RANGER OIL CORPORATI

ROCC
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RANGER OIL CORP Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

05/05/2022 | 05:45pm


The following discussion and analysis of the financial condition and results of
operations of Ranger 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 ended March
31, 2022
or 2021, as applicable.

This section of the Form 10-Q discusses the results of operations for the
quarter ended March 31, 2022 compared to the quarter ended March 31, 2021 unless
otherwise indicated. On October 5, 2021, the Company acquired Lonestar Resources
US Inc., a Delaware corporation ("Lonestar"), as a result of which Lonestar and
its subsidiaries became wholly-owned subsidiaries of Ranger Oil (the "Lonestar
Acquisition"). The results of operations of Lonestar are reflected in our
accompanying condensed consolidated financial statements for the quarter ended
March 31, 2022. Results for the quarter ended March 31, 2021 reflect the
financial and operating results of Ranger 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.


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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




On April 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 through March 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.

On May 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 in March
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 the Organization of the Petroleum Exporting Countries ("OPEC") and
Russia (together with OPEC, collectively "OPEC+") continued to execute its
strategy throughout 2021 to gradually increase production. In its most recent
March 2022 meeting, OPEC+ reconfirmed the agreement to increase output targets
each month by 432,000 bbl/day beginning May 1, 2022. Most recently, WTI crude
oil prices have surged, closing at over $120 per bbl during first quarter 2022
as a result of the Russia-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 the Russia-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.

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Capital Expenditures, Development Progress and Production




During the three months ended March 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 April 28, 2022, we had approximately 170,800 gross (139,900 net) acres in
the Eagle Ford, net of expirations, of which approximately 95% is held by
production.




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 of April 28, 2022, we have hedged a portion of our estimated future crude oil
and natural gas production from April 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




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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 $ 191,079 $ 81,913
Crude oil revenues as a percent of total



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 ended March 31, 2022, December 31, 2021 and March 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.

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Sequential Quarterly Analysis




The following summarizes our key operating and financial highlights for the
three months ended March 31, 2022, with comparison to the three months ended
December 31, 2021. The year-over-year highlights for the quarterly periods ended
March 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.


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Year over Year Analysis of Operating and Financial Results



Sales Volume



The following tables set forth a summary of our total and average daily sales
volumes by product for the periods presented:




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 ended March 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 %



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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 the
Russia-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 ended
March 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 ended March 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 ended
March 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").


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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.


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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.


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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 $ 2.09


$ 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 effective January 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.


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Impairment of Oil and Gas Properties




We assess our oil and gas properties on a quarterly basis based on the results
of a comparison of the unamortized cost of our oil and gas properties, net of
deferred income taxes, to the sum of our estimated after-tax discounted future
net revenues from proved properties adjusted for costs excluded from
amortization (the "Ceiling Test") in accordance with the full cost method of
accounting for oil and gas properties.

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 September 29, 2017 (the "Second Lien Term Loan") which was
repaid in full in October 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 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.


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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, primarily Texas, 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 ended March 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 the
State of Texas. Our net deferred income tax liability balance of $2.1 million as
of March 31, 2022 is also fully attributable to the State of Texas and primarily
related to property.

The income tax provision resulted in a benefit of $0.3 million for the three
months ended March 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 the
State of Texas.

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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 of March 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 of April 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 the Russia-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 and 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."


Share Repurchase Program




In April 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 through March 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 its
U.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 its U.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 ending December 31, 2022 or in future years.

35

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Cash Flows



The following table summarizes our cash flows for the periods presented:



Three Months Ended March 31,



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) $ (1,152)





Cash Flows from Operating Activities. The increase of $101.1 million in net cash
provided by operating activities for the three months ended March 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 ended March 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 Ended March 31,
2022
2021
Drilling and completion $



82,794 $ 53,585
Lease acquisitions, land-related costs, and geological and geophysical
(seismic) costs


665 788
Pipeline, gathering facilities and other equipment, net 1 2 (251)
Total capital expenditures incurred $


83,461 $ 54,122



_______________________



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 March 31,



2022 2021
Total capital expenditures program costs (from above) $


83,461 $ 54,122
Increase in accounts payable for capital items and accrued
capitalized costs


(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 $ 34,758



_______________________



1 Includes purchases made in advance of drilling.




Cash Flows from Financing Activities. During the three months ended March 31,
2022
, we had borrowings of $50.0 million and repayments of $130.0 million under
the Credit Facility. During the three months ended March 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 ended March 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

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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 of March 31, 2022 and December 31, 2021,
these assets were classified as Assets held for sale on the condensed
consolidated balance sheets.


2 Other debt of $2.2 million was extinguished during the three months ended
March 31, 2022 and recorded as a gain on extinguishment of debt.




Credit Facility. As of March 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 in May 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 of March 31, 2022 and December 31, 2021, respectively. The maturity date
under the Credit Facility is October 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 of March 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

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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 for Boland 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. On August 10, 2021, our indirect, wholly-owned
subsidiary Penn 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
by Penn 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 March 31, 2022, we were in compliance with all of the debt covenants.



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 ended December 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 of March 31, 2021, resulting in a $1.8
million
impairment.

38



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