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OFFON

RANGER OIL CORPORATION

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

11/04/2021 | 09:54am EST
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 statistics
for the prior period have been reclassified to conform to the current period
presentation. References to "quarters" represent the three months ended
September 30, 2021 or 2020, as applicable.

Overview and Executive Summary
We are an independent oil and gas company focused on the onshore development and
production of crude oil, natural gas liquids ("NGLs"), and natural gas. Our
current operations consist of drilling unconventional horizontal development
wells and operating our producing wells in the Eagle Ford Shale in South Texas.
Recent Developments
Acquisition of Lonestar Resources
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 "Merger"). Lonestar's oil
and gas properties are located in the Eagle Ford Shale in South Texas.
In accordance with the terms of the Merger, Lonestar shareholders received 0.51
shares of Penn Virginia Corporation ("Penn Virginia") common stock for each
share of Lonestar common stock held immediately prior to the effective time of
the Merger. Based on the closing price of Penn Virginia common stock on October
5, 2021 of $30.19, the total value of Penn Virginia common stock issued to
holders of Lonestar common stock, warrants and restricted stock units as
applicable, was approximately $173.6 million.
Following the completion of the Merger, the Company changed its name from Penn
Virginia to Ranger Oil Corporation, and its Class A common stock ("Class A
Common Stock") began trading on the Nasdaq under the ticker symbol "ROCC" on
October 18, 2021. As the Merger was completed after the quarterly period ended
September 30, 2021, our results exclude Lonestar's financial information and
operating results for all periods presented and discussed herein.
See Note 14 to the condensed consolidated financial statements included in Part
I, Item 1, "Financial Statements" for additional information.
Financing Updates
9.25% Senior Notes due 2026
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"). These notes bear interest at 9.25% and were sold at 99.018% of par.
Debt Repayments
In connection with the consummation of the Merger, the net proceeds from the
offering of $400 million aggregate principal amount of 9.25% Senior Notes due
2026 and certain additional funds totaling $411.5 million were released from
escrow on October 5, 2021. Obligations under the 9.25% Senior Notes due 2026
were assumed by Holdings, as borrower, and are guaranteed by the subsidiaries of
Holdings that guarantee our credit agreement (the "Credit Facility").
The net proceeds from the 9.25% Senior Notes due 2026 were used to repay and
discharge $249.8 million of Lonestar's long-term debt including accrued interest
and related expenses, and the remainder, along with cash on hand, of
$146.2 million was used to repay the Second Lien Credit Agreement, dated as of
September 29, 2017 (the "Second Lien Facility") including a prepayment premium
and accrued interest and related expenses.
Increased Borrowing Base of Credit Facility
Upon closing of the Merger, our borrowing base under the Credit Facility
increased to $600 million with aggregate elected commitments of $400 million.
See Note 7 and Note 14 to the condensed consolidated financial statements
included in Part I, Item 1, "Financial Statements" for additional information on
our debt.
Hedging Update
                                       26

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Immediately following the Merger, we paid approximately $50 million to
restructure certain of Lonestar's derivatives, which was funded by borrowings
under our Credit Facility. We have reset the majority of the swaps to reflect
current market pricing.

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Recapitalization of the Company's Common Stock
On October 6, 2021, the Company effected a recapitalization (the
"Recapitalization"), pursuant to which (i) the Company's common stock was
renamed and reclassified as Class A common stock, (ii) the authorized number of
shares of capital stock of the Company was increased to 145,000,000 shares,
(iii) 30,000,000 shares of Class B common stock, par value of $0.01 per share
("Class B Common Stock"), a new class of capital stock of the Company, was
authorized, (iv) all outstanding shares of the Series A Preferred Stock were
exchanged for newly issued shares of Class B Common Stock, and (v) the
designation of the Series A Preferred Stock was cancelled.
See Note 14 to the condensed consolidated financial statements included in Part
I, Item 1, "Financial Statements" for additional information.
Strategic Investment by Juniper
In January 2021, we consummated the Juniper Transactions whereby affiliates of
Juniper contributed $150 million in cash and certain oil and gas assets in
Lavaca and Fayette Counties in Texas to us in exchange for equity that entitles
Juniper to both vote and share in any dividend on the same basis as 22,548,998
shares of common stock (after post-closing adjustments). For additional
information regarding the Juniper Transactions, see Note 3 to the condensed
consolidated financial statements included in Part I, Item 1, "Financial
Statements."
Industry Environment and Recent Operating and Financial Highlights
Commodity Price and Other Economic Conditions
As an oil and gas development and production company, we are exposed to a number
of risks and uncertainties that are inherent to our industry. In addition to
such industry-specific risks, the global public health crisis associated with
the novel coronavirus ("COVID-19") continues to create uncertainty for global
economic activity. Over the past 18 months, the slowdown in global economic
activity attributable to COVID-19 resulted in a dramatic decline in the demand
for energy beginning in March 2020, which directly impacted our industry and the
Company. Most recently, however, increased mobility and other factors has
resulted in increased oil demand and commodity prices.
In addition, there remains a high level of uncertainty regarding the volatility
of energy supply and demand as the Organization of the Petroleum Exporting
Countries ("OPEC") and Russia (together with OPEC, collectively "OPEC+") reached
an agreement in July 2021 to increase production over this past quarter. In
early October 2021, OPEC+ reconfirmed the agreement to boost output during the
fourth quarter 2021. Higher energy prices may add to inflationary pressures,
which could lead to increased service costs and a slowdown in the economic
recovery.
Our crude oil production is sold at a premium or deduct differential to the
prevailing NYMEX West Texas Intermediate ("NYMEX WTI") price. The differential
reflects adjustments for location, quality and transportation and gathering
costs, as applicable. In 2021, we sell all of our crude oil volumes under
Magellan East Houston ("MEH") pricing, whereas historically our crude oil
volumes sold were largely priced using either Light Louisiana Sweet ("LLS"), or
MEH grade differentials. While both LLS and MEH have historically been at a
premium to NYMEX WTI, LLS has had a more favorable differential than MEH.
Natural gas prices vary by region and locality, depending upon the distance to
markets, availability of pipeline capacity, and supply and demand relationships
in that region or locality. Similar to crude oil, our natural gas production
price has a premium or deduct differential to the prevailing NYMEX Henry Hub
("NYMEX HH") price primarily due to differential adjustments for the location
and the energy content of the natural gas. Location differentials result from
variances in natural gas transportation costs based on the proximity of the
natural gas to its major consuming markets that correspond with the ultimate
delivery point as well as individual interaction of supply and demand.
A summary of these pricing differentials is provided in the discussion of
"Results of Operations - Realized Differentials" that follows.
In addition to the volatility of commodity prices, we are subject to
inflationary and other factors that could result in higher costs for products,
materials and services that we utilize in both our capital projects and with
respect to our operating expenses. Where possible, we have taken certain actions
with vendors and other service providers to secure products and services at
fixed prices and to pay for certain materials and services in advance in order
to lock in favorable costs.

