RANGER OIL CORPORATION 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 endedJune 30, 2022 or 2021, as applicable. This section of the Form 10-Q discusses the results of operations for the three and six months endedJune 30, 2022 compared to the three and six months endedJune 30, 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 three and six months endedJune 30, 2022 . Results for the three and six months endedJune 30, 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. 26
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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 the Eagle Ford Shale in South Texas .
Recent Developments
Share Repurchase Program
On April 13, 2022 , our Board of Directors approved a share repurchase program,
under which the Company was authorized to repurchase up to $100 million of its
outstanding Class A Common Stock through March 31, 2023 . On July 7, 2022 , the
Board of Directors authorized an increase in the share repurchase program from
$100 million to $140 million and extended the term of the program through June
30, 2023 .
During the three and six months ended June 30, 2022 , we repurchased 680,876
shares of our Class A Common Stock at a total cost of $25.0 million and at an
average purchase price of $36.74 . During July 2022 , we repurchased an additional
672,985 shares of our Class A Common Stock at an average price of $30.57 for a
total cost of $20.6 million .
See Note 12 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information.
Dividends
OnJuly 7, 2022 , the Company's Board of Directors declared a cash dividend of$0.075 per share of Class A Common Stock, payable onAugust 4, 2022 to holders of record of Class A Common Stock as of the close of business onJuly 25, 2022 .
Recent Acquisitions
In June andJuly 2022 , we closed on several acquisitions of oil and gas producing properties in theEagle Ford Shale , comprised of additional working interests in Ranger-operated wells and adjacent producing assets and undeveloped acreage for aggregate preliminary cash consideration totaling$135.5 million subject to customary purchase price adjustments.
See Note 3 and Note 15 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information on our acquisitions.
Increased Borrowing Base of Credit Facility
OnJune 1, 2022 , our borrowing base under the Credit Facility increased to$875 million from$725 million with aggregate elected commitments remaining at$400 million .
See Note 7 to the condensed consolidated financial statements included in Part I, Item 1, "Financial Statements" for additional information on our debt.
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. 27
-------------------------------------------------------------------------------- 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. InAugust 2022 , OPEC+ announced its intent to increase output targets by 100,000 bbls per day in September after raising it by 648,000 bbls per day in July and August. Most recently, WTI crude oil prices have surged but remain volatile, closing at over$120 per bbl during second 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 inflation, 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 and remain volatile as a result of theRussia -Ukraine conflict, with NYMEX Henry Hub ("NYMEX HH") closing as low as$5.47 per Mcf and as high as$9.46 per Mcf during second quarter 2022. 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.
Capital Expenditures, Development Progress and Production
As ofJune 30, 2022 , we operated three drilling rigs and during the six months endedJune 30, 2022 , we incurred capital expenditures of approximately$207.0 million , of which$204.9 million was directed to drilling and completion projects. During the second quarter 2022, a total of 13 gross (12.3 net) wells were completed and turned in line.
As of
Total sales volume for the second quarter 2022 was 3,502 thousand barrels of oil
equivalent ("Mboe"), or 38,479 barrels of oil equivalent ("boe") per day, with
approximately 71%, or 2,502 thousand barrels of oil ("Mbbl"), of sales volume
from crude oil, 15% from NGLs and 14% from natural gas.
