenues$ 140,133 $
123,789
$ 127,995 $
116,314
91 % 94 % 92 % 93 % 93 % Realized prices: Crude oil ($/bbl)$ 68.10 $ 63.54 $ 37.39 $ 62.99 $ 36.05 NGLs ($/bbl)$ 27.24 $ 18.31 $ 9.20 $ 21.21 $ 6.86 Natural gas ($/Mcf)$ 4.11 $ 2.70 $ 1.80 $ 3.23 $ 1.73 Aggregate ($/boe)$ 59.77 $ 54.75 $ 30.70 $ 54.58 $ 29.57 Realized prices, including effects of derivatives, net 2 Crude oil ($/bbl)$ 57.15 $ 52.70 $ 48.28 $ 52.08 $ 51.05 NGLs ($/bbl)$ 25.77 $ 17.87 $ 9.20 $ 20.52 $ 6.86 Natural gas ($/Mcf)$ 3.44 $ 2.71 $ 1.88 $ 3.01 $ 1.86 Aggregate ($/boe)$ 50.49 $ 45.93 $ 38.99 $ 45.63 $ 41.14 Production and lifting costs: Lease operating ($/boe)$ 4.54 $
4.30
$ 2.43 $
2.29
$ 4.66 $
3.09
$ 13.21 $
12.74
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1 All volumetric statistics presented above represent volumes of commodity production that were sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods. 2 Realized prices, including effects of derivatives, net is a non-GAAP measure (see discussion and reconciliation to GAAP measure below in "Results of Operations - Effects of Derivatives" that follows). 3 Includes combined amounts of$1.56 ,$0.43 and$1.20 per boe for the three months endedSeptember 30, 2021 ,June 30, 2021 andSeptember 30, 2020 and$1.82 and$0.65 per boe for the nine months endedSeptember 30, 2021 and 2020, respectively, attributable to share-based compensation and significant special charges related to organizational restructuring and acquisition, divestiture and strategic transaction costs, as described in the discussion of "Results of Operations - General and Administrative" that follows. 31
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Sequential Quarterly Analysis The following summarizes our key operating and financial highlights for the three months endedSeptember 30, 2021 , with comparison to the three months endedJune 30, 2021 . The year-over-year highlights for the quarterly periods endedSeptember 30, 2021 and 2020 are addressed in further detail in the discussions that follow below in Year over Year Analysis of Operating and Financial Results. •Daily sales volume increased marginally to 25,483 boe per day from 24,844 boe per day with 9.2 net wells turned in line for both third quarter 2021 and second quarter 2021. Total sales volume increased 4% to 2,344 Mboe from 2,261 Mboe. •Product revenues increased 13% to$140.1 million from$123.8 million as a result of 7% higher crude oil realized prices, or$8.6 million , coupled with slightly higher crude oil sales volume, or$3.1 million . NGL revenues were higher due to 49% higher realized prices, or$2.3 million , as well as 10% higher sales volume, or$0.4 million . Natural gas revenues were 61% higher as a result of 52% higher realized prices and 6% higher volume for an overall increase of$1.9 million . •Production and lifting costs, consisting of Lease operating expenses ("LOE") and Gathering, processing and transportation expenses ("GPT"), increased on an absolute basis to$16.3 million from$14.9 million and increased on a per unit basis to$6.97 per boe from$6.59 per boe due primarily to the effects of slightly higher sales volume of 4%. •Production and ad valorem taxes increased on an absolute and per unit basis to$7.5 million and$3.21 per boe from$6.7 million and$2.97 per boe, respectively, due to the overall effects of 9% higher aggregate realized product pricing, partially offset by lower estimated ad valorem tax assessments. •General and administrative ("G&A") expenses increased on an absolute and per unit basis to$10.9 million and$4.66 per boe from$7.0 million and$3.09 per boe, respectively, primarily due to$2.7 million of acquisition and integration costs associated with the Lonestar acquisition as well as higher employee compensation costs. •Depreciation, depletion and amortization ("DD&A") increased to$31.0 million and increased on a per unit basis to$13.21 per boe during the third quarter 2021 as compared to$28.8 million and$12.74 per boe during the second quarter 2021 due primarily to lower total proved reserves, partially offset by lower future development cost assumptions. 32
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Year over Year Analysis of Operating and Financial Results Sales Volume The following tables set forth a summary of our total and average daily sales volumes by product for the periods presented: Total Sales Volume 1 Average Daily Sales Volume 1 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Three Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable)
Crude oil (Mbbl and bbl/d) 1,879 1,691 188 20,429 18,383 2,046 NGLs (Mbbl and bbl/d) 263 307 (44) 2,860 3,338 (478) Natural gas (MMcf and MMcf/d) 1,211 1,421 (210) 13 15 (2) Total (Mboe and boe/d) 2,344 2,235 109 25,483 24,295 1,188 2021 vs. 2020
2021 vs. 2020 Nine Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Crude oil (Mbbl and bbl/d) 5,179 5,291 (112) 18,972 19,309 (337) NGLs (Mbbl and bbl/d) 713 917 (204) 2,611 3,347 (736) Natural gas (MMcf and MMcf/d) 3,367 4,206 (839) 12 15 (3) Total (Mboe and boe/d) 6,453 6,909 (456) 23,638 25,214 (1,576)