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Capital Expenditures, Development Progress and Production
We currently operate two drilling rigs and during the three and nine months
ended September 30, 2021, incurred capital expenditures of approximately $60.0
million and $182.8 million, respectively, substantially all of which was
directed to drilling and completion projects. During the third quarter 2021, a
total of 10 gross (9.2 net) wells were drilled, completed and turned in line. As
of October 29, 2021, we turned an additional two gross (1.9 net) wells in line
and three gross (2.2 net) wells were completing and seven gross (6.2 net) wells
were in progress.
Following the Lonestar acquisition on October 5, 2021, we had approximately
174,600 gross (142,600 net) acres in the Eagle Ford, net of expirations, of
which approximately 93% is held by production.
Total sales volume for the third quarter 2021 was 2,344 thousand barrels of oil
equivalent ("Mboe"), or 25,483 barrels of oil equivalent ("boe") per day, with
approximately 80%, or 1,879 thousand barrels of oil ("Mbbls"), of sales volume
from crude oil, 11% from NGLs and 9% from natural gas.




                                       29

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Commodity Hedging Program
As of October 29, 2021, we have hedged a portion of our estimated future crude
oil and natural gas production from October 1, 2021 through the first quarter of
2024. The following table summarizes our net hedge positions for the periods
presented:
                                      4Q21             1Q22             2Q22              3Q22              4Q22              1Q23             2Q23              3Q23              4Q23              1Q24              2Q24
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)         6,215            3,250             3,000             3,000             3,000            2,500             2,400             2,807             2,657               462              308
Weighted Average Swap Price
($/bbl)                            $ 72.76$ 75.16$  74.12$  73.01$  69.20$ 54.40$  54.26$  54.92$  54.93$  58.75$ 58.75
NYMEX WTI Collars
Average Volume Per Day (bbl)        16,304           15,417            12,775             7,745             6,114            2,917             2,885
Weighted Average Purchased
Put Price ($/bbl)                  $ 51.40$ 55.14$  52.90$  47.37$  45.33$ 40.00$  40.00
Weighted Average Sold Call
Price ($/bbl)                      $ 62.23$ 68.26$  71.14$  64.60$  60.87$ 50.00$  50.00
NYMEX WTI Purchased Puts
Average Volume Per Day (bbl)         3,261
Weighted Average Purchased
Put Price ($/bbl)                  $ 55.00
NYMEX WTI Crude CMA Roll
Basis Swaps
Average Volume Per Day (bbl)        11,957           10,000             9,890             3,261             3,261
Weighted Average Swap Price
($/bbl)                            $  0.17$  0.79$   0.79$   1.12$   1.12
NYMEX HH Swaps
Average Volume Per Day
(MMBtu)                             20,700           17,500            12,500            12,500            12,500           10,000             7,500
Weighted Average Swap Price
($/MMBtu)                          $ 3.530$ 3.857$  3.342$  3.360$  3.408$ 3.346$  3.325
NYMEX HH Collars
Average Volume Per Day
(MMBtu)                              9,783            3,333            13,187            13,043            13,043                             11,538            11,413            11,413            11,538           11,538
Weighted Average Purchased
Put Price($/MMBtu)                 $ 2.607$ 4.150$  2.500$  2.500$  2.500$  2.500$  2.500$  2.500$  2.500$ 2.328
Weighted Average Sold Call
Price ($/MMBtu)                    $ 3.117$ 5.750$  3.220$  3.220$  3.220$  2.682$  2.682$  2.682$  3.650$ 3.000
NYMEX HH Sold Puts
Average Volume Per Day
(MMBtu)                              6,522
Weighted Average Sold Put
Price ($/MMBtu)                    $ 2.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)                                           28,022            27,717            27,717                             98,901            34,239            34,239            34,615
Weighted Average Fixed Price
($/gal)                                                              $ 0.2500$ 0.2500$ 0.2500$ 0.2288$ 0.2275$ 0.2275$ 0.2275




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Results of Operations The following table sets forth certain historical summary operating and financial statistics for the periods presented:

                                                                   Three Months Ended                                  Nine Months Ended
                                                September 30,           June 30,          September 30,                  September 30,
                                                     2021                 2021                 2020                 2021               2020
Total sales volume (Mboe) 1                            2,344              2,261                  2,235              6,453              6,909
Average daily sales volume (boe/d) 1                  25,483             24,844                 24,295             23,638             25,214
Crude oil sales volume (Mbbl) 1                        1,879              1,831                  1,691              5,179              5,291
Crude oil sold as a percent of total 1                    80  %              81  %                  76  %              80  %              77  %
Product revenues                               $     140,133          $ 

123,789 $ 68,614$ 352,230$ 204,300 Crude oil revenues

                             $     127,995          $ 

116,314 $ 63,227$ 326,222$ 190,732 Crude oil revenues as a percent of total

                  91  %              94  %                  92  %              93  %              93  %
Realized prices:
Crude oil ($/bbl)                              $       68.10$   63.54$       37.39$   62.99$   36.05
NGLs ($/bbl)                                   $       27.24$   18.31$        9.20$   21.21$    6.86
Natural gas ($/Mcf)                            $        4.11$    2.70$        1.80$    3.23$    1.73
Aggregate ($/boe)                              $       59.77$   54.75$       30.70$   54.58$   29.57
Realized prices, including effects of
derivatives, net 2
Crude oil ($/bbl)                              $       57.15$   52.70$       48.28$   52.08$   51.05
NGLs ($/bbl)                                   $       25.77$   17.87$        9.20$   20.52$    6.86
Natural gas ($/Mcf)                            $        3.44$    2.71$        1.88$    3.01$    1.86
Aggregate ($/boe)                              $       50.49$   45.93$       38.99$   45.63$   41.14
Production and lifting costs:
Lease operating ($/boe)                        $        4.54          $   

4.30 $ 3.70$ 4.52$ 4.04 Gathering, processing and transportation ($/boe)

                                        $        2.43          $    

2.29 $ 2.58$ 2.41$ 2.43 Production and ad valorem taxes ($/boe) $ 3.21$ 2.97$ 1.95$ 3.06$ 1.90 General and administrative ($/boe) 3

           $        4.66          $    

3.09 $ 3.84$ 4.82$ 3.45 Depreciation, depletion and amortization ($/boe)

                                        $       13.21          $   

12.74 $ 16.57$ 12.96$ 16.63

__________________________________________________________________________________

1  All volumetric statistics presented above represent volumes of commodity
production that were sold during the periods presented. Volumes of crude oil
physically produced in excess of volumes sold are placed in temporary storage to
be sold in subsequent periods.
2  Realized prices, including effects of derivatives, net is a non-GAAP measure
(see discussion and reconciliation to GAAP measure below in "Results of
Operations - Effects of Derivatives" that follows).
3  Includes combined amounts of $1.56, $0.43 and $1.20 per boe for the three
months ended September 30, 2021, June 30, 2021 and September 30, 2020 and $1.82
and $0.65 per boe for the nine months ended September 30, 2021 and 2020,
respectively, attributable to share-based compensation and significant special
charges related to organizational restructuring and acquisition, divestiture and
strategic transaction costs, as described in the discussion of "Results of
Operations - General and Administrative" that follows.
                                       31