28
--------------------------------------------------------------------------------Commodity Hedging Program 1
As ofJuly 29, 2022 , we have hedged a portion of our estimated future crude oil and natural gas production fromJuly 1, 2022 through the first half of 2024. The following table summarizes our net hedge position for the periods presented: 3Q2022 4Q2022 1Q2023 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 3,000 3,000 2,500 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl)$ 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) 15,625 15,625 7,917 6,181 4,891 2,446 Weighted Average Purchased Put Price ($/bbl)$ 59.22 $ 61.30 $ 55.79 $ 50.67 $ 70.00 $ 65.00 Weighted Average Sold Call Price ($/bbl)$ 84.70 $ 86.98 $ 74.85 $ 65.65 $ 92.37 $ 85.75 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 7,337 1,630 Weighted Average Swap Price ($/bbl)$ 1.172 $ 1.020 NYMEX HH Swaps Average Volume Per Day (MMBtu) 12,500 12,500 10,000 7,500 Weighted Average Swap Price ($/MMBtu)$ 3.745 $ 3.793 $ 3.620 $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 15,679 14,511 6,417 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu)$ 3.088 $ 2.854 $ 6.000 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price ($/MMBtu)$ 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) 27,717 27,717 98,901 34,239 34,239 34,615 Weighted Average Fixed Price ($/gal)$ 0.2500 $ 0.2500 $ 0.2288 $ 0.2275 $ 0.2275 $ 0.2275 _______________________ 1 As ofJuly 29, 2022 , we also had 50,000 bbls/month of incremental WTI Long Calls at$125 /bbl in August andSeptember 2022 as well as 25,000 bbls/month of incremental WTI Long Puts at$85 /bbl in August andSeptember 2022 . 29 --------------------------------------------------------------------------------
Results of Operations
The following table sets forth certain historical summary operating and financial statistics for the periods presented:
Three Months Ended Six Months Ended June 30,
June 30, 2022 March 31, 2022 June 30, 2021 2022 2021
Total sales volume (Mboe) 1 3,502 3,398 2,261 6,899 4,109
Average daily sales volume (boe/d) 1 38,479 37,752 24,844 38,118 22,701
Crude oil sales volume (Mbbl) 1 2,502 2,428 1,831 4,930 3,300
Crude oil sold as a percent of total 1 71 % 71 % 81 % 71 % 80 %
Product revenues $ 313,444 $ 255,599 $ 123,789 $ 569,043 $ 212,097
Crude oil revenues$ 273,589 $ 226,732 $ 116,314 $ 500,321 $
198,227
Crude oil revenues as a percent of total 87 % 89 % 94 % 88 % 93 % Realized prices: Crude oil ($/bbl)$ 109.34 $ 93.38 $ 63.54 $ 101.48 $ 60.07 NGLs ($/bbl)$ 36.77 $ 33.40 $ 18.31 $ 35.11 $ 17.68 Natural gas ($/Mcf)$ 7.19 $ 4.32$ 2.70 $ 5.78 $ 2.75 Aggregate ($/boe)$ 89.51 $ 75.23 $ 54.75 $ 82.48 $ 51.62 Realized prices, including effects of derivatives, net 2 Crude oil ($/bbl)$ 84.43 $ 74.00 $ 52.70 $ 79.29 $ 49.18 NGLs ($/bbl)$ 35.10 $ 33.40 $ 17.87 $ 34.27 $ 17.44 Natural gas ($/Mcf)$ 4.08 $ 3.96$ 2.71 $ 4.02 $ 2.77 Aggregate ($/boe)$ 68.87 $ 61.08 $ 45.93 $ 65.03 $ 42.86 Production and lifting costs: Lease operating ($/boe)$ 5.40 $ 5.33$ 4.30 $ 5.36 $ 4.52 Gathering, processing and transportation ($/boe)$ 2.47 $ 2.66$ 2.29 $ 2.56 $ 2.40
Production and ad valorem taxes ($/boe)
$ 2.98
General and administrative ($/boe) 3
$ 4.91 Depreciation, depletion and amortization ($/boe)$ 15.50 $ 14.98 $ 12.74 $ 15.25 $ 12.82 _______________________ 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$0.71 ,$0.79 and$0.43 per boe for the three months endedJune 30, 2022 ,March 31, 2022 andJune 30, 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 and second quarters of 2022 as well as costs attributable to our acquisitions in the second quarter of 2022 as described in the discussion of "Results of Operations - General and Administrative" that follows. 30 --------------------------------------------------------------------------------
Sequential Quarterly Analysis
The following summarizes our key operating and financial highlights for the three months endedJune 30, 2022 , with comparison to the three months endedMarch 31, 2022 . The year-over-year highlights for the quarterly periods endedJune 30, 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 increased to 38,479 boe per day from 37,752 boe per day with 12.3 net wells turned in line for the second quarter 2022 compared to 8.9 net wells turned in line for the first quarter 2022. Total sales volume increased 3% to 3,502 Mboe from 3,398 Mboe. •Product revenues increased 23% to$313.4 million from$255.6 million as a result of 19% higher aggregate realized prices and 3% higher total sales volumes. Crude oil realized prices were 17% higher, or$39.9 million , coupled with higher crude oil sales volume, or$6.9 million . NGL revenues were higher due to 2% higher total sales volume, or$0.4 million , and 10% higher realized prices, or$1.7 million . Natural gas revenues were 73% higher as a result of 66% higher realized prices and 4% higher volume for an overall increase of$8.9 million . •Production and lifting costs, consisting of Lease operating expenses ("LOE") and Gathering, processing and transportation expenses ("GPT"), increased on an absolute basis to$27.5 million from$27.1 million and decreased on a per unit basis to$7.87 per boe from$7.99 per boe. The per unit basis decrease is due to the effects of 3% higher sales volume.
