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 amounts for the prior period have been reclassified to conform to the current period presentation. References to "quarters" represent the three months endedMarch 31, 2022 or 2021, as applicable. This section of the Form 10-Q discusses the results of operations for the quarter endedMarch 31, 2022 compared to the quarter endedMarch 31, 2021 unless otherwise indicated. 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 "Lonestar Acquisition"). The results of operations of Lonestar are reflected in our accompanying condensed consolidated financial statements for the quarter endedMarch 31, 2022 . Results for the quarter endedMarch 31, 2021 reflect the financial and operating results ofRanger Oil and do not include the financial and operating results of Lonestar. As such, our historical results of operations are not comparable from period to period. 23 --------------------------------------------------------------------------------
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
OnApril 13, 2022 , our Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to$100 million of its outstanding Class A common stock throughMarch 31, 2023 . The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions, or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including among other things, our earnings, liquidity, capital requirements, financial condition, management's assessment of the intrinsic value of the Class A Common Stock, the market price of the Company's Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements (including maintaining a leverage ratio of no more than 1.0 to 1.0), applicable legal requirements and other factors deemed relevant and may be discontinued at any time. OnMay 3, 2022 , we entered into separate agreements to acquire "bolt-on" oil producing properties in the Eagle Ford shale contiguous to our existing assets for a total purchase price of approximately$64 million in cash, subject to customary adjustments. The transactions are expected to close early in the third quarter, subject to customary closing conditions.
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 COVID-19 created uncertainty for global economic activity. Beginning inMarch 2020 , the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy, which directly impacted our industry and the Company. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. A high level of uncertainty remains regarding the volatility of energy supply and demand as theOrganization of the Petroleum Exporting Countries ("OPEC") andRussia (together withOPEC , collectively "OPEC+") continued to execute its strategy throughout 2021 to gradually increase production. In its most recentMarch 2022 meeting, OPEC+ reconfirmed the agreement to increase output targets each month by 432,000 bbl/day beginningMay 1, 2022 . Most recently, WTI crude oil prices have surged, closing at over$120 per bbl during first quarter 2022 as a result of theRussia -Ukraine conflict and related sanctions and concerns that it might result in significant oil supply shortages. In response, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, including releasing emergency oil reserves. Higher energy prices, along with the global supply chain issues and other factors, have increased inflationary pressures, which has led or may lead to increased costs of services and certain materials necessary for our operations. 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. All of our crude oil volumes are sold under Magellan East Houston ("MEH") pricing, which historically has been at a premium to NYMEX WTI. Similar to crude prices, Natural gas prices have jumped substantially as a result of theRussia -Ukraine conflict, with NYMEX Henry Hub ("NYMEX HH") closing well over$5.00 per Mcf during first quarter 2022, which is the highest level in more than a decade. 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 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 have resulted in higher costs for products, materials and services that we utilize in both our capital projects and with respect to our operating expenses. In 2021, we took 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 but we have continued to experience higher costs and this may be exacerbated in the future. 24
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Capital Expenditures, Development Progress and Production
During the three months endedMarch 31, 2022 , we operated two drilling rigs and incurred capital expenditures of approximately$83.5 million , of which$82.8 million was directed to drilling and completion projects. During the first quarter 2022, a total of 14 gross (8.9 net) wells were completed and turned in line. During the second quarter of 2022, we entered into a contract to operate a spot drilling rig.
As of
Total sales volume for the first quarter 2022 was 3,398 thousand barrels of oil equivalent ("Mboe"), or 37,752 barrels of oil equivalent ("boe") per day, with approximately 71%, or 2,428 thousand barrels of oil ("Mbbl"), of sales volume from crude oil, 15% from NGLs and 14% from natural gas.