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Sequential Quarterly Analysis
The following summarizes our key operating and financial highlights for the
three months ended September 30, 2021, with comparison to the three months ended
June 30, 2021. The year-over-year highlights for the quarterly periods ended
September 30, 2021 and 2020 are addressed in further detail in the discussions
that follow below in Year over Year Analysis of Operating and Financial Results.
•Daily sales volume increased marginally to 25,483 boe per day from 24,844 boe
per day with 9.2 net wells turned in line for both third quarter 2021 and second
quarter 2021. Total sales volume increased 4% to 2,344 Mboe from 2,261 Mboe.
•Product revenues increased 13% to $140.1 million from $123.8 million as a
result of 7% higher crude oil realized prices, or $8.6 million, coupled with
slightly higher crude oil sales volume, or $3.1 million. NGL revenues were
higher due to 49% higher realized prices, or $2.3 million, as well as 10% higher
sales volume, or $0.4 million. Natural gas revenues were 61% higher as a result
of 52% higher realized prices and 6% higher volume for an overall increase of
$1.9 million.
•Production and lifting costs, consisting of Lease operating expenses ("LOE")
and Gathering, processing and transportation expenses ("GPT"), increased on an
absolute basis to $16.3 million from $14.9 million and increased on a per unit
basis to $6.97 per boe from $6.59 per boe due primarily to the effects of
slightly higher sales volume of 4%.
•Production and ad valorem taxes increased on an absolute and per unit basis to
$7.5 million and $3.21 per boe from $6.7 million and $2.97 per boe,
respectively, due to the overall effects of 9% higher aggregate realized product
pricing, partially offset by lower estimated ad valorem tax assessments.
•General and administrative ("G&A") expenses increased on an absolute and per
unit basis to $10.9 million and $4.66 per boe from $7.0 million and $3.09 per
boe, respectively, primarily due to $2.7 million of acquisition and integration
costs associated with the Lonestar acquisition as well as higher employee
compensation costs.
•Depreciation, depletion and amortization ("DD&A") increased to $31.0 million
and increased on a per unit basis to $13.21 per boe during the third quarter
2021 as compared to $28.8 million and $12.74 per boe during the second quarter
2021 due primarily to lower total proved reserves, partially offset by lower
future development cost assumptions.


                                       32

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Year over Year Analysis of Operating and Financial Results
Sales Volume
The following tables set forth a summary of our total and average daily sales
volumes by product for the periods presented:
                                                      Total Sales Volume 1                                                             Average Daily Sales Volume 1
                                                                                      2021 vs. 2020                                                                          2021 vs. 2020
                                  Three Months Ended September 30,                      Favorable                      Three Months Ended September 30,                        Favorable
                                2021                            2020                  (Unfavorable)                 2021                              2020                   (Unfavorable)
Crude oil (Mbbl and
bbl/d)                          1,879                            1,691                       188                   20,429                              18,383                       2,046
NGLs (Mbbl and bbl/d)             263                              307                       (44)                   2,860                               3,338                        (478)
Natural gas (MMcf and
MMcf/d)                         1,211                            1,421                      (210)                      13                                  15                          (2)
Total (Mboe and boe/d)          2,344                            2,235                       109                   25,483                              24,295                       1,188

                                                                                      2021 vs. 2020                                                    
                     2021 vs. 2020
                                  Nine Months Ended September 30,                       Favorable                       Nine Months Ended September 30,                        Favorable
                                2021                            2020                  (Unfavorable)                 2021                              2020                   (Unfavorable)
Crude oil (Mbbl and
bbl/d)                          5,179                            5,291                      (112)                  18,972                              19,309                        (337)
NGLs (Mbbl and bbl/d)             713                              917                      (204)                   2,611                               3,347                        (736)
Natural gas (MMcf and
MMcf/d)                         3,367                            4,206                      (839)                      12                                  15                          (3)
Total (Mboe and boe/d)          6,453                            6,909                      (456)                  23,638                              25,214                      (1,576)

__________________________________________________________________________________

1  All volumetric statistics represent volumes of commodity production that were
actually sold during the periods presented. Volumes of crude oil physically
produced in excess of volumes sold are placed in temporary storage to be sold in
subsequent periods.
Total sales volume were relatively flat during the third quarter 2021 as
compared to the corresponding quarter in 2020 with 9.2 net wells turned in line
in the current quarter 2021 period as compared to 4.8 net wells in the
corresponding quarter in 2020. Total sales volume decreased 7% during the nine
months ended September 30, 2021 when compared to the corresponding period in
2020 as a result of the temporary suspension of the drilling program due to the
global economic downturn associated with COVID-19 in 2020 as our overall
production levels remained depressed in early 2021.
Approximately 80% of total sales volume during the three and nine month periods
in 2021 was attributable to crude oil when compared to approximately 76% during
the corresponding periods in 2020. The increase in the crude oil composition of
total sales volume is due primarily to drilling in the oilier northern and
eastern portions of our acreage holdings and focus on development plans with
emphasis in such portions.
Product Revenues and Prices
The following tables set forth a summary of our revenues and prices per unit of
volume by product for the periods presented:
                                               Total Product Revenues                                   Product Revenues per Unit of Volume
                                                                       2021 vs. 2020                                                   2021 vs. 2020
                              Three Months Ended September 30,           Favorable           Three Months Ended September 30,            Favorable
                                  2021                2020             (Unfavorable)              2021                2020             (Unfavorable)
                                                                                                  ($ per unit of volume)
Crude oil                     $  127,995$  63,227$       64,768$      68.10$  37.39          $         30.71
NGLs                               7,165              2,824                   4,341          $      27.24$   9.20          $         18.04
Natural gas                        4,973              2,563                   2,410          $       4.11$   1.80          $          2.31
Total                         $  140,133$  68,614$       71,519$      59.77$  30.70          $         29.07

                                                                       2021 vs. 2020                                                   2021 vs. 2020
                              Nine Months Ended September 30,            Favorable            Nine Months Ended September 30,            Favorable
                                  2021                2020             (Unfavorable)              2021                2020             (Unfavorable)
                                                                                                  ($ per unit of volume)
Crude oil                     $  326,222$ 190,732$      135,490$      62.99$  36.05          $         26.94
NGLs                              15,115              6,295                   8,820          $      21.21$   6.86          $         14.35
Natural gas                       10,893              7,273                   3,620          $       3.23$   1.73          $          1.50
Total                         $  352,230$ 204,300$      147,930$      54.58$  29.57          $         25.01




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The following table provides an analysis of the changes in our revenues for the periods presented:

                         Three Months Ended September 30, 2021 vs. 2020             Nine Months Ended September 30, 2021 vs. 2020
                                     Revenue Variance Due to                                   Revenue Variance Due to
                           Volume                Price             Total             Volume             Price              Total
Crude oil             $        7,038$ 57,730$ 64,768$  (4,014)$ 139,504$ 135,490
NGLs                            (405)            4,746             4,341             (1,403)            10,223              8,820
Natural gas                     (379)            2,789             2,410             (1,450)             5,070              3,620
                      $        6,254$ 65,265$ 71,519$  (6,867)$ 154,797$ 147,930