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1 All volumetric statistics represent volumes of commodity production that were actually sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods. Total sales volume were relatively flat during the third quarter 2021 as compared to the corresponding quarter in 2020 with 9.2 net wells turned in line in the current quarter 2021 period as compared to 4.8 net wells in the corresponding quarter in 2020. Total sales volume decreased 7% during the nine months endedSeptember 30, 2021 when compared to the corresponding period in 2020 as a result of the temporary suspension of the drilling program due to the global economic downturn associated with COVID-19 in 2020 as our overall production levels remained depressed in early 2021. Approximately 80% of total sales volume during the three and nine month periods in 2021 was attributable to crude oil when compared to approximately 76% during the corresponding periods in 2020. The increase in the crude oil composition of total sales volume is due primarily to drilling in the oilier northern and eastern portions of our acreage holdings and focus on development plans with emphasis in such portions. Product Revenues and Prices The following tables set forth a summary of our revenues and prices per unit of volume by product for the periods presented: Total Product Revenues Product Revenues per Unit of Volume 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Three Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) ($ per unit of volume) Crude oil$ 127,995 $ 63,227 $ 64,768 $ 68.10 $ 37.39 $ 30.71 NGLs 7,165 2,824 4,341$ 27.24 $ 9.20 $ 18.04 Natural gas 4,973 2,563 2,410$ 4.11 $ 1.80 $ 2.31 Total$ 140,133 $ 68,614 $ 71,519 $ 59.77 $ 30.70 $ 29.07 2021 vs. 2020 2021 vs. 2020 Nine Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) ($ per unit of volume) Crude oil$ 326,222 $ 190,732 $ 135,490 $ 62.99 $ 36.05 $ 26.94 NGLs 15,115 6,295 8,820$ 21.21 $ 6.86 $ 14.35 Natural gas 10,893 7,273 3,620$ 3.23 $ 1.73 $ 1.50 Total$ 352,230 $ 204,300 $ 147,930 $ 54.58 $ 29.57 $ 25.01 33
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The following table provides an analysis of the changes in our revenues for the periods presented:
Three Months Ended September 30, 2021 vs. 2020 Nine Months Ended September 30, 2021 vs. 2020 Revenue Variance Due to Revenue Variance Due to Volume Price Total Volume Price Total Crude oil$ 7,038 $ 57,730 $ 64,768 $ (4,014) $ 139,504 $ 135,490 NGLs (405) 4,746 4,341 (1,403) 10,223 8,820 Natural gas (379) 2,789 2,410 (1,450) 5,070 3,620$ 6,254 $ 65,265 $ 71,519 $ (6,867) $ 154,797 $ 147,930 Our product revenues during the three and nine month periods in 2021 increased compared to the corresponding periods in 2020 due primarily to significantly higher prices and the continued economic recovery following the easing of COVID-19 restrictions as compared to the prior year that resulted in increases to the NYMEX WTI benchmark price of 70% for the three and nine month periods, as well as an increase of 11% in crude oil volume in the three month period, partially offset by lower NGL and natural gas volume. Total crude oil revenues remain over 90% of our total product revenues during both the three and nine month periods in 2021 and 2020. Realized Differentials The following table reconciles our realized price differentials from average NYMEX-quoted prices for WTI crude oil and HH natural gas for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Realized crude oil prices ($/bbl)$ 68.10 $ 37.39 $ 30.71$ 62.99 $ 36.05 $ 26.94 Average WTI prices 70.52 41.40 29.12 65.04 38.37 26.67 Realized differential to WTI$ (2.42) $ (4.01) $ 1.59$ (2.05) $ (2.32) $ 0.27 Realized natural gas prices ($/Mcf)$ 4.11 $ 1.80 $ 2.31$ 3.23 $ 1.73 $ 1.50 Average HH prices ($/MMBtu) 4.27 1.95 2.32 3.52 1.82 1.70 Realized differential to HH$ (0.16) $ (0.15) $ (0.01)$ (0.29) $ (0.09) $ (0.20) Beginning inMarch 2020 , the adverse impact of COVID-19 and instability in the global energy markets effectively eliminated our premium margin to the NYMEX WTI index price for crude oil. Average NYMEX WTI crude oil prices have rebounded as stabilization continued, with crude oil averaging approximately$70 per bbl for the third quarter 2021. Our differential to NYMEX WTI for the three month period in 2021 compared to the corresponding period in 2020 is primarily due to the change during 2020 from selling our production volumes based on LLS and MEH pricing to selling fully based on MEH pricing. While both LLS and MEH have historically been at a premium to NYMEX WTI, MEH is less of a premium than LLS. Beginning inMarch 2020 , average NYMEX HH prices were also impacted by COVID-19 and the overall industry instability noted above, as well as by the colder than normal weather during first quarter 2021 that affected most of the Lower 48 states and caused significant natural gas supply and demand imbalances. Recently, demand has rebounded while supply is constrained, causing a significant increase in natural gas prices compared to the prior year as noted in the table above. See also the discussion of Commodity Price and Other Economic Conditions in the Overview above. Effects of Derivatives We present realized prices for crude oil, natural gas liquids and natural gas, as adjusted for the effects of derivatives, net as we believe these measures are useful to management and stakeholders in determining the effectiveness of our price-risk management program that is designed to reduce the volatility associated with our operations. Realized prices for crude oil, natural gas liquids and natural gas, as adjusted for the effects of derivatives, net, are supplemental financial measures that are not prepared in accordance with generally accepted accounting principles ("GAAP"). 34