•Production and ad valorem taxes increased on an absolute and per unit basis to
•General and administrative ("G&A") expenses increased on an absolute and per
unit basis to $10.6 million and $3.04 per boe from $9.8 million and $2.88 per
boe, respectively, primarily due to $1.3 million higher consulting and
professional services fees and $1.1 million increased compensation cost
associated with employee share-based compensation granted during second quarter
2022, partially offset by $1.3 million lower acquisition and integration costs
associated with the Lonestar Acquisition as those efforts were substantially
completed by the end of the first quarter 2022.
•Depreciation, depletion and amortization ("DD&A") increased on an absolute and
per unit basis to $54.3 million and $15.50 per boe during the second quarter
2022 as compared to $50.9 million and $14.98 per boe during the first quarter
2022 due primarily to the oil and gas property acquisitions that closed during
the second quarter 2022 and higher development costs.
31
--------------------------------------------------------------------------------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 June 30, Six Months Ended June 30,
Total Sales Volume 1 2022 2021 Change % Change 2022 2021 Change % Change
Crude oil (Mbbl) 2,502 1,831 671 37 % 4,930 3,300 1,630 49 %
NGLs (Mbbl) 512 240 272 113 % 1,013 450 563 125 %
Natural gas (MMcf) 2,926 1,143 1,783 156 % 5,737 2,156 3,581 166 %
Total (Mboe) 3,502 2,261 1,241 55 % 6,899 4,109 2,790 68 %
Three Months Ended June 30, Six Months Ended June 30,
Average Daily Sales
Volume 1 2022 2021 Change % Change 2022 2021 Change % Change
Crude oil (bbl/d) 27,496 20,117 7,379 37 % 27,239 18,231 9,008 49 %
NGLs (bbl/d) 5,624 2,633 2,991 114 % 5,596 2,485 3,111 125 %
Natural gas (MMcf/d) 32 13 19 146 % 32 12 20 167 %
Total (boe/d) 38,479 24,844 13,635 55 % 38,118 22,701 15,417 68 %
_______________________
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 55% and 68% during the three and six month periods
in 2022, respectively, when compared to the corresponding periods in 2021 as a
result of the Lonestar Acquisition that closed in fourth quarter of 2021 and
increased drilling activity. Additionally, during the three month period in
2022, total sales volume increased compared to the corresponding period in 2021
due to 12.3 net wells turned in line in the three month period in 2022 as
compared to 8.2 net wells in the corresponding period in 2021.