Our product revenues during the three and nine month periods in 2021 increased
compared to the corresponding periods in 2020 due primarily to significantly
higher prices and the continued economic recovery following the easing of
COVID-19 restrictions as compared to the prior year that resulted in increases
to the NYMEX WTI benchmark price of 70% for the three and nine month periods, as
well as an increase of 11% in crude oil volume in the three month period,
partially offset by lower NGL and natural gas volume. Total crude oil revenues
remain over 90% of our total product revenues during both the three and nine
month periods in 2021 and 2020.
Realized Differentials
The following table reconciles our realized price differentials from average
NYMEX-quoted prices for WTI crude oil and HH natural gas for the periods
presented:
                                                                   2021 vs. 2020                                                  2021 vs. 2020
                            Three Months Ended September
                                         30,                         Favorable            Nine Months Ended September 30,           Favorable
                               2021               2020             (Unfavorable)              2021               2020             (Unfavorable)
Realized crude oil prices
($/bbl)                    $    68.10$  37.39          $         30.71          $    62.99$  36.05          $         26.94
Average WTI prices              70.52             41.40                    29.12               65.04             38.37                    26.67
Realized differential to
WTI                        $    (2.42)$  (4.01)         $          1.59          $    (2.05)$  (2.32)         $          0.27

Realized natural gas
prices ($/Mcf)             $     4.11$   1.80          $          2.31          $     3.23$   1.73          $          1.50
Average HH prices
($/MMBtu)                        4.27              1.95                     2.32                3.52              1.82                     1.70
Realized differential to
HH                         $    (0.16)$  (0.15)         $         (0.01)         $    (0.29)$  (0.09)         $         (0.20)


Beginning in March 2020, the adverse impact of COVID-19 and instability in the
global energy markets effectively eliminated our premium margin to the NYMEX WTI
index price for crude oil. Average NYMEX WTI crude oil prices have rebounded as
stabilization continued, with crude oil averaging approximately $70 per bbl for
the third quarter 2021. Our differential to NYMEX WTI for the three month period
in 2021 compared to the corresponding period in 2020 is primarily due to the
change during 2020 from selling our production volumes based on LLS and MEH
pricing to selling fully based on MEH pricing. While both LLS and MEH have
historically been at a premium to NYMEX WTI, MEH is less of a premium than LLS.
Beginning in March 2020, average NYMEX HH prices were also impacted by COVID-19
and the overall industry instability noted above, as well as by the colder than
normal weather during first quarter 2021 that affected most of the Lower 48
states and caused significant natural gas supply and demand imbalances.
Recently, demand has rebounded while supply is constrained, causing a
significant increase in natural gas prices compared to the prior year as noted
in the table above. See also the discussion of Commodity Price and Other
Economic Conditions in the Overview above.
Effects of Derivatives
We present realized prices for crude oil, natural gas liquids and natural gas,
as adjusted for the effects of derivatives, net as we believe these measures are
useful to management and stakeholders in determining the effectiveness of our
price-risk management program that is designed to reduce the volatility
associated with our operations. Realized prices for crude oil, natural gas
liquids and natural gas, as adjusted for the effects of derivatives, net, are
supplemental financial measures that are not prepared in accordance with
generally accepted accounting principles ("GAAP").
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The following table presents the calculation of our non-GAAP realized prices for
crude oil, natural gas liquids and natural gas, as adjusted for the effects of
derivatives, net and reconciles to realized prices for crude oil, natural gas
liquids and natural gas determined in accordance with GAAP:
                                                                  2021 vs. 2020                                                  2021 vs. 2020
                           Three Months Ended September
                                        30,                         Favorable            Nine Months Ended September 30,           Favorable
                              2021               2020             (Unfavorable)              2021               2020             (Unfavorable)

Realized crude oil prices
($/bbl)                   $    68.10$  37.39          $         30.71          $    62.99$  36.05          $         26.94
Effects of derivatives,
net ($/bbl)                   (10.95)            10.89                   (21.84)             (10.91)            15.00                   (25.91)
Crude oil realized
prices, including effects
of derivatives, net
($/bbl)                   $    57.15$  48.28          $          8.87          $    52.08$  51.05          $          1.03

Realized natural gas
liquid prices ($/bbl)     $    27.24$   9.20          $         18.04          $    21.21$   6.86          $         14.35
Effects of derivatives,
net ($/bbl)                    (1.47)                -                    (1.47)              (0.69)                -                    (0.69)
Natural gas liquids
realized prices,
including effects of
derivatives, net ($/bbl)  $    25.77$   9.20          $         16.57          $    20.52$   6.86          $         13.66

Realized natural gas
prices ($/Mcf)            $     4.11$   1.80          $          2.31          $     3.23$   1.73          $          1.50
Effects of derivatives,
net ($/Mcf)                    (0.67)             0.08                    (0.75)              (0.22)             0.13                    (0.35)
Natural gas realized
prices, including effects
of derivatives, net
($/Mcf)                   $     3.44$   1.88          $          1.56          $     3.01$   1.86          $          1.15


Effects of derivatives, net include, as applicable to the period presented: (i)
current period commodity derivative settlements; (ii) the impact of option
premiums paid or received in prior periods related to current period production;
(iii) the impact of prior period cash settlements of early-terminated
derivatives originally designated to settle against current period production;
(iv) the exclusion of option premiums paid or received in current period related
to future period production; and (v) the exclusion of the impact of current
period cash settlements for early-terminated derivatives originally designated
to settle against future period production.
Other operating income, net
Other operating income, net includes fees for marketing and water disposal
services that we charge to third parties, net of related expenses, as well as
other miscellaneous revenues and credits attributable to our current operations
and gains and losses on the sale or disposition of assets other than our oil and
gas properties. In addition, charges attributable to credit losses associated
with our trade and joint venture partner receivables are included in this
caption as a contra-revenue item.
The following table sets forth the total Other revenues, net recognized for the
periods presented:
                                                                     2021 vs. 2020                                                 2021 vs. 2020
                            Three Months Ended September 30,           Favorable           Nine Months Ended September 30,           Favorable
                                 2021               2020             (Unfavorable)             2021               2020             (Unfavorable)

Other operating income, net $ 928$ 797 $

131 $ 2,085$ 1,972 $ 113



Our marketing fees slightly increased in the three and nine month periods in
2021 as compared to the corresponding periods in 2020 due primarily to higher
commodity-based pricing and we recovered certain suspended revenues attributable
to prior years during the 2021 periods. The increase was partially offset by
lower water disposal fees in the nine month period due to lower sales volumes.

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Lease Operating Expenses
LOE includes costs that we incur to operate our producing wells and field
operations. The most significant costs include compression and gas lift,
chemicals, water disposal, repairs and maintenance, including down-hole repairs,
field labor, pumping and well-tending, equipment rentals, utilities and
supplies, among others.
The following table sets forth our LOE for the periods presented:
                                                                   2021 vs. 2020                                               2021 vs. 2020
                             Three Months Ended September                                 Nine Months Ended September
                                          30,                        Favorable                        30,                        Favorable
                                2021               2020            (Unfavorable)             2021              2020            (Unfavorable)
Lease operating             $   10,647$  8,275$      (2,372)$  29,200$ 27,901$      (1,299)
Per unit ($/boe)            $     4.54$   3.70$       (0.84)$    4.52$   4.04$       (0.48)
% change per unit                                                         (22.7) %                                                    (11.9) %