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The following table presents the calculation of our non-GAAP realized prices for crude oil, natural gas liquids and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil, natural gas liquids and natural gas determined in accordance with GAAP: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Realized crude oil prices ($/bbl)$ 68.10 $ 37.39 $ 30.71$ 62.99 $ 36.05 $ 26.94 Effects of derivatives, net ($/bbl) (10.95) 10.89 (21.84) (10.91) 15.00 (25.91) Crude oil realized prices, including effects of derivatives, net ($/bbl)$ 57.15 $ 48.28 $ 8.87$ 52.08 $ 51.05 $ 1.03 Realized natural gas liquid prices ($/bbl)$ 27.24 $ 9.20 $ 18.04$ 21.21 $ 6.86 $ 14.35 Effects of derivatives, net ($/bbl) (1.47) - (1.47) (0.69) - (0.69) Natural gas liquids realized prices, including effects of derivatives, net ($/bbl)$ 25.77 $ 9.20 $ 16.57$ 20.52 $ 6.86 $ 13.66 Realized natural gas prices ($/Mcf)$ 4.11 $ 1.80 $ 2.31$ 3.23 $ 1.73 $ 1.50 Effects of derivatives, net ($/Mcf) (0.67) 0.08 (0.75) (0.22) 0.13 (0.35) Natural gas realized prices, including effects of derivatives, net ($/Mcf)$ 3.44 $ 1.88 $ 1.56$ 3.01 $ 1.86 $ 1.15 Effects of derivatives, net include, as applicable to the period presented: (i) current period commodity derivative settlements; (ii) the impact of option premiums paid or received in prior periods related to current period production; (iii) the impact of prior period cash settlements of early-terminated derivatives originally designated to settle against current period production; (iv) the exclusion of option premiums paid or received in current period related to future period production; and (v) the exclusion of the impact of current period cash settlements for early-terminated derivatives originally designated to settle against future period production. Other operating income, net Other operating income, net includes fees for marketing and water disposal services that we charge to third parties, net of related expenses, as well as other miscellaneous revenues and credits attributable to our current operations and gains and losses on the sale or disposition of assets other than our oil and gas properties. In addition, charges attributable to credit losses associated with our trade and joint venture partner receivables are included in this caption as a contra-revenue item. The following table sets forth the total Other revenues, net recognized for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable)
Other operating income, net
131
Our marketing fees slightly increased in the three and nine month periods in 2021 as compared to the corresponding periods in 2020 due primarily to higher commodity-based pricing and we recovered certain suspended revenues attributable to prior years during the 2021 periods. The increase was partially offset by lower water disposal fees in the nine month period due to lower sales volumes. 35
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Lease Operating Expenses LOE includes costs that we incur to operate our producing wells and field operations. The most significant costs include compression and gas lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment rentals, utilities and supplies, among others. The following table sets forth our LOE for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September Nine Months Ended September 30, Favorable 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Lease operating$ 10,647 $ 8,275 $ (2,372) $ 29,200 $ 27,901 $ (1,299) Per unit ($/boe)$ 4.54 $ 3.70 $ (0.84) $ 4.52 $ 4.04 $ (0.48) % change per unit (22.7) % (11.9) % LOE increased on an absolute basis and per unit basis during the three month period in 2021 when compared to the corresponding period in 2020 due primarily to higher variable costs and greater utilization of gas lift and lower maintenance costs as substantial work was completed in the prior year during shut-in periods partially offset by the effects of higher sales volumes in the three month period in 2021 and higher water disposal costs in the three month period in 2020 attributable to protective measures from offset stimulation activities. LOE also increased on an absolute and per unit basis during the nine month period in 2021 when compared to the corresponding period in 2020. The increases were due primarily to a combination of higher variable costs, higher gas lift costs, partially offset by continued cost-containment efforts and the application of operational improvements throughout 2021. Gathering, Processing and Transportation GPT expense includes costs that we incur to gather and aggregate our crude oil and natural gas production from our wells and deliver them via pipeline or truck to a central delivery point, downstream pipelines or processing