Commodity Hedging Program
As ofApril 28, 2022 , we have hedged a portion of our estimated future crude oil and natural gas production fromApril 1, 2022 through the first half of 2024. The following table summarizes our net hedge position for the periods presented: 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 3,000 3,000 3,000 2,500 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl)$ 74.12 $ 73.01 $ 69.20 $ 54.40 $ 54.26 $ 54.92 $ 54.93 $ 58.75 $58.75 NYMEX WTI Crude Collars Average Volume Per Day (bbl) 17,720 14,266 9,375 6,250 6,181 1,630 1,630 Weighted Average Purchased Put Price ($/bbl)$ 59.12 $ 57.14 $ 52.17 $ 50.67 $ 50.67 $ 60.00 $ 60.00 Weighted Average Sold Call Price ($/bbl)$ 77.01 $ 81.13 $ 67.57 $ 65.65 $ 65.65 $ 76.12 $ 76.12 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 20,879 7,337 1,630 Weighted Average Swap Price ($/bbl)$ 1.120 $ 1.172 $ 1.020 NYMEX HH Swaps Average Volume Per Day (MMBtu) 12,500 12,500 12,500 10,000 7,500 Weighted Average Swap Price ($/MMBtu)$ 3.727 $ 3.745 $ 3.793 $ 3.620 $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 13,187 15,679 14,511 6,417 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu)$ 2.500 $ 3.088 $ 2.854 $ 6.000 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price($/MMBtu)$ 3.220 $ 4.141 $ 3.791 $ 10.000 $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000 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 25
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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 December 31, March 31, 2022 2021 March 31, 2021 Total sales volume (Mboe) 1 3,398 3,702 1,848 Average daily sales volume (boe/d) 1 37,752 40,236 20,534 Crude oil sales volume (Mbbl) 1 2,428 2,532 1,469 Crude oil sold as a percent of total 1 71 % 68 % 80 % Product revenues$ 255,599 $ 224,594 $ 88,308 Crude oil revenues $
226,732
89 % 85 % 93 % Realized prices: Crude oil ($/bbl)$ 93.38 $ 75.48 $ 55.76 NGLs ($/bbl)$ 33.40 $ 29.91 $ 16.95 Natural gas ($/Mcf) $ 4.32$ 4.54 $ 2.80 Aggregate ($/boe)$ 75.23 $ 60.67 $ 47.79 Realized prices, including effects of derivatives, net 2 Crude oil ($/bbl)$ 74.00 $ 64.50 $ 44.80 Natural gas ($/Mcf) $ 3.96$ 2.99 $ 2.84 Aggregate ($/boe)$ 61.08 $ 51.77 $ 39.10 Production and lifting costs: Lease operating ($/boe) $ 5.33$ 4.38 $ 4.78 Gathering, processing and transportation ($/boe) $ 2.66$ 2.19 $ 2.53 Production and ad valorem taxes ($/boe) $ 3.87$ 3.05 $ 2.98 General and administrative ($/boe) 3 $ 2.88$ 9.57 $ 7.13 Depreciation, depletion and amortization ($/boe)$ 14.98 $ 12.97 $ 12.92 _______________________ 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$0.79 ,$7.57 and$3.86 per boe for the three months endedMarch 31, 2022 ,December 31, 2021 andMarch 31, 2021 , respectively, attributable to share-based compensation and significant special charges, comprised of organizational restructuring, acquisition and integration costs and strategic transaction costs, including costs attributable to the Lonestar Acquisition during the first quarter 2022 and fourth quarter 2021 periods and a change-in-control event during the first quarter of 2021 as described in the discussion of "Results of Operations - General and Administrative" that follows. 26 --------------------------------------------------------------------------------
Sequential Quarterly Analysis