LOE increased on an absolute basis and per unit basis during the three month
period in 2021 when compared to the corresponding period in 2020 due primarily
to higher variable costs and greater utilization of gas lift and lower
maintenance costs as substantial work was completed in the prior year during
shut-in periods partially offset by the effects of higher sales volumes in the
three month period in 2021 and higher water disposal costs in the three month
period in 2020 attributable to protective measures from offset stimulation
activities. LOE also increased on an absolute and per unit basis during the nine
month period in 2021 when compared to the corresponding period in 2020. The
increases were due primarily to a combination of higher variable costs, higher
gas lift costs, partially offset by continued cost-containment efforts and the
application of operational improvements throughout 2021.
Gathering, Processing and Transportation
GPT expense includes costs that we incur to gather and aggregate our crude oil
and natural gas production from our wells and deliver them via pipeline or truck
to a central delivery point, downstream pipelines or processing plants, and
blend or process, as necessary, depending upon the type of production and the
specific contractual arrangements that we have with the applicable midstream
operators. In addition, GPT expense includes short-term rental charges for crude
oil storage tanks.
The following table sets forth our GPT expense for the periods presented:
                                                                 2021 vs. 2020                                               2021 vs. 2020
                           Three Months Ended September                                 Nine Months Ended September
                                        30,                        Favorable                        30,                        Favorable
                              2021               2020            (Unfavorable)             2021              2020            (Unfavorable)
GPT                       $    5,688$  5,760          $          72          $  15,535$ 16,797$       1,262
Per unit ($/boe)          $     2.43$   2.58$        0.15$    2.41$   2.43$        0.02
% change per unit                                                         5.8  %                                                      0.8  %


GPT expense was relatively flat on an absolute basis during the three month
period in 2021 as compared to the corresponding period in 2020. GPT expense
decreased on an absolute basis during the nine month period in 2021 as compared
to the corresponding period in 2020 due primarily to lower gas gathering costs
attributable to 20% lower natural gas sales volumes, as well as the effects of
an increase in the mix of crude oil volume sold at the wellhead, resulting in
lower transportation costs. These favorable variances were partially offset by
higher costs associated with short-term rental charges with multiple vendors to
temporarily store a portion of our crude oil production.
Production and Ad Valorem Taxes
Production or severance taxes represent taxes imposed by the states in which we
operate for the removal of resources including crude oil, NGLs and natural gas.
Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily
counties, in which we operate, based on the assessed value of our operating
properties. The assessments for ad valorem taxes are generally based on a
published index prices.

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The following table sets forth our production and ad valorem taxes for the
periods presented:
                                                                                   2021 vs. 2020                                                  2021 vs. 2020
                                        Three Months Ended September 30,             Favorable            Nine Months Ended September 30,           Favorable
                                             2021                 2020             (Unfavorable)              2021               2020             (Unfavorable)

Production/severance taxes            $        6,589$  3,074$        (3,515)$  16,608$  8,692$        (7,916)
Ad valorem taxes                                 945              1,294                      349              3,160              4,460                    1,300
                                      $        7,534$  4,368$        (3,166)$  19,768$ 13,152$        (6,616)
Per unit ($/boe)                      $         3.21           $   1.95          $         (1.26)         $    3.06$   1.90          $         (1.16)
Production/severance tax rate as a
percent of product revenues                      4.7   %            4.5  %                                      4.7   %            4.3  %


Production taxes increased on an absolute basis and per unit basis during the
three and nine month periods in 2021 when compared to the corresponding periods
in 2020 due primarily to the increases in aggregate commodity sales prices in
the three and nine month periods in 2021. Our accruals for ad valorem taxes are
based on our most recent estimates for assessments which reflect lower property
values in 2021.
General and Administrative
Our G&A expenses include employee compensation, benefits and other related costs
for our corporate management and governance functions, rent and occupancy costs
for our corporate facilities, insurance, and professional fees and consulting
costs supporting various corporate-level functions, among others. In order to
facilitate a meaningful discussion and analysis of our results of operations
with respect to G&A expenses, we have disaggregated certain costs into three
components as presented in the table below. Primary G&A encompasses all G&A
costs except share-based compensation and certain significant special charges
that are generally attributable to material stand-alone transactions or
corporate actions that are not otherwise in the normal course.
The following table sets forth the components of our G&A for the periods
presented:
                                                                             2021 vs. 2020                                                   2021 vs. 2020
                                   Three Months Ended September 30,            Favorable            Nine Months Ended September 30,            Favorable
                                        2021                2020             (Unfavorable)              2021                2020             (Unfavorable)
Primary G&A                        $     7,281$   5,913$        (1,368)$   19,341$  19,322          $           (19)
Share-based compensation                   971                775                     (196)              4,179              2,582                   (1,597)
Significant special charges:
Organizational restructuring,
including severance                          -              1,372                    1,372                 239              1,372                    1,133
Acquisition/integration,
divestiture and strategic
transaction costs                        2,680                525                   (2,155)              7,335                525                   (6,810)

Total G&A                          $    10,932$   8,585$        (2,347)$   31,094$  23,801$        (7,293)
Per unit ($/boe)                   $      4.66$    3.84          $         (0.82)         $     4.82$    3.45          $         (1.37)
Per unit ($/boe) excluding
share-based compensation and other
significant special charges
identified above                   $      3.11$    2.65          $         (0.46)         $     3.00$    2.80          $         (0.20)


Our primary G&A expenses increased on an absolute and per unit basis during the
three and nine month periods in 2021 compared to the corresponding periods in
2020. The increase for the three month period in 2021 compared to 2020 is due
primarily to higher incentive compensation costs. Primary G&A was relatively
flat during the nine month period in 2021 compared to the corresponding period
in 2020.
Share-based compensation charges during the periods presented are attributable
to the amortization of compensation cost, net of forfeitures, associated with
the grants of time-vested restricted stock units ("RSUs"), and performance-based
restricted stock units ("PRSUs"). The grants of RSUs and PRSUs are described in
greater detail in Note 12 to the condensed consolidated financial statements
included in Part I, Item 1, "Financial Statements." As a result of the Juniper
Transactions which qualified as a change-in-control event, all of the RSUs
granted before 2019 vested as of the Juniper Closing Date in accordance with
their terms. This resulted in an incremental charge of approximately $1.9
million during the first quarter 2021. All of our share-based compensation
represents non-cash expenses.
Our total G&A expenses were higher on an absolute and per unit basis during the
three and nine month periods in 2021 as compared to the corresponding periods in
2020 due to higher overall incentive compensation and severance costs as well as
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acquisition and integration related costs associated with the Merger and Juniper
Transactions, partially offset by lower organizational restructuring.
Depreciation, Depletion and Amortization
DD&A expense includes charges for the allocation of property costs based on the
volume of production, depreciation of fixed assets other than oil and gas assets
as well as the accretion of our asset retirement obligations.
The following table sets forth total and per unit costs for DD&A for the periods
presented:
                                                                     2021 vs. 2020                                                  2021 vs. 2020
                               Three Months Ended September
                                           30,                         Favorable            Nine Months Ended September 30,           Favorable
                                  2021              2020             (Unfavorable)              2021               2020             (Unfavorable)
DD&A expense                  $  30,975$ 37,038          $         6,063          $  83,654$ 114,891$        31,237
DD&A rate ($/boe)             $   13.21$  16.57          $          3.36          $   12.96$   16.63          $          3.67