plants, and blend or process, as necessary, depending upon the type of production and the specific contractual arrangements that we have with the applicable midstream operators. In addition, GPT expense includes short-term rental charges for crude oil storage tanks. The following table sets forth our GPT expense for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September Nine Months Ended September 30, Favorable 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) GPT$ 5,688 $ 5,760 $ 72$ 15,535 $ 16,797 $ 1,262 Per unit ($/boe)$ 2.43 $ 2.58 $ 0.15 $ 2.41 $ 2.43 $ 0.02 % change per unit 5.8 % 0.8 % GPT expense was relatively flat on an absolute basis during the three month period in 2021 as compared to the corresponding period in 2020. GPT expense decreased on an absolute basis during the nine month period in 2021 as compared to the corresponding period in 2020 due primarily to lower gas gathering costs attributable to 20% lower natural gas sales volumes, as well as the effects of an increase in the mix of crude oil volume sold at the wellhead, resulting in lower transportation costs. These favorable variances were partially offset by higher costs associated with short-term rental charges with multiple vendors to temporarily store a portion of our crude oil production. Production and Ad Valorem Taxes Production or severance taxes represent taxes imposed by the states in which we operate for the removal of resources including crude oil, NGLs and natural gas. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties, in which we operate, based on the assessed value of our operating properties. The assessments for ad valorem taxes are generally based on a published index prices. 36
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The following table sets forth our production and ad valorem taxes for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Production/severance taxes$ 6,589 $ 3,074 $ (3,515) $ 16,608 $ 8,692 $ (7,916) Ad valorem taxes 945 1,294 349 3,160 4,460 1,300$ 7,534 $ 4,368 $ (3,166) $ 19,768 $ 13,152 $ (6,616) Per unit ($/boe) $ 3.21$ 1.95 $ (1.26)$ 3.06 $ 1.90 $ (1.16) Production/severance tax rate as a percent of product revenues 4.7 % 4.5 % 4.7 % 4.3 % Production taxes increased on an absolute basis and per unit basis during the three and nine month periods in 2021 when compared to the corresponding periods in 2020 due primarily to the increases in aggregate commodity sales prices in the three and nine month periods in 2021. Our accruals for ad valorem taxes are based on our most recent estimates for assessments which reflect lower property values in 2021. General and Administrative Our G&A expenses include employee compensation, benefits and other related costs for our corporate management and governance functions, rent and occupancy costs for our corporate facilities, insurance, and professional fees and consulting costs supporting various corporate-level functions, among others. In order to facilitate a meaningful discussion and analysis of our results of operations with respect to G&A expenses, we have disaggregated certain costs into three components as presented in the table below. Primary G&A encompasses all G&A costs except share-based compensation and certain significant special charges that are generally attributable to material stand-alone transactions or corporate actions that are not otherwise in the normal course. The following table sets forth the components of our G&A for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Primary G&A$ 7,281 $ 5,913 $ (1,368) $ 19,341 $ 19,322 $ (19) Share-based compensation 971 775 (196) 4,179 2,582 (1,597) Significant special charges: Organizational restructuring, including severance - 1,372 1,372 239 1,372 1,133 Acquisition/integration, divestiture and strategic transaction costs 2,680 525 (2,155) 7,335 525 (6,810) Total G&A$ 10,932 $ 8,585 $ (2,347) $ 31,094 $ 23,801 $ (7,293) Per unit ($/boe)$ 4.66 $ 3.84 $ (0.82)$ 4.82 $ 3.45 $ (1.37) Per unit ($/boe) excluding share-based compensation and other significant special charges identified above$ 3.11 $ 2.65 $ (0.46)$ 3.00 $ 2.80 $ (0.20) Our primary G&A expenses increased on an absolute and per unit basis during the three and nine month periods in 2021 compared to the corresponding periods in 2020. The increase for the three month period in 2021 compared to 2020 is due primarily to higher incentive compensation costs. Primary G&A was relatively flat during the nine month period in 2021 compared to the corresponding period in 2020. Share-based compensation charges during the periods presented are attributable to the amortization of compensation cost, net of forfeitures, associated with the grants of time-vested restricted stock units ("RSUs"), and performance-based restricted stock units ("PRSUs"). The grants of RSUs and PRSUs are described in greater detail in Note 12 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements." As a result of the Juniper Transactions which qualified as a change-in-control event, all of the RSUs granted before 2019 vested as of the Juniper Closing Date in accordance with their terms. This resulted in an incremental charge of approximately$1.9 million during the first quarter 2021. All of our share-based compensation represents non-cash expenses. Our total G&A expenses were higher on an absolute and per unit basis during the three and nine month periods in 2021 as compared to the corresponding periods in 2020 due to higher overall incentive compensation and severance costs as well as 37
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acquisition and integration related costs associated with the Merger and Juniper Transactions, partially offset by lower organizational restructuring. Depreciation, Depletion and Amortization DD&A expense includes charges for the allocation of property costs based on the volume of production, depreciation of fixed assets other than oil and gas assets as well as the accretion of our asset retirement obligations. The following table sets forth total and per unit costs for DD&A for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) DD&A expense$ 30,975 $ 37,038 $ 6,063$ 83,654 $ 114,891 $ 31,237 DD&A rate ($/boe)$ 13.21 $ 16.57 $ 3.36$ 12.96 $ 16.63 $ 3.67 DD&A decreased on an absolute and a per unit basis during the three and nine month periods in 2021 when compared to the corresponding periods in 2020. Lower production volume provided for decreases of$7.6 million and lower DD&A rates resulted in decreases of$23.7 million in the first nine months of 2021. The lower DD&A rate in 2021 is primarily attributable to the effect of adding additional reserves in 2021 as well as the effect of the impairments recorded in the latter part of 2020 and in the first quarter 2021. Impairment ofOil and Gas Properties We assess our oil and gas properties on a quarterly basis based on the results of a comparison of the unamortized cost of our oil and gas properties, net of deferred income taxes, to the sum of our estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the "Ceiling Test") in accordance with the full cost method of accounting for oil and gas properties. 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Impairment of oil and gas properties $ -$ 235,989 $
235,989
We did not record an impairment of our oil and gas properties during the three month period in 2021, compared to an impairment of$236.0 million recorded in the corresponding period in 2020. During the nine month period in 2021, we recorded an impairment of$1.8 million , compared to the$271.5 million recorded in the nine month period in 2020. These impairments were the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by the respective quarterly Ceiling Test under the full cost method of accounting for oil and gas properties. Interest Expense Interest expense includes charges for outstanding borrowings under the Credit Facility and Second Lien Facility derived from internationally-recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. Also included is the accretion of original issue discount ("OID") on the Second Lien Facility and the amortization of issuance costs capitalized attributable to the Credit Facility and the Second Lien Facility. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage. Amortization of issuance costs and OID on the 9.25% Senior Notes due 2026 are excluded as ofSeptember 30, 2021 as the proceeds and accrued interest were held in escrow contingent upon the closing of the Lonestar acquisition which occurred subsequent to the period end. 38
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The following table summarizes the components of our interest expense for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September Nine Months Ended September 30, Favorable 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable)
Interest on borrowings and related fees$ 10,936 $ 7,375 $ (3,561) $ 22,101 $ 22,944 $ 843 Accretion of original issue discount 84 205 121 274 602 328 Amortization of debt issuance costs 479 594 115 1,468 2,734 1,266 Capitalized interest (917) (677) 240 (2,561) (2,067) 494 Total interest expense, net of capitalized interest$ 10,582 $ 7,497 $ (3,085) $ 21,282 $ 24,213 $ 2,931 The increase in interest expense during the three month period in 2021 is substantially attributable to interest incurred in the amount of$5 million for the 9.25% Senior Notes due 2026. This is offset by decreased interest expense attributable to the Credit Facility and Second Lien Facility during the three and nine month periods in 2021 as compared to the corresponding periods in 2020 due primarily to the effect of lower outstanding balances during the three and nine month periods in 2021 and lower interest rates associated with the Credit Facility, resulting from lower applicable margins based on lower utilization levels. The weighted-average balances under the Credit Facility were lower in the three and nine month periods in 2021 by approximately$109 million and$125 million , respectively. The weighted-average interest rates during the same periods were lower by 47 basis points. The accretion of OID is entirely attributable to the Second Lien Facility and the amortization of debt issuance costs includes amounts attributable to both the Credit Facility and Second Lien Facility. We capitalized a larger portion of interest during the three and nine month periods in 2021 as we maintained a higher portion of unproved property as compared to the corresponding period in 2020 due primarily to the property contribution from the Juniper Transactions coupled with the impact of additional interest related to the 9.25% Senior Notes due 2026. Derivatives The gains and losses for our derivatives portfolio reflect changes in the fair value attributable to changes in market values relative to our hedged commodity prices and interest rates. The following table summarizes the gains and (losses) attributable to our commodity derivatives portfolio and interest rate swaps for the periods presented: 2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Commodity derivative gains (losses)$ (21,000) $ (6,923) $ (14,077) $ (119,631) $ 117,406 $ (237,037) Interest rate swap gains (losses) (84) 32 (116) (48) (7,527) 7,479 Total$ (21,084) $ (6,891) $ (14,193) $ (119,679) $ 109,879 $ (229,558) In the three and nine month periods in 2021, commodity prices recovered to levels that were significantly higher on an average aggregate basis than those during the corresponding periods in 2020. Accordingly, the derivative losses in the three and nine month periods in 2021 reflect the decline in the mark-to-market values consistent with the increase in prices attributable to open positions. The effect in the three and nine month periods in 2020 was in the opposite direction as the mark-to-market gains associated were attributable to the substantial collapse in prices for the underlying commodities relative to our hedged positions. In the second quarter 2021, we began hedging a portion of our NGL production. Realized settlement payments, net for crude oil, NGL and natural gas derivatives were$21.3 million and$43.2 million during the three and nine month periods in 2021, respectively, as compared to realized settlement receipts, net of$7.3 million and$66.6 million during the three and nine month periods in 2020, respectively. In 2020, we began hedging a portion of our exposure to variable interest rates associated with our Credit Facility and Second Lien Facility. For the three and nine month periods in 2021, we paid$1.0 million and$2.9 million , respectively, of net settlements from our interest rate swaps. For the three and nine month periods in 2020, we paid$0.9 and$1.3 million of net settlements from our interest rate swaps, respectively. Income Taxes Income taxes represent our income tax provision as determined in accordance with generally accepted accounting principles. It considers taxes attributable to our obligations for federal taxes under the Internal Revenue Code as well as to the various states in which we operate, primarilyTexas , or otherwise have continuing involvement. 39
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The following table summarizes our income taxes for the periods presented:
2021 vs. 2020 2021 vs. 2020 Three Months Ended September 30, Favorable Nine Months Ended September 30, Favorable 2021 2020 (Unfavorable) 2021 2020 (Unfavorable) Income tax (expense) benefit $ (549)$ 1,558 $ (2,107) $ (410)$ 1,110 $ (1,520) Effective tax rate 1.3 % 0.6 % 1.3 % 0.6 % The income tax provision resulted in an expense of$0.5 million and$0.4 million for the three and nine months endedSeptember 30, 2021 , respectively. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 1.3%, which is fully attributable to theState of Texas . In connection with the Juniper Transactions, we recorded an adjustment of$0.7 million to Paid-in capital (see Note 3 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information) attributable to certain state deferred income tax effects associated with the change in legal entity structure. Our net deferred income tax liability balance of$0.8 million as ofSeptember 30, 2021 is also fully attributable to theState of Texas and primarily related to property. We recognized a federal and state income tax benefit of$1.6 million and$1.1 million the three and nine months endedSeptember 30, 2020 , respectively. The federal and state tax expense was offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.6% which was fully attributable to theState of Texas . The provision also reflected a reclassification of$1.2 million from deferred tax assets to current income taxes receivable for certain refundable alternative minimum tax credit carryforwards that were later received inJune 2020 . Liquidity and Capital Resources Liquidity Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. As ofSeptember 30, 2021 , we had liquidity of$172.0 million , comprised of cash and cash equivalents of$35.3 million and availability under our Credit Facility of$136.7 million (factoring in letters of credit), and excludes$15.4 million restricted cash - current representing escrowed accrued interest and an amount equivalent to the original issue discount for the 9.25% Senior Notes due 2026 which funds were subsequently released upon closing of the Merger. Additionally, following the closing of the Merger in connection with the Eleventh Amendment (as defined below), the borrowing base under the Credit Facility was increased to$600 million , with aggregate elected commitments of$400 million . OnAugust 10, 2021 , our indirect, wholly-owned subsidiaryPenn Virginia Escrow LLC (the "Escrow Issuer") completed an offering of$400 million aggregate principal amount of the 9.25% Senior Notes due 2026 which bear interest at 9.25% and were sold at 99.018% of par. The gross proceeds of the offering and other funds had initially been deposited in an escrow account pending satisfaction of certain conditions, including the consummation of the Merger. AtSeptember 30, 2021 , the gross proceeds plus accrued interest and original issue discount were held in escrow. Upon the closing of the Merger, Holdings assumed all obligations under the 9.25% Senior Notes due 2026 and the net proceeds and certain other funds were released from escrow and used to repay and discharge certain long-debt of Lonestar including accrued interest and related expenses, and the remainder, along with cash on hand, was used to repay the Second Lien Facility including a prepayment premium, accrued interest and related expenses. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been negatively impacted by the continuing COVID-19 pandemic and the related instability in the global energy markets. In order to mitigate this volatility, we are extensively utilizing derivative contracts with a number of financial institutions, all of which are participants in our Credit Facility, hedging a portion of our estimated future crude oil, NGLs and natural gas production through the first half of 2023. The level of our hedging activity and duration of the financial instruments employed depends on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy. We continually evaluate potential sales of assets, including certain non-strategic oil and gas properties and undeveloped acreage, among others. Additionally, from time-to-time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities. We maintain an effective shelf registration statement to allow for optionality. 40
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Capital Resources Our 2021 capital budget contemplates capital expenditures from$240 to$270 million , of which$235 to$265 million has been allocated to drilling and completion activities. We plan to fund our 2021 capital program and our operations for the next twelve months primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our capital spending and operations for at least the next twelve months; however, future cash flows are subject to a number of variables including the length and magnitude of the current global economic uncertainties associated with the COVID-19 pandemic and related instability in the global energy markets. Cash Flows The following table summarizes our cash flows for the periods presented: Nine Months Ended September 30, September 30, 2021 2020 Net cash provided by operating activities 204,084 189,723 Net cash used in investing activities (146,481) (138,927) Net cash provided by (used in) financing activities 376,146 (38,078)
Net increase in cash, cash equivalents and restricted cash
Cash Flows from Operating Activities. The increase of$14.4 million in net cash provided by operating activities for the nine months endedSeptember 30, 2021 compared to the corresponding period in 2020 was primarily attributable to the effect of cash receipts that were derived from higher average prices in 2021, as well as lower interest payments, net of interest rate swap settlements in the 2021 period as compared to 2020, partially offset by (i) the effects of lower total sales volume (ii) higher net payments for commodity derivatives settlements and premiums, (iii) transaction costs paid in connection with the Juniper Transactions and Lonestar acquisition and integration costs and (iv) executive restructuring costs including severance payments. Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during the nine months endedSeptember 30, 2021 as compared to the corresponding period in 2020, due primarily to the suspension of the drilling and completion program during a portion of 2020 as a result of the COVID-19 pandemic and related market instability. The following table sets forth costs related to our capital expenditures program for the periods presented: Nine Months EndedSeptember 30 ,September 30, 2021 2020 Drilling and completion $
181,144
2,315 3,317 Pipeline, gathering facilities and other equipment, net 1 (632) 1,221 Total capital expenditures incurred $
182,827
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1 Includes certain capital charges to our working interest partners for completion services. The following table reconciles the total costs of our capital expenditures program with the net cash paid for capital expenditures as reported in our condensed consolidated statements of cash flows for the periods presented:
Nine Months Ended
September 30 ,September 30, 2021 2020 Total capital expenditures program costs (from above) $
182,827
(30,303) 30,579 Net purchases of tubular inventory and well materials 1 1,858 3,441
Prepayments for drilling and completion services, net of (transfers) (12,653)
3,613 Capitalized internal labor, capitalized interest and other 4,909 3,396 Total cash paid for capital expenditures $
146,638
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1 Includes purchases made in advance of drilling.
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Cash Flows from Financing Activities. InJanuary 2021 , we received over$150 million of proceeds from the issuance of Common Units and Series A Preferred Stock in connection with the Juniper Transactions. These proceeds were used to fund the repayments of$80.5 million and$50.0 million under the Credit Facility and Second Lien Facility, respectively. The remainder of the proceeds were used to pay: (i)$3.8 million of issue costs associated with the redeemable securities (Common Units and Series A Preferred Stock), (ii)$5.5 million of transaction costs attributable to Juniper's Noncontrolling interest, (iii)$1.8 million of issue costs associated with the amendments to the Credit Facility and Second Lien Facility in connection with the Juniper Transactions, (iv)$1.3 million to liquidate outstanding Second Lien Facility advances attributable to a single participant lender and (v) a portion of interest payments and other Juniper Transactions costs, both of which are presented as cash disbursements included in net cash provided by operating activities above. The nine months endedSeptember 30, 2021 also includes additional net repayments of$21.0 million under the Credit Facility and$5.6 million quarterly amortization payments under the Second Lien Facility as well as$396.1 million net proceeds received from the 9.25% Senior Notes due 2026. The nine months endedSeptember 30, 2020 includes borrowings of$51.0 million and repayments of$89.0 million under the Credit Facility which were used to fund a portion of the capital program at the beginning of 2020. Capitalization The following table summarizes our total capitalization as of the dates presented: September 30, December 31, 2021 2020 Credit facility$ 212,900 $ 314,400 Second lien facility, net 139,133 195,097 9.25 Senior Notes due 2026, net 394,795 - Total debt, net 746,828 509,497 Total equity 426,590 212,838$ 1,173,418 $ 722,335 Debt as a % of total capitalization 64 % 71 % Credit Facility. As ofSeptember 30, 2021 , the Credit Facility had a$1.0 billion revolving commitment and a$375 million borrowing base, including a$25 million sublimit for the issuance of letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders generally may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes including working capital. Prior to the Eleventh Amendment (as defined below), the Credit Facility was scheduled to mature inMay 2024 . We had$0.4 million in letters of credit outstanding as ofSeptember 30, 2021 andDecember 31, 2020 . The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including theLondon interbank offered rate ("LIBOR") through 2021, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar, including LIBOR, borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As ofSeptember 30, 2021 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.09%. Unused commitment fees are charged at a rate of 0.50%. The following table summarizes our borrowing activity under the Credit Facility for the periods presented: Borrowings Outstanding Weighted- Weighted- End of Period Average Maximum Average Rate Three months ended September 30, 2021$ 212,900 $ 233,818 $ 238,900 3.10 % Nine months ended September 30, 2021$ 212,900 $ 241,206 $ 314,400 3.13 % The Credit Facility is guaranteed by all of the subsidiaries of the borrower (the "Guarantor Subsidiaries"), except forBoland Building, LLC , effective upon the Eleventh Amendment, which holds real estate assets that are associated with Lonestar's legacy mortgage obligations. The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on the ability of the borrower or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries' assets. InAugust 2021 , we entered into the Master Assignment, Agreement and Amendment No. 11 to Credit Agreement (the "Eleventh Amendment"). The Eleventh Amendment, in addition to other changes described therein, amended the Credit 42
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Facility to, effective on the closing of the Merger, (1) increase the borrowing base under to$600 million , with aggregate elected commitments of$400 million , (2) remove certain availability restrictions, (3) remove minimum hedging requirements, (4) remove the first lien leverage ratio covenant, (5) remove the Partnership andPV Energy Holdings GP, LLC as guarantors, and (6) extend the maturity date to the date that is the four year anniversary of the date such amendment became effective, orOctober 6, 2025 . Second Lien Facility. OnOctober 5, 2021 , Holdings repaid all of its outstanding obligations under the Second Lien Facility, and terminated the Second Lien Facility. In accordance with the Second Lien Facility, we incurred a prepayment premium of 102% as a result of repayment. Covenant Compliance. As ofSeptember 30, 2021 , the Credit Facility required us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset) of 1.00 to 1.00, (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00. and (3) a maximum first lien leverage ratio (consolidated secured indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter, of 2.50 to 1.00. The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. In addition, as ofSeptember 30, 2021 , the Credit Facility contained certain anti-cash hoarding provisions. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information. The Credit Facility contains events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As ofSeptember 30, 2021 , we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information on our debt, including the 9.25% Senior Notes due 2026. Off Balance Sheet Arrangements As ofSeptember 30, 2021 , we had no off-balance sheet arrangements other than information technology licensing, service agreements, in-kind commodity recovery arrangements for imbalances and letters of credit, all of which are customary in our business. Critical Accounting Estimates The process of preparing financial statements in accordance with accounting principles generally accepted inthe United States of America ("GAAP") requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year endedDecember 31, 2020 . As described in this Quarterly Report on Form 10-Q as well as the Critical Accounting Estimates disclosures in the Annual Report on Form 10-K, we apply the full cost method to account for our oil and gas properties. At the end of each quarterly reporting period, we perform a Ceiling Test in order to determine if our oil and gas properties have been impaired. For purposes of the Ceiling Test, estimated discounted future net revenues are determined using the prior 12-month's average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. The carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test as ofMarch 31, 2021 , resulting in a$1.8 million impairment. There was no such impairment of our proved oil and gas properties during the second or third quarters of 2021. 43
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