Approximately 71% of total sales volume during the three and six month periods
in 2022 was attributable to crude oil when compared to approximately 81% and
80%, respectively, 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 June 30, Six Months Ended June 30,
Total Product Revenues 2022 2021 Change % Change 2022 2021 Change % Change
Crude oil $ 273,589 $ 116,314 $ 157,275 135 % $ 500,321 $ 198,227 $ 302,094 152 %
NGLs 18,818 4,388 14,430 329 % 35,558 7,950 27,608 347 %
Natural gas 21,037 3,087 17,950 581 % 33,164 5,920 27,244 460 %
Total $ 313,444 $ 123,789 $ 189,655 153 % $ 569,043 $ 212,097 $ 356,946 168 %
Realized Prices Three Months Ended June 30, Six Months Ended June 30,
($ per unit of volume) 2022 2021 Change % Change 2022 2021 Change % Change
Crude oil $ 109.34 $ 63.54 $ 45.80 72 % $ 101.48 $ 60.07 $ 41.41 69 %
NGLs $ 36.77 $ 18.31 $ 18.46 101 % $ 35.11 $ 17.68 $ 17.43 99 %
Natural gas $ 7.19 $ 2.70 $ 4.49 166 % $ 5.78 $ 2.75 $ 3.03 110 %
Total $ 89.51 $ 54.75 $ 34.76 63 % $ 82.48 $ 51.62 $ 30.86 60 %
32
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The following table provides an analysis of the changes in our revenues for the periods presented:
Three Months Ended June 30, 2022 vs. 2021 Six Months Ended June 30, 2022 vs. 2021
Revenue Variance Due to Revenue Variance Due to
Volume Price Total Volume Price Total
Crude oil $ 42,664 $ 114,611 $ 157,275 $ 97,949 $ 204,145 $ 302,094
NGLs 4,984 9,446 14,430 9,956 17,652 27,608
Natural gas 4,815 13,135 17,950 9,833 17,411 27,244
$ 52,463 $ 137,192 $ 189,655 $ 117,738 $ 239,208 $ 356,946
Our product revenues during the three and six month periods in 2022 increased
compared to the corresponding periods in 2021 due to significantly higher prices
from continued economic recovery, as well as supply concerns resulting from the
Russia -Ukraine conflict. These factors resulted in an increase to the NYMEX WTI
benchmark price of 64% for the three and six month periods in 2022 as compared
to the corresponding periods in 2021. 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 55% and 68% for three and six
month periods in 2022, respectively.
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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Realized crude oil prices
($/bbl) $ 109.34 $ 63.54 $ 45.80 72 % $ 101.48 $ 60.07 $ 41.41 69 %
Average WTI prices 108.52 66.17 42.35 64 % 101.77 62.22 39.55 64 %
Realized differential to
WTI $ 0.82 $ (2.63) $ 3.45 131 % $ (0.29) $ (2.15) $ 1.86 87 %
Realized natural gas
prices ($/Mcf) $ 7.19 $ 2.70 $ 4.49 166 % $ 5.78 $ 2.75 $ 3.03 110 %
Average HH prices
($/MMBtu) 7.40 2.88 4.52 157 % 6.01 3.13 2.88 92 %
Realized differential to
HH $ (0.21) $ (0.18) $ (0.03) (17) % $ (0.23) $ (0.38) $ 0.15 39 %
Our differential to NYMEX WTI for the three and six month periods in 2022,
improved by 131% and 87%, respectively, compared to the corresponding periods 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
was fairly consistent for the three month period in 2022 as compared to the
corresponding period in 2021, while the differential improved for the six month
period in 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").