DD&A decreased on an absolute and a per unit basis during the three and nine
month periods in 2021 when compared to the corresponding periods in 2020. Lower
production volume provided for decreases of $7.6 million and lower DD&A rates
resulted in decreases of $23.7 million in the first nine months of 2021. The
lower DD&A rate in 2021 is primarily attributable to the effect of adding
additional reserves in 2021 as well as the effect of the impairments recorded in
the latter part of 2020 and in the first quarter 2021.
Impairment 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.
                                                                   2021 vs. 2020                                                      2021 vs. 2020
                          Three Months Ended September 30,           Favorable             Nine Months Ended September 30,              Favorable
                              2021                2020             (Unfavorable)               2021                  2020             (Unfavorable)
Impairment of oil and gas
properties                $        -          $ 235,989          $      

235,989 $ 1,811$ 271,498$ 269,687



We did not record an impairment of our oil and gas properties during the three
month period in 2021, compared to an impairment of $236.0 million recorded in
the corresponding period in 2020. During the nine month period in 2021, we
recorded an impairment of $1.8 million, compared to the $271.5 million recorded
in the nine month period in 2020. These impairments were the result of the
decline in the twelve-month average prices of crude oil, NGLs and natural gas as
indicated by the respective quarterly Ceiling Test under the full cost method of
accounting for oil and gas properties.
Interest Expense
Interest expense includes charges for outstanding borrowings under the Credit
Facility and Second Lien Facility derived from internationally-recognized
interest rates with a premium based on our credit profile and the level of
credit outstanding and the contractual rate associated with the 9.25% Senior
Notes due 2026. In addition, we are assessed certain fees for the overall credit
commitments provided to us as well as fees for credit utilization and letters of
credit. Also included is the accretion of original issue discount ("OID") on the
Second Lien Facility and the amortization of issuance costs capitalized
attributable to the Credit Facility and the Second Lien Facility. These costs
are partially offset by interest amounts that we capitalize on unproved property
costs while we are engaged in the evaluation of projects for the underlying
acreage. Amortization of issuance costs and OID on the 9.25% Senior Notes due
2026 are excluded as of September 30, 2021 as the proceeds and accrued interest
were held in escrow contingent upon the closing of the Lonestar acquisition
which occurred subsequent to the period end.

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The following table summarizes the components of our interest expense for the
periods presented:
                                                                    2021 vs. 2020                                                 2021 vs. 2020
                             Three Months Ended September                                   Nine Months Ended September
                                          30,                         Favorable                         30,                         Favorable
                                2021               2020             (Unfavorable)              2021              2020             (Unfavorable)
Interest on borrowings and
related fees                $   10,936$  7,375$        (3,561)$  22,101$ 22,944          $           843
Accretion of original issue
discount                            84               205                      121                274               602                      328
Amortization of debt
issuance costs                     479               594                      115              1,468             2,734                    1,266
Capitalized interest              (917)             (677)                     240             (2,561)           (2,067)                     494
Total interest expense, net
of capitalized interest     $   10,582$  7,497$        (3,085)$  21,282$ 24,213          $         2,931


The increase in interest expense during the three month period in 2021 is
substantially attributable to interest incurred in the amount of $5 million for
the 9.25% Senior Notes due 2026. This is offset by decreased interest expense
attributable to the Credit Facility and Second Lien Facility during the three
and nine month periods in 2021 as compared to the corresponding periods in 2020
due primarily to the effect of lower outstanding balances during the three and
nine month periods in 2021 and lower interest rates associated with the Credit
Facility, resulting from lower applicable margins based on lower utilization
levels. The weighted-average balances under the Credit Facility were lower in
the three and nine month periods in 2021 by approximately $109 million and $125
million, respectively. The weighted-average interest rates during the same
periods were lower by 47 basis points. The accretion of OID is entirely
attributable to the Second Lien Facility and the amortization of debt issuance
costs includes amounts attributable to both the Credit Facility and Second Lien
Facility. We capitalized a larger portion of interest during the three and nine
month periods in 2021 as we maintained a higher portion of unproved property as
compared to the corresponding period in 2020 due primarily to the property
contribution from the Juniper Transactions coupled with the impact of additional
interest related to the 9.25% Senior Notes due 2026.
Derivatives
The gains and losses for our derivatives portfolio reflect changes in the fair
value attributable to changes in market values relative to our hedged commodity
prices and interest rates.
The following table summarizes the gains and (losses) attributable to our
commodity derivatives portfolio and interest rate swaps for the periods
presented:
                                                                  2021 vs. 2020                                                   2021 vs. 2020
                           Three Months Ended September
                                        30,                         Favorable            Nine Months Ended September 30,            Favorable
                              2021               2020             (Unfavorable)              2021                2020             (Unfavorable)
Commodity derivative
gains (losses)            $  (21,000)$ (6,923)$      (14,077)$  (119,631)$ 117,406$     (237,037)
Interest rate swap gains
(losses)                         (84)               32                    (116)                 (48)            (7,527)                  7,479
  Total                   $  (21,084)$ (6,891)$      (14,193)$  (119,679)$ 109,879$     (229,558)


In the three and nine month periods in 2021, commodity prices recovered to
levels that were significantly higher on an average aggregate basis than those
during the corresponding periods in 2020. Accordingly, the derivative losses in
the three and nine month periods in 2021 reflect the decline in the
mark-to-market values consistent with the increase in prices attributable to
open positions. The effect in the three and nine month periods in 2020 was in
the opposite direction as the mark-to-market gains associated were attributable
to the substantial collapse in prices for the underlying commodities relative to
our hedged positions. In the second quarter 2021, we began hedging a portion of
our NGL production. Realized settlement payments, net for crude oil, NGL and
natural gas derivatives were $21.3 million and $43.2 million during the three
and nine month periods in 2021, respectively, as compared to realized settlement
receipts, net of $7.3 million and $66.6 million during the three and nine month
periods in 2020, respectively. In 2020, we began hedging a portion of our
exposure to variable interest rates associated with our Credit Facility and
Second Lien Facility. For the three and nine month periods in 2021, we paid $1.0
million and $2.9 million, respectively, of net settlements from our interest
rate swaps. For the three and nine month periods in 2020, we paid $0.9 and $1.3
million of net settlements from our interest rate swaps, respectively.
Income Taxes
Income taxes represent our income tax provision as determined in accordance with
generally accepted accounting principles. It considers taxes attributable to our
obligations for federal taxes under the Internal Revenue Code as well as to the
various states in which we operate, primarily Texas, or otherwise have
continuing involvement.

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The following table summarizes our income taxes for the periods presented:

                                                                          2021 vs. 2020                                                        2021 vs. 2020
                              Three Months Ended September 30,              Favorable               Nine Months Ended September 30,              Favorable
                                   2021                  2020             (Unfavorable)                 2021                  2020             (Unfavorable)
Income tax (expense)
benefit                     $         (549)           $  1,558$        (2,107)         $         (410)           $  1,110$        (1,520)
Effective tax rate                     1.3    %            0.6  %                                           1.3    %            0.6  %


The income tax provision resulted in an expense of $0.5 million and $0.4 million
for the three and nine months ended September 30, 2021, respectively. The
federal portion was fully offset by an adjustment to the valuation allowance
against our net deferred tax assets resulting in an effective tax rate of 1.3%,
which is fully attributable to the State of Texas. In connection with the
Juniper Transactions, we recorded an adjustment of $0.7 million to Paid-in
capital (see Note 3 to the condensed consolidated financial statements included
in Part I, Item 1, "Financial Statements" for additional information)
attributable to certain state deferred income tax effects associated with the
change in legal entity structure. Our net deferred income tax liability balance
of $0.8 million as of September 30, 2021 is also fully attributable to the State
of Texas and primarily related to property.
We recognized a federal and state income tax benefit of $1.6 million and $1.1
million the three and nine months ended September 30, 2020, respectively. The
federal and state tax expense was offset by an adjustment to the valuation
allowance against our net deferred tax assets resulting in an effective tax rate
of 0.6% which was fully attributable to the State of Texas. The provision also
reflected a reclassification of $1.2 million from deferred tax assets to current
income taxes receivable for certain refundable alternative minimum tax credit
carryforwards that were later received in June 2020.

Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity include our cash on hand, cash provided by
operating activities and borrowings under the Credit Facility. As of September
30, 2021, we had liquidity of $172.0 million, comprised of cash and cash
equivalents of $35.3 million and availability under our Credit Facility of
$136.7 million (factoring in letters of credit), and excludes $15.4 million
restricted cash - current representing escrowed accrued interest and an amount
equivalent to the original issue discount for the 9.25% Senior Notes due 2026
which funds were subsequently released upon closing of the Merger. Additionally,
following the closing of the Merger in connection with the Eleventh Amendment
(as defined below), the borrowing base under the Credit Facility was increased
to $600 million, with aggregate elected commitments of $400 million.
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 the 9.25% Senior Notes due 2026 which bear interest at 9.25%
and were sold at 99.018% of par. The gross proceeds of the offering and other
funds had initially been deposited in an escrow account pending satisfaction of
certain conditions, including the consummation of the Merger. At September 30,
2021, the gross proceeds plus accrued interest and original issue discount were
held in escrow. Upon the closing of the Merger, Holdings assumed all obligations
under the 9.25% Senior Notes due 2026 and the net proceeds and certain other
funds were released from escrow and used to repay and discharge certain
long-debt of Lonestar including accrued interest and related expenses, and the
remainder, along with cash on hand, was used to repay the Second Lien Facility
including a prepayment premium, accrued interest and related expenses. See Note
14 to the condensed consolidated financial statements included in Part I, Item
1, "Financial Statements" for additional information.
Our cash flows from operating activities are subject to significant volatility
due to changes in commodity prices for crude oil, NGL and natural gas products,
as well as variations in our production. The prices for these commodities are
driven by a number of factors beyond our control, including global and regional
product supply and demand, weather, product distribution, refining and
processing capacity and other supply chain dynamics, among other factors. All of
these factors have been negatively impacted by the continuing COVID-19 pandemic
and the related instability in the global energy markets. In order to mitigate
this volatility, we are extensively utilizing derivative contracts with a number
of financial institutions, all of which are participants in our Credit Facility,
hedging a portion of our estimated future crude oil, NGLs and natural gas
production through the first half of 2023. The level of our hedging activity and
duration of the financial instruments employed depends on our desired cash flow
protection, available hedge prices, the magnitude of our capital program and our
operating strategy.
We continually evaluate potential sales of assets, including certain
non-strategic oil and gas properties and undeveloped acreage, among others.
Additionally, from time-to-time and under market conditions that we believe are
favorable to us, we may consider capital market transactions, including the
offering of debt and equity securities. We maintain an effective shelf
registration statement to allow for optionality.

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Capital Resources
Our 2021 capital budget contemplates capital expenditures from $240 to $270
million, of which $235 to $265 million has been allocated to drilling and
completion activities. We plan to fund our 2021 capital program and our
operations for the next twelve months primarily with cash on hand, cash from
operating activities and, to the extent necessary, supplemental borrowings under
the Credit Facility. Based upon current price and production expectations, we
believe that our cash on hand, cash from operating activities and borrowings
under our Credit Facility, as necessary, will be sufficient to fund our capital
spending and operations for at least the next twelve months; however, future
cash flows are subject to a number of variables including the length and
magnitude of the current global economic uncertainties associated with the
COVID-19 pandemic and related instability in the global energy markets.
Cash Flows
The following table summarizes our cash flows for the periods presented:
                                                                                Nine Months Ended
                                                                      September 30,           September 30,
                                                                          2021                    2020
Net cash provided by operating activities                                  204,084                 189,723
Net cash used in investing activities                                     (146,481)               (138,927)
Net cash provided by (used in) financing activities                        376,146                 (38,078)

Net increase in cash, cash equivalents and restricted cash $ 433,749$ 12,718



Cash Flows from Operating Activities. The increase of $14.4 million in net cash
provided by operating activities for the nine months ended September 30, 2021
compared to the corresponding period in 2020 was primarily attributable to the
effect of cash receipts that were derived from higher average prices in 2021, as
well as lower interest payments, net of interest rate swap settlements in the
2021 period as compared to 2020, partially offset by (i) the effects of lower
total sales volume (ii) higher net payments for commodity derivatives
settlements and premiums, (iii) transaction costs paid in connection with the
Juniper Transactions and Lonestar acquisition and integration costs and (iv)
executive restructuring costs including severance payments.
Cash Flows from Investing Activities. Our cash payments for capital expenditures
were higher during the nine months ended September 30, 2021 as compared to the
corresponding period in 2020, due primarily to the suspension of the drilling
and completion program during a portion of 2020 as a result of the COVID-19
pandemic and related market instability.
The following table sets forth costs related to our capital expenditures program
for the periods presented:
                                                                                  Nine Months Ended
                                                                        September 30,           September 30,
                                                                            2021                    2020
Drilling and completion                                               $     

181,144 $ 93,443 Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs

                                                    2,315                   3,317
Pipeline, gathering facilities and other equipment, net 1                       (632)                  1,221
  Total capital expenditures incurred                                 $     

182,827 $ 97,981

__________________________________________________________________________________

1 Includes certain capital charges to our working interest partners for completion services. The following table reconciles the total costs of our capital expenditures program with the net cash paid for capital expenditures as reported in our condensed consolidated statements of cash flows for the periods presented:

Nine Months Ended

                                                                       September 30,           September 30,
                                                                           2021                    2020
Total capital expenditures program costs (from above)                $      

182,827 $ 97,981 Decrease (increase) in accounts payable for capital items and accrued capitalized costs

                                                   (30,303)                 30,579
Net purchases of tubular inventory and well materials 1                       1,858                   3,441

Prepayments for drilling and completion services, net of (transfers) (12,653)

                  3,613
Capitalized internal labor, capitalized interest and other                    4,909                   3,396
Total cash paid for capital expenditures                             $      