The following summarizes our key operating and financial highlights for the three months endedMarch 31, 2022 , with comparison to the three months endedDecember 31, 2021 . The year-over-year highlights for the quarterly periods endedMarch 31, 2022 and 2021 are addressed in further detail in the discussions that follow below in Year over Year Analysis of Operating and Financial Results. •Daily sales volume decreased to 37,752 boe per day from 40,236 boe per day with 8.9 net wells turned in line for the first quarter 2022 compared to 10.4 net wells turned in line for the fourth quarter 2021. Total sales volume decreased 8% to 3,398 Mboe from 3,702 Mboe. •Product revenues increased 14% to$255.6 million from$224.6 million as a result of 24% higher crude oil realized prices, or$43.5 million , coupled with lower crude oil sales volume, or$7.8 million . NGL revenues were lower due to 18% lower sales volume, or$3.4 million , although realized prices were 12% higher, or$1.7 million . Natural gas revenues were 20% lower as a result of 5% lower realized prices and 16% lower volume for an overall decrease of$3.0 million . •Production and lifting costs, consisting of Lease operating expenses ("LOE") and Gathering, processing and transportation expenses ("GPT"), increased on an absolute basis and per unit basis to$27.1 million and$7.99 per boe from$24.3 million and$6.57 per boe due primarily to the impact of the Lonestar Acquisition, partially offset by the effects of 8% lower sales volume. •Production and ad valorem taxes increased on an absolute and per unit basis to$13.1 million and$3.87 per boe from$11.3 million and$3.05 per boe, respectively, due to the overall effects of 24% higher aggregate realized product pricing, coupled with higher estimated ad valorem tax assessments in 2022. •General and administrative ("G&A") expenses decreased on an absolute and per unit basis to$9.8 million and$2.88 per boe from$35.4 million and$9.57 per boe, respectively, primarily due to less acquisition and integration costs associated with the Lonestar Acquisition of$1.7 million incurred during the first quarter 2022 compared to$27.0 million during the fourth quarter 2021. •Depreciation, depletion and amortization ("DD&A") increased on an absolute and per unit basis to$50.9 million and$14.98 per boe during the first quarter 2022 as compared to$48.0 million and$12.97 per boe during the fourth quarter 2021 due primarily to higher development costs. 27 --------------------------------------------------------------------------------
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:
Three Months Ended March 31, Total Sales Volume 1 2022 2021 Change % Change Crude oil (Mbbl and bbl/d) 2,428 1,469 959 65 % NGLs (Mbbl and bbl/d) 501 210 291 139 % Natural gas (MMcf and MMcf/d) 2,810 1,013 1,797 177 % Total (Mboe and boe/d) 3,398 1,848 1,550 84 % Three Months Ended March 31, Average Daily Sales Volume 1 2022 2021 Change % Change Crude oil (Mbbl and bbl/d) 26,980 16,324 10,656 65 % NGLs (Mbbl and bbl/d) 5,568 2,335 3,233 138 % Natural gas (MMcf and MMcf/d) 31 11 20 182 % Total (Mboe and boe/d) 37,752 20,534 17,218 84 % _______________________ 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 increased 84% during the three months endedMarch 31, 2022 when compared to the corresponding period in 2021 as a result of the Lonestar Acquisition that closed in fourth quarter of 2021 and increased drilling activity throughout 2021. Approximately 71% of total sales volume during the three month periods in 2022 was attributable to crude oil when compared to approximately 80% during the corresponding periods in 2021. The decrease in the crude oil composition of total sales volume is due primarily to higher gas content of the wells acquired in the Lonestar Acquisition. 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:
Three Months Ended March 31, Total Product Revenues 2022 2021 Change % Change Crude oil$ 226,732 $ 81,913 $ 144,819 177 % NGLs 16,740 3,562 13,178 370 % Natural gas 12,127 2,833 9,294 328 % Total$ 255,599 $ 88,308 $ 167,291 189 % Product Revenues per Unit of Three Months Ended March 31, Volume ($ per unit of volume) 2022 2021 Change % Change Crude oil$ 93.38 $ 55.76 $ 37.62 67 % NGLs$ 33.40 $ 16.95 $ 16.45 97 % Natural gas$ 4.32 $ 2.80 $ 1.52 54 % Total$ 75.23 $ 47.79 $ 27.44 57 % 28
-------------------------------------------------------------------------------- The following table provides an analysis of the changes in our revenues for the periods presented: Three Months Ended March 31, 2022 vs. 2021 Revenue Variance Due to Volume Price Total Crude oil$ 53,472 $ 91,347 $ 144,819 NGLs 4,934 8,244 13,178 Natural gas 5,029 4,265 9,294$ 63,435 $ 103,856 $ 167,291 Our product revenues during the three month period in 2022 increased compared to the corresponding period in 2021 due to significantly higher prices from continued economic recovery, as well as supply concerns resulting from theRussia -Ukraine conflict as compared to the prior year. These factors resulted in an increase to the NYMEX WTI benchmark price of 63% for the three months endedMarch 31, 2022 , as compared to the corresponding period in 2022. Also contributing to the higher product revenues was an increase in volumes across all commodities due to the Lonestar Acquisition, with an overall increase in Mboe of 84%. 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: Three Months Ended March 31, 2022 2021 Change % Change Realized crude oil prices ($/bbl)$ 93.38 $ 55.76 $ 37.62 67 % Average WTI prices 95.01 58.14 36.87 63 % Realized differential to WTI$ (1.63) $ (2.38) $ 0.75 (32) % Realized natural gas prices ($/Mcf)$ 4.32 $ 2.80 $ 1.52 54 % Average HH prices ($/MMBtu) 4.60 3.38 1.22 36 % Realized differential to HH$ (0.28) $ (0.58) $ 0.30 (52) % Our differential to NYMEX WTI for the three months endedMarch 31, 2022 improved by 32% compared to the corresponding period in 2021 due to more favorable NYMEX Calendar Month Average contractual pricing component and more favorable pricing negotiated with certain new crude purchasers effective early in first quarter 2022. Our differential to NYMEX HH also improved for the three months endedMarch 31, 2022 due to more favorable location basis differentials. 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 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 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"). 29
-------------------------------------------------------------------------------- The following table presents the calculation of our non-GAAP realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil and natural gas determined in accordance with GAAP: Three Months Ended March 31, 2022 2021 Change % Change Realized crude oil prices ($/bbl)$ 93.38 $ 55.76 $ 37.62 67 % Effects of derivatives, net ($/bbl) (19.38) (10.96) (8.42) 77 % Crude oil realized prices, including effects of derivatives, net ($/bbl)$ 74.00 $ 44.80 $ 29.20 65 % Realized natural gas prices ($/Mcf)$ 4.32 $ 2.80 $ 1.52 54 % Effects of derivatives, net ($/Mcf) (0.36) 0.04 (0.40) (1000) % Natural gas realized prices, including effects of derivatives, net ($/Mcf)$ 3.96 $ 2.84 $ 1.12 39 % 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 netted within this caption. The following table sets forth the total Other operating income, net recognized for the periods presented: Three Months Ended March 31, 2022 2021 Change % Change Other operating income, net $ 856$ 247 $ 609 247 % Our marketing fee income increased in the three month period in 2022 as compared to the corresponding period in 2021 due primarily to the higher commodity-based pricing and gain on sales of field materials.
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:
Three Months Ended March 31, 2022 2021 Change % Change Lease operating $ 18,102$ 8,825 $ 9,277 105 % Per unit ($/boe) $ 5.33$ 4.78 $ 0.55 12 % LOE increased on an absolute basis and per unit basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to the impact of the Lonestar Acquisition, increased field labor and variable costs driven by higher sales volume.
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. 30
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The following table sets forth our GPT expense for the periods presented:
Three Months Ended March 31, 2022 2021 Change % Change GPT$ 9,040 $ 4,674 $ 4,366 93 % Per unit ($/boe) $ 2.66$ 2.53 $ 0.13 5 % GPT expense increased on an absolute basis and per unit basis during the three month period in 2022 as compared to the corresponding period in 2021 due primarily to the impact of the Lonestar Acquisition, which contributed to the 177% higher natural gas sales volumes and 65% higher crude oil sales volumes. Additionally, for certain of our crude oil volumes gathered, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of$90 per bbl, the gathering rate escalates. As such, with the higher prices during first quarter 2022 compared to first quarter 2021, we incurred higher gathering costs associated with these volumes. These unfavorable variances were partially offset by the effects of an increase in the mix of crude oil volume sold at the wellhead, including the majority of crude oil volumes from the acquired Lonestar wells, resulting in reduced transportation costs and cost per unit.
Production and Ad Valorem Taxes
Production or severance taxes represent taxes imposed by the states in which we operate for the removal of resources including crude oil, NGLs and natural gas. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties in which we operate, based on the assessed value of our operating properties. The assessments for ad valorem taxes are generally based on published index prices. The following table sets forth our production and ad valorem taxes for the periods presented: Three Months Ended March 31, 2022 2021 Change % Change Production/severance taxes$ 11,570 $ 4,242 $ 7,328 173 % Ad valorem taxes 1,570 1,271 299 24 %$ 13,140 $ 5,513 $ 7,627 138 % Per unit ($/boe) $ 3.87$ 2.98 $ 0.89 30 %
Production/severance tax rate as a percent of product revenues
4.5 % 4.8 % (0.3) % - % Production and Ad Valorem taxes increased on an absolute basis and per unit basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to the impact of the Lonestar Acquisition. Additionally, Production taxes increased on an absolute and per unit basis due to higher aggregate commodity sales prices during the three month period in 2022.
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. 31 -------------------------------------------------------------------------------- The following table sets forth the components of our G&A expenses for the periods presented: Three Months Ended March 31, 2022 2021 Change % Change Primary G&A expenses$ 7,112 $ 6,037 $ 1,075 18 % Share-based compensation 924 2,246 (1,322) Significant special charges: 100 % Organizational restructuring, including severance - 239 (239) (100) %
Acquisition/integration and strategic transaction costs 1,743
4,655 (2,912) (63) % Total G&A expenses$ 9,779 $ 13,177 $ (3,398) (26) % Per unit ($/boe)$ 2.88 $ 7.13 $ (4.25) (60) %
Per unit ($/boe) excluding share-based compensation and
other significant special charges identified above
$ 3.27 $ (1.18) (36) % Our total G&A expenses were lower on an absolute and per unit basis during the three month period in 2022 when compared to the corresponding period in 2021 due to lower costs incurred in first quarter 2022 for the Lonestar Acquisition integration related costs than the costs incurred in first quarter 2021 associated with the Juniper Transactions, as well as lower share-based compensation cost due to the incremental$1.9 million charge during first quarter 2021 discussed below. These decreases were partially offset by higher salaries and wages in 2022, primarily driven by increased headcount. Our primary G&A expenses increased on an absolute basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to increased headcount following the Lonestar Acquisition and the impact of salary increases effectiveJanuary 1, 2022 . Primary G&A expenses decreased on a per unit basis due to higher overall sales volumes. 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, all of the RSUs granted before 2019 vested and an incremental charge of approximately$1.9 million was recorded during the first quarter 2021. All of our share-based compensation represents non-cash expenses.
Depreciation, Depletion and Amortization
DD&A expense includes charges for the allocation of property costs based on the volume of production, depreciation of fixed assets other than oil and gas assets as well as the accretion of our asset retirement obligations. The following table sets forth total and per unit costs for DD&A expense for the periods presented: Three Months Ended March 31, 2022 2021 Change % Change DD&A expense$ 50,893 $ 23,884 $ 27,009 113 % DD&A rate ($/boe) $ 14.98$ 12.92 $ 2.06 16 % DD&A expense increased on an absolute and a per unit basis during the three month period in 2022 when compared to the corresponding period in 2021. Higher production volume provided for an increase of$20.0 million and a higher DD&A rate resulted in an increase of$7.0 million for first quarter 2022. The higher DD&A rate in 2022 is primarily due to the Lonestar Acquisition, which contributed to an increase in our total proved reserves at a higher relative cost per boe as compared to the first quarter 2021. 32 --------------------------------------------------------------------------------
Impairment of
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. Three Months Ended March
31,
2022 2021 Change % Change Impairment of oil and gas properties $ -$ 1,811 $ (1,811) (100) % We did not record an impairment of our oil and gas properties during the three month period in 2022, compared to an impairment of$1.8 million recorded in the corresponding period in 2021. The impairment in 2021 was the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by the respective quarterly Ceiling Test under the full cost method of accounting for oil and gas properties.
Interest Expense
Interest expense for the three month period in 2022 includes charges for outstanding borrowings under the Credit Facility derived from internationally recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. Also included are the amortization of issuance costs capitalized attributable to the Credit Facility and the 9.25% Senior Notes due 2026 and accretion of original issue discount ("OID") on the 9.25% Senior Notes due 2026.
Interest expense for the three month period in 2021 includes charges for
outstanding borrowings under the Credit Facility and the Second Lien Credit
Agreement, dated
In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage. The following table summarizes the components of our interest expense for the periods presented: Three Months Ended March 31, 2022 2021 Change % Change Interest on borrowings and related fees$ 10,957 $ 5,632 $ 5,325 95 % Accretion of original issue discount 640 105 535 510 % Amortization of debt issuance costs 160 506 (346) (68) % Capitalized interest (1,060) (846) (214) 25 % Total interest expense, net of capitalized interest$ 10,697 $ 5,397 $ 5,300 98 % The increase in interest expense during the three month period in 2022 is primarily attributable to interest incurred in the amount of$8.8 million for the 9.25% Senior Notes due 2026 and$1.7 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of$3.5 million for the Second Lien Term Loan and$1.9 million for the Credit Facility as well as increased amortization of OID compared to the corresponding period in 2021. These increases are partially offset by decreased amortization of debt issuance costs during the three month period in 2022 when compared to the corresponding period in 2021 and increased capitalized interest during the three month period in 2022, driven by higher overall weighted-average interest rate in 2022 as compared to the corresponding period in 2021. 33 --------------------------------------------------------------------------------
Derivatives
The gains and losses for our derivatives portfolio reflect changes in the fair value attributable to changes in market values relative to our hedged commodity prices and interest rates. The following table summarizes the gains and (losses) attributable to our commodity derivatives portfolio and interest rate swaps for the periods presented: Three Months Ended March 31, 2022 2021 Change % Change Commodity derivative losses$ (167,970) $ (44,400) $ (123,570) 278 % Interest rate swap gains 83 32 51 159 % Total$ (167,887) $ (44,368) $ (123,519) 278 % In the three month period in 2022, commodity prices were significantly higher on an average aggregate basis than those during the corresponding periods in 2021. The derivative losses in the three month periods in 2022 and 2021 reflect the decline in the mark-to-market values consistent with the increase in prices attributable to open positions for both periods. Realized settlement payments, net for crude oil and natural gas derivatives were$28.5 million and$6.2 million during the three month periods in 2022 and 2021, respectively. We hedge a portion of our exposure to variable interest rates associated with our Credit Facility and, in first quarter 2021, our Second Lien Term Loan. For both the three month periods in 2022 and 2021, we paid$0.9 million of net settlements from our interest rate swaps. 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.
The following table summarizes our income taxes for the periods presented:
Three Months Ended March 31, 2022 2021 Change % Change Income tax benefit $ 189$ 310 $ (121) (39) % Effective tax rate 0.9 % 1.5 % (0.6) % - % The income tax provision resulted in a benefit of$0.2 million for the three months endedMarch 31, 2022 . 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 0.9%, which is fully attributable to theState of Texas . Our net deferred income tax liability balance of$2.1 million as ofMarch 31, 2022 is also fully attributable to theState of Texas and primarily related to property. The income tax provision resulted in a benefit of$0.3 million for the three months endedMarch 31, 2021 . The federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 1.5% which was fully attributable to theState of Texas . 34
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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 ofMarch 31, 2022 , we had liquidity of$277.7 million , comprised of cash and cash equivalents of$6.4 million and availability under our Credit Facility of$271.3 million (factoring in letters of credit). The Credit Facility provides us up to$1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is$725.0 million with aggregate elected commitments of$400.0 million . The availability under the Credit Facility of$271.3 million remained unchanged as ofApril 28, 2022 . 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 impacted by the COVID-19 pandemic and theRussia -Ukraine conflict and related instability in the global energy markets. In order to mitigate this volatility, we utilize 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 2024. 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. 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. Capital Resources Our 2022 capital budget contemplates capital expenditures of up to approximately$435 million , of which approximately$425 million has been allocated to drilling and completion activities. We plan to fund our 2022 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 andRussia -Ukraine conflict and related instability in the global energy markets. Additionally, we have other obligations primarily consisting of our outstanding debt principal and interest obligations, derivative instruments, service agreements, operating leases, and asset retirement and environmental obligations, all of which are customary in our business. See Note 11 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for more details related to these obligations. The Partnership is also required in certain circumstances to make certain tax distributions to its partners, which may impact cash flow from operations for the Company, as discussed below under "Tax Distributions."
Share Repurchase Program
InApril 2022 , we announced that the Board of Directors approved a share repurchase program under which we are authorized to repurchase up to$100 million of outstanding Class A Common Stock throughMarch 31, 2023 . The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's shares, the market price of the Company's Class A common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements (including maintaining a leverage ratio of no more than 1.0 to 1.0), and applicable legal requirements. We expect to fund repurchases from available working capital and cash provided by operating activities.
Tax Distributions
Under its partnership agreement, the Partnership is required to make distributions to all of its limited partners pro rata on a quarterly basis and in such amounts as necessary to enable the Company to timely satisfy all of itsU.S. federal, state and local and non-U.S. tax liabilities. Additionally, the Partnership is required to make advances to its non-corporate partners in an amount sufficient to enable such partner to timely satisfy itsU.S. federal, state and local and non-U.S. tax liabilities (a "Tax Advance"). Any such Tax Advance will be treated as an advance against and, therefore, reduce any future distributions that such partner is otherwise entitled to receive. The Company's cash flow from operations and ability to effect share repurchases or cash dividends to our stockholders could be adversely impacted as a result of such cash distributions. Whether and how much Tax Advances are required to be paid is dependent upon the amount and timing of taxable income generated in the future that is allocable to partners and the federal tax rates then applicable. We are unable to assess whether the Partnership will be required to make Tax Advances for the year endingDecember 31, 2022 or in future years. 35 --------------------------------------------------------------------------------
Cash Flows
The following table summarizes our cash flows for the periods presented:
Three Months Ended
2022 2021 Net cash provided by operating activities 133,835 32,687 Net cash used in investing activities (70,517) (34,754) Net cash provided by (used in) financing activities (80,641) 915 Net decrease in cash, cash equivalents and restricted cash $
(17,323)
Cash Flows from Operating Activities. The increase of$101.1 million in net cash provided by operating activities for the three months endedMarch 31, 2022 compared to the corresponding period in 2021 was primarily attributable to the effect of cash receipts that were derived from higher average prices in 2022 and the effects of higher total sales volume, partially offset by (i) higher net payments for commodity derivatives settlements and premiums, (iii) higher acquisition, integration and strategic transaction costs paid in 2021 and (iv) executive restructuring costs including severance payments in 2021. Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during the three months endedMarch 31, 2022 as compared to the corresponding period in 2021, due primarily to the continued impact into early 2021 from the temporary suspension of the drilling program in 2020 due to the global economic downturn associated with COVID-19. This is coupled with the current economic impacts from inflation and higher costs. The following table sets forth costs related to our capital expenditures program for the periods presented: Three Months EndedMarch 31, 2022 2021 Drilling and completion $
82,794
665 788 Pipeline, gathering facilities and other equipment, net 1 2 (251) Total capital expenditures incurred $
83,461
_______________________
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:
Three Months Ended
2022 2021 Total capital expenditures program costs (from above) $
83,461
(9,361) (20,246) Net purchases of tubular inventory and well materials 1 3,587 (545)
Prepayments for drilling and completion services, net of (transfers)
(8,964) 339 Capitalized internal labor, capitalized interest and other 2,450 1,088 Total cash paid for capital expenditures $
71,173
_______________________
1 Includes purchases made in advance of drilling.
Cash Flows from Financing Activities. During the three months endedMarch 31, 2022 , we had borrowings of$50.0 million and repayments of$130.0 million under the Credit Facility. During the three months endedMarch 31, 2021 , we received over$150 million of proceeds from the issuance of equity in connection with the Juniper Transactions. These proceeds were primarily used to (i) fund the repayments of$80.5 million and$50.0 million under the Credit Facility and Second Lien Term Loan, respectively and (ii) pay$9.3 million of transaction and issue costs related to Juniper. The three months endedMarch 31, 2021 includes an additional repayment of$5 million under the Credit Facility and a$1.9 million quarterly amortization payment under the Second Lien Term Loan. 36 --------------------------------------------------------------------------------
Capitalization
The following table summarizes our total capitalization as of the dates presented: March 31, 2022 December 31, 2021 Credit facility$ 128,000 $ 208,000 9.25 Senior Notes due 2026, net 386,992 386,427 Mortgage debt 1 8,391 8,438 Other 2 322 2,516 Total debt, net 523,705 605,381 Total equity 649,325 669,508 Total capitalization$ 1,173,030 $ 1,274,889 Debt as a % of total capitalization 45 % 47 % _______________________ 1 The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As ofMarch 31, 2022 andDecember 31, 2021 , these assets were classified as Assets held for sale on the condensed consolidated balance sheets.
2 Other debt of
Credit Facility. As ofMarch 31, 2022 , the Credit Facility had a$1.0 billion revolving commitment and a$725 million borrowing base, with aggregate elected commitments of$400 million and 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 may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. Our next borrowing base redetermination is scheduled inMay 2022 . The Credit Facility is available to us for general corporate purposes including working capital. We had$0.7 million and$0.9 million in letters of credit outstanding as ofMarch 31, 2022 andDecember 31, 2021 , respectively. The maturity date under the Credit Facility isOctober 6, 2025 . The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar, including LIBOR, borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As ofMarch 31, 2022 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.02%. Unused commitment fees are charged at a rate of 0.50%. 37 -------------------------------------------------------------------------------- The following table summarizes our borrowing activity under the Credit Facility for the periods presented: Borrowings Outstanding Weighted- Weighted- End of Period Average Maximum Average Rate Three months ended March 31, 2022$ 128,000 $ 199,000 $ 228,000 3.18 % The Credit Facility is guaranteed by all of the subsidiaries of the borrower (the "Guarantor Subsidiaries"), except forBoland Building, LLC which holds real estate assets that are associated with mortgage obligations assumed in the Lonestar Acquisition. 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. 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") that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed byPenn Virginia Holdings, LLC ("Holdings"), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility. Covenant Compliance. The Credit Facility requires 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 and (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. The Credit Facility and the indenture governing the 9.25% Senior Notes due 2026 contain customary affirmative and negative covenants as well as 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 of
See Note 7 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information on our debt.
Critical Accounting Estimates
The process of preparing financial statements in accordance with 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, 2021 . 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. We had no impairments of our proved oil and gas properties during the first quarter of 2022. 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. 38
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