33
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The following table presents the calculation of our non-GAAP realized prices for
crude oil, NGLs 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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Realized crude oil prices
($/bbl) $ 109.34 $ 63.54 $ 45.80 72 % $ 101.48 $ 60.07 $ 41.41 69 %
Effects of derivatives,
net ($/bbl) (24.91) (10.84) (14.07) (130) % (22.19) (10.89) (11.30) (104) %
Crude oil realized
prices, including effects
of derivatives, net
($/bbl) $ 84.43 $ 52.70 $ 31.73 60 % $ 79.29 $ 49.18 $ 30.11 61 %
Realized natural gas
liquid prices ($/bbl) $ 36.77 $ 18.31 $ 18.46 101 % $ 35.11 $ 17.68 $ 17.43 99 %
Effects of derivatives,
net ($/bbl) (1.67) (0.44) (1.23) (280) % (0.84) (0.24) (0.60) (250) %
Natural gas liquids
realized prices,
including effects of
derivatives, net ($/bbl) $ 35.10 $ 17.87 $ 17.23 96 % $ 34.27 $ 17.44 $ 16.83 97 %
Realized natural gas
prices ($/Mcf) $ 7.19 $ 2.70 $ 4.49 166 % $ 5.78 $ 2.75 $ 3.03 110 %
Effects of derivatives,
net ($/Mcf) (3.11) 0.01 (3.12) NM (1.76) 0.02 (1.78) NM
Natural gas realized
prices, including effects
of derivatives, net
($/Mcf) $ 4.08 $ 2.71 $ 1.37 51 % $ 4.02 $ 2.77 $ 1.25 45 %
_______________________
NM - percentage change not meaningful
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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Other operating income, net $ 1,047 $ 910 $ 137 15 % $ 1,903 $ 1,157 $ 746 64 %
Our marketing fee income increased in the three and six month periods in 2022,
as compared to the corresponding periods in 2021 due primarily to the higher
commodity-based pricing. Additionally, the six month period in 2022 included a
gain on sales of field materials.
34
--------------------------------------------------------------------------------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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Lease operating $ 18,908 $ 9,728 $ 9,180 94 % $ 37,010 $ 18,553 $ 18,457 99 %
Per unit ($/boe) $ 5.40 $ 4.30 $ 1.10 26 % $ 5.36 $ 4.52 $ 0.84 19 %
LOE increased on an absolute basis and per unit basis during three and six month
periods in 2022 as compared to the corresponding periods in 2021 due primarily
to the impact of the Lonestar Acquisition as well as increased workovers and
increased fuel, service and equipment 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.
The following table sets forth our GPT expense for the periods presented:
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
GPT $ 8,638 $ 5,173 $ 3,465 67 % $ 17,678 $ 9,847 $ 7,831 80 %
Per unit ($/boe) $ 2.47 $ 2.29 $ 0.18 8 % $ 2.56 $ 2.40 $ 0.16 7 %
GPT expense increased on an absolute basis and per unit basis during the three
and six month periods in 2022 as compared to the corresponding periods in 2021
due primarily to the impact of the Lonestar Acquisition, which contributed to
the 156% and 166% higher natural gas sales volumes and 37% and 49% higher crude
oil sales volumes for the three and six month periods in 2022, respectively.
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 the three and six month periods in 2022, as compared to the
corresponding periods in 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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Production/severance taxes $ 14,504 $ 5,777 $8,727 151 % $ 26,074 $ 10,019 $ 16,055 160 %
Ad valorem taxes 2,270 944 1,326 140 % 3,840 2,215 1,625 73 %
$ 16,774 $ 6,721 $10,053 150 % $ 29,914 $ 12,234 $ 17,680 145 %
Per unit ($/boe) $ 4.79 $ 2.97 $ 1.82 61 % $ 4.34 $ 2.98 $ 1.36 46 %
Production/severance tax rate as a
percent of product revenues 4.6 % 4.7 % (0.1) % (2) % 4.6 % 4.7 % (0.1) % (2) %
Production and ad valorem taxes increased on an absolute basis and per unit basis during the three and six month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of higher volumes from the Lonestar Acquisition. Additionally, Production taxes increased on an absolute and per unit basis due to higher aggregate commodity sales prices during the three and six month periods in 2022.
35
--------------------------------------------------------------------------------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 special charges that are
generally attributable to 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 expenses for the
periods presented:
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Primary G&A expenses $ 8,151 $ 6,023 $ 2,128 35 % $ 15,263 $ 12,060 $ 3,203 27 %
Share-based compensation 2,049 962 1,087 113 % 2,973 3,208 (235) (7) %
Significant special charges:
Organizational restructuring,
including severance - - - - % - 239 (239) (100) %
Acquisition/integration and
strategic transaction costs 435 - 435 100 % 2,178 4,655 (2,477) (53) %
Total G&A expenses $ 10,635 $ 6,985 $ 3,650 52 % $ 20,414 $ 20,162 $ 252 1 %
Per unit ($/boe) $ 3.04 $ 3.09 $ (0.05) (2) % $ 2.96 $ 4.91 $ (1.95) (40) %
Per unit ($/boe) excluding
share-based compensation and other
special charges identified above $ 2.33 $ 2.66 $ (0.33) (12) % $ 2.21 $ 2.94 $ (0.73) (25) %
Our total G&A expenses were higher on an absolute basis during the three month
period in 2022 when compared to the corresponding period in 2021 due primarily
to increased headcount discussed below and higher share-based compensation cost
but relatively flat on a per unit basis due to a 55% increase in total volumes
in 2022. Total G&A was relatively flat on an absolute basis for the six month
period in 2022 when compared to the corresponding period in 2021 but decreased
on a per unit basis due to a 68% increase in total volumes in 2022.
Our primary G&A expenses increased on an absolute basis during the three and six
month periods in 2022 as compared to the corresponding periods in 2021 due
primarily to increased headcount following the Lonestar Acquisition and the
impact of salary increases effective
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 13 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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
DD&A expense $ 54,290 $ 28,795 $ 25,495 89 % $ 105,183 $ 52,679 $ 52,504 100 %
DD&A rate ($/boe) $ 15.50 $ 12.74 $ 2.76 22 % $ 15.25 $ 12.82 $ 2.43 19 %
DD&A expense increased on an absolute and a per unit basis during the three and
six month periods in 2022 as compared to the corresponding periods in 2021.
Higher production volume provided for an increase of $15.8 million and $35.8
million and a higher DD&A rate resulted in an increase of $9.7 million and $16.8
million , for the three and six month periods in 2022, respectively. 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 corresponding periods in 2021.
36
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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. We did not record an impairment of our oil and gas properties during the three and six month periods in 2022. We recorded an impairment of$1.8 million in the six months endedJune 30, 2021 as a result of capitalized costs of oil and gas properties exceeding the ceiling test in the first quarter of 2021. The impairment in 2021 was the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by the respective quarterly Ceiling Test under the full cost method of accounting for oil and gas properties. Interest Expense Interest expense for periods in 2022 includes charges for outstanding borrowings under the Credit Facility derived from internationally recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. Also included are the amortization of issuance costs capitalized attributable to the Credit Facility and the 9.25% Senior Notes due 2026 and accretion of original issue discount ("OID") on the 9.25% Senior Notes due 2026. Interest expense for the periods in 2021 includes charges for outstanding borrowings under the Credit Facility and the Second Lien Credit Agreement, datedSeptember 29, 2017 (the "Second Lien Term Loan") which was repaid in full inOctober 2021 , as well as amortization of their respective issuance costs capitalized. Also included is the accretion of OID on the Second Lien Term Loan. In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage. The following table summarizes the components of our interest expense for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 Change % Change 2022 2021 Change % Change Interest on borrowings and related fees$ 11,290 $ 5,533 $ 5,757 104 %$ 22,247 $ 11,165 $ 11,082 99 % Accretion of original issue discount 165 85 80 94 % 325 190 135 71 % Amortization of debt issuance costs 706 483 223 46 % 1,346 989 357 36 % Capitalized interest (1,123) (798) (325) 41 % (2,183) (1,644) (539) 33 % Total interest expense, net of capitalized interest$ 11,038 $ 5,303 $ 5,735 108 %$ 21,735 $ 10,700 $ 11,035 103 % The increase in interest expense during the three month period in 2022 is primarily attributable to interest incurred in the amount of$9.2 million for the 9.25% Senior Notes due 2026 and$1.6 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of$3.4 million for the Second Lien Term Loan and$1.9 million for the Credit Facility as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during the three month period in 2022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding period in 2021. The increase in interest expense during the six month period in 2022 is primarily attributable to interest incurred in the amount of$18.1 million for the 9.25% Senior Notes due 2026 and$3.3 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of$7.0 million for the Second Lien Term Loan and$3.9 million for the Credit Facility as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during the six month period in 2022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding periods in 2021. 37 --------------------------------------------------------------------------------
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 June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Commodity derivative
losses $ (44,923) $ (54,231) $ 9,308 (17) % $ (212,893) $ (98,631) $ (114,262) 116 %
Interest rate swap gains
(losses) (19) 4 (23) (575) % 64 36 28 78 %
Total $ (44,942) $ (54,227) $ 9,285 (17) % $ (212,829) $ (98,595) $ (114,234) 116 %
In the three and six month periods 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 and six 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 these periods. Realized
settlement payments, net for crude oil, NGL and natural gas derivatives were
$74.0 million and $102.5 million for the three and six month periods in 2022,
respectively, and $15.7 million and $21.9 million during the three and six month
periods in 2021, respectively. We hedge a portion of our exposure to variable
interest rates associated with our Credit Facility and, in the three and six
month periods in 2021, our Second Lien Term Loan. We paid $0.5 million and
$1.4 million of net settlements from our interest rate swaps for the three and
six month periods in 2022, respectively, and $1.0 million and $1.9 million for
the corresponding periods in 2021, 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.
The following table summarizes our income taxes for the periods presented:
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 Change % Change 2022 2021 Change % Change
Income tax (expense)
benefit $ (1,308) $ (171) $ (1,137) 665 % $ (1,119) $ 139 $ (1,258) (905) %
Effective tax rate 0.9 % 2.2 % (1.3) % (59) % 0.9 % 1.1 % (0.2) % (18) %
The income tax provision resulted in an expense of $1.3 million and an expense
of $1.1 million for the three and six month periods in 2022, 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 0.9%,
which is fully attributable to the State of Texas . Our net deferred income tax
liability balance of $2.9 million as of June 30, 2022 is also fully attributable
to the State of Texas and primarily related to property.
The income tax provision resulted in an expense of $0.2 million and a benefit of
$0.1 million for the three and six month periods in 2021, respectively. 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 1.1% which was fully attributable to the State of Texas .
38
--------------------------------------------------------------------------------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 ofJune 30, 2022 , we had liquidity of$262.8 million , comprised of cash and cash equivalents of$34.5 million and availability under our Credit Facility of$228.3 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$875.0 million with aggregate elected commitments of$400.0 million . As ofJuly 29, 2022 , we had liquidity of$175.0 million , comprised of cash and cash equivalents of$15.7 million and availability under the Credit Facility of$159.3 million (factoring in letters of credit). 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, as well as recession fears that impacts demand. 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 We expect full year 2022 drilling and completions capital expenditures of between$440 and$470 million . 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,Russia -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."
Dividends
OnJuly 7, 2022 , the Company's Board of Directors declared a cash dividend of$0.075 per share of Class A Common Stock, payable onAugust 4, 2022 to holders of record of Class A Common Stock as of the close of business onJuly 25, 2022 . In connection with any dividend, Ranger's operating subsidiary will also make a corresponding distribution to its common unitholders. We expect to fund dividends and distributions from available working capital and cash provided by operating activities. Share Repurchase Program InApril 2022 , we announced that the Board of Directors approved a share repurchase program under which we were authorized to repurchase up to$100 million of outstanding Class A Common Stock throughMarch 31, 2023 . Subsequently onJuly 7, 2022 , the Board of Directors authorized an increase in the share repurchase program from$100 million to$140 million and extended the term of the program throughJune 30, 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, 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 39 -------------------------------------------------------------------------------- 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. At this time, 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. Cash Flows
The following table summarizes our cash flows for the periods presented:
Six Months Ended
2022 2021
Net cash provided by operating activities $ 298,884 $ 123,225
Net cash used in investing activities (226,009) (95,553)
Net cash provided by (used in) financing activities (62,106) 9,002
Net increase in cash and cash equivalents $
10,769
Cash Flows from Operating Activities. The increase of$175.7 million in net cash provided by operating activities for the six months endedJune 30, 2022 compared to the corresponding period in 2021 was primarily attributable to the effect of 2022 cash receipts that were derived from higher average prices and higher total sales volume, partially offset by higher net payments for commodity derivatives settlements and premiums. Additionally, during the six months endedJune 30, 2021 , there were higher acquisition, integration and strategic transaction costs and executive restructuring costs including severance payments. Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during the six months endedJune 30, 2022 as compared to the corresponding period in 2021, due primarily to significantly increased drilling and completions activities in 2022, coupled with the current economic impacts from inflation and higher costs, and oil and gas property acquisitions closed and deposits paid in the second quarter of 2022. Early 2021 was impacted by the temporary suspension of the drilling program that began in 2020 due to the global economic downturn associated with COVID-19. The following table sets forth costs related to our capital expenditures program for the periods presented: Six Months EndedJune 30, 2022 2021 Drilling and completion $
204,939
2,299 1,219
Pipeline, gathering facilities and other equipment, net 1 (204) (481)
Total capital expenditures incurred $ 207,034 $ 122,853
_______________________
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:
Six Months Ended
2022 2021
Total capital expenditures program costs (from above) $
207,034
(30,461) (22,891)
Net purchases of tubular inventory and well materials 1 1,718 2,851
Prepayments for drilling and completion services, net of (transfers)
(8,784) (10,023) Capitalized internal labor, capitalized interest and other 4,737 2,916 Total cash paid for capital expenditures $
174,244
_______________________
1 Includes purchases made in advance of drilling.
Cash Flows from Financing Activities. During the six months endedJune 30, 2022 , we had borrowings of$243.0 million and repayments of$280.0 million under the Credit Facility and$24.1 million of share repurchases. During the six months endedJune 30, 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 six months endedJune 30, 2021 includes an additional repayment of$5 million under the Credit Facility and a$3.8 million quarterly amortization payment under the Second Lien Term Loan. 40 --------------------------------------------------------------------------------
Capitalization
The following table summarizes our total capitalization as of the dates presented:
June 30, 2022 December 31, 2021
Credit Facility $ 171,000 $ 208,000
9.25 Senior Notes due 2026, net 387,604 386,427
Mortgage debt 1 8,304 8,438
Other 2 318 2,516
Total debt, net 567,226 605,381
Total equity 774,151 669,508
Total capitalization $ 1,341,377 $ 1,274,889
Debt as a % of total capitalization 42 % 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 of June 30, 2022 and December 31, 2021 ,
these assets were classified as Assets held for sale on the condensed
consolidated balance sheets. In July 2022 , the mortgage debt was fully repaid in
connection with the sale of the corporate office building. See Note 15 to the
condensed consolidated financial statements included in Part I, Item 1,
"Financial Statements" for additional information on the sale.
2 Other debt of
Credit Facility. As ofJune 30, 2022 , the Credit Facility had a$1.0 billion revolving commitment and an$875 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 expected to be inAugust 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 ofJune 30, 2022 andDecember 31, 2021 , respectively. The maturity date under the Credit Facility isOctober 6, 2025 . InJune 2022 , we entered into the Agreement and Amendment No. 12 to Credit Agreement (the "Twelfth Amendment"). The Twelfth Amendment, in addition to other changes described therein, amended the Credit Facility to, effective onJune 1, 2022 , (1) increase the borrowing base from$725 million to$875 million , with aggregate elected commitments remaining at$400 million and (2) replaced LIBOR with the Secured Overnight Financing Rate ("SOFR"), an index supported by short-termTreasury repurchase agreements. 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) effectiveJune 1, 2022 , a term SOFR reference rate (a Eurodollar rate, including LIBOR prior toJune 1, 2022 ), 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 SOFR, 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 ofJune 30, 2022 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.98%. Unused commitment fees are charged at a rate of 0.50%. 41 -------------------------------------------------------------------------------- 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
4.08 %
Six months ended
3.58 %
The Credit Facility is guaranteed by all of the subsidiaries of the borrower
(the "Guarantor Subsidiaries"), except for Boland Building, LLC . 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. On August 10, 2021 , our indirect, wholly-owned
subsidiary 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 by ROCC Holdings, LLC (formerly, Penn
Virginia Holdings, LLC , hereinafter referred to as "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 and second 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 for the six months endedJune 30, 2021 . 42
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