146,638 $ 139,010

__________________________________________________________________________________

1 Includes purchases made in advance of drilling.

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Cash Flows from Financing Activities. In January 2021, we received over $150
million of proceeds from the issuance of Common Units and Series A Preferred
Stock in connection with the Juniper Transactions. These proceeds were used to
fund the repayments of $80.5 million and $50.0 million under the Credit Facility
and Second Lien Facility, respectively. The remainder of the proceeds were used
to pay: (i) $3.8 million of issue costs associated with the redeemable
securities (Common Units and Series A Preferred Stock), (ii) $5.5 million of
transaction costs attributable to Juniper's Noncontrolling interest, (iii) $1.8
million of issue costs associated with the amendments to the Credit Facility and
Second Lien Facility in connection with the Juniper Transactions, (iv) $1.3
million to liquidate outstanding Second Lien Facility advances attributable to a
single participant lender and (v) a portion of interest payments and other
Juniper Transactions costs, both of which are presented as cash disbursements
included in net cash provided by operating activities above. The nine months
ended September 30, 2021 also includes additional net repayments of $21.0
million under the Credit Facility and $5.6 million quarterly amortization
payments under the Second Lien Facility as well as $396.1 million net proceeds
received from the 9.25% Senior Notes due 2026. The nine months ended September
30, 2020 includes borrowings of $51.0 million and repayments of $89.0 million
under the Credit Facility which were used to fund a portion of the capital
program at the beginning of 2020.
Capitalization
The following table summarizes our total capitalization as of the dates
presented:
                                       September 30,      December 31,
                                           2021               2020
Credit facility                       $    212,900$    314,400
Second lien facility, net                  139,133            195,097
9.25 Senior Notes due 2026, net            394,795                  -
Total debt, net                            746,828            509,497
Total equity                               426,590            212,838
                                      $  1,173,418$    722,335
Debt as a % of total capitalization             64  %              71  %


Credit Facility. As of September 30, 2021, the Credit Facility had a $1.0
billion revolving commitment and a $375 million borrowing base, including a $25
million sublimit for the issuance of letters of credit. The borrowing base under
the Credit Facility is redetermined semi-annually, generally in the Spring and
Fall of each year. Additionally, we and the Credit Facility lenders generally
may, upon request, initiate a redetermination at any time during the six-month
period between scheduled redeterminations. The Credit Facility is available to
us for general corporate purposes including working capital. Prior to the
Eleventh Amendment (as defined below), the Credit Facility was scheduled to
mature in May 2024. We had $0.4 million in letters of credit outstanding as of
September 30, 2021 and December 31, 2020.
The outstanding borrowings under the Credit Facility bear interest at a rate
equal to, at our option, either (a) a customary reference rate plus an
applicable margin ranging from 1.50% to 2.50%, determined based on the
utilization level under the Credit Facility or (b) a Eurodollar rate, including
the London interbank offered rate ("LIBOR") through 2021, plus an applicable
margin ranging from 2.50% to 3.50%, determined based on the utilization level
under the Credit Facility. Interest on reference rate borrowings is payable
quarterly in arrears and is computed on the basis of a year of 365/366 days, and
interest on Eurodollar, including LIBOR, borrowings is payable every one, three
or six months, at our election, and is computed on the basis of a year of 360
days. As of September 30, 2021, the actual weighted-average interest rate on the
outstanding borrowings under the Credit Facility was 3.09%. Unused commitment
fees are charged at a rate of 0.50%.
The following table summarizes our borrowing activity under the Credit Facility
for the periods presented:
                                                                            Borrowings Outstanding
                                                                         Weighted-                                     Weighted-
                                                     End of Period        Average               Maximum              Average Rate
Three months ended September 30, 2021              $      212,900$    233,818$ 238,900                        3.10  %
Nine months ended September 30, 2021               $      212,900$    241,206$ 314,400                        3.13  %


The Credit Facility is guaranteed by all of the subsidiaries of the borrower
(the "Guarantor Subsidiaries"), except for Boland Building, LLC, effective upon
the Eleventh Amendment, which holds real estate assets that are associated with
Lonestar's legacy mortgage obligations. The guarantees under the Credit Facility
are full and unconditional and joint and several. Substantially all of our
consolidated assets are held by the Guarantor Subsidiaries. There are no
significant restrictions on the ability of the borrower or any of the Guarantor
Subsidiaries to obtain funds through dividends, advances or loans. The
obligations under the Credit Facility are secured by a first priority lien on
substantially all of our subsidiaries' assets.
In August 2021, we entered into the Master Assignment, Agreement and Amendment
No. 11 to Credit Agreement (the "Eleventh Amendment"). The Eleventh Amendment,
in addition to other changes described therein, amended the Credit
                                       42

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Facility to, effective on the closing of the Merger, (1) increase the borrowing
base under to $600 million, with aggregate elected commitments of $400 million,
(2) remove certain availability restrictions, (3) remove minimum hedging
requirements, (4) remove the first lien leverage ratio covenant, (5) remove the
Partnership and PV Energy Holdings GP, LLC as guarantors, and (6) extend the
maturity date to the date that is the four year anniversary of the date such
amendment became effective, or October 6, 2025.
Second Lien Facility. On October 5, 2021, Holdings repaid all of its outstanding
obligations under the Second Lien Facility, and terminated the Second Lien
Facility. In accordance with the Second Lien Facility, we incurred a prepayment
premium of 102% as a result of repayment.
Covenant Compliance. As of September 30, 2021, the Credit Facility required us
to maintain (1) a minimum current ratio (as defined in the Credit Facility,
which considers the unused portion of the total commitment as a current asset)
of 1.00 to 1.00, (2) a maximum leverage ratio (consolidated indebtedness to
EBITDAX, each as defined in the Credit Facility), in each case measured as of
the last day of each fiscal quarter of 3.50 to 1.00. and (3) a maximum first
lien leverage ratio (consolidated secured indebtedness to adjusted earnings
before interest, taxes, depreciation, depletion, amortization and exploration
expenses, both as defined in the Credit Facility), measured as of the last day
of each fiscal quarter, of 2.50 to 1.00.
The Credit Facility also contains customary affirmative and negative covenants,
including as to compliance with laws (including environmental laws, ERISA and
anti-corruption laws), maintenance of required insurance, delivery of quarterly
and annual financial statements, oil and gas engineering reports and budgets,
maintenance and operation of property (including oil and gas properties),
restrictions on the incurrence of liens and indebtedness, merger, consolidation
or sale of assets, payment of dividends, and transactions with affiliates and
other customary covenants. In addition, as of September 30, 2021, the Credit
Facility contained certain anti-cash hoarding provisions. See Note 14 to the
condensed consolidated financial statements included in Part I, Item 1,
"Financial Statements" for additional information.
The Credit Facility contains events of default and remedies. If we do not comply
with the financial and other covenants in the Credit Facility, the lenders may,
subject to customary cure rights, require immediate payment of all amounts
outstanding under the Credit Facility.
As of September 30, 2021, we were in compliance with all of the covenants under
the Credit Facility and the Second Lien Facility.
See Note 14 to the condensed consolidated financial statements included in Part
I, Item 1, "Financial Statements" for additional information on our debt,
including the 9.25% Senior Notes due 2026.

Off Balance Sheet Arrangements
As of September 30, 2021, we had no off-balance sheet arrangements other than
information technology licensing, service agreements, in-kind commodity recovery
arrangements for imbalances and letters of credit, all of which are customary in
our business.
Critical Accounting Estimates
The process of preparing financial statements in accordance with accounting
principles generally accepted in the United States of America ("GAAP") requires
our management to make estimates and judgments regarding certain items and
transactions. It is possible that materially different amounts could be recorded
if these estimates and judgments change or if the actual results differ from
these estimates and judgments. Disclosure of our most critical accounting
estimates that involve the judgment of our management can be found in our Annual
Report on Form 10-K for the year ended December 31, 2020.
As described in this Quarterly Report on Form 10-Q as well as the Critical
Accounting Estimates disclosures in the Annual Report on Form 10-K, we apply the
full cost method to account for our oil and gas properties. At the end of each
quarterly reporting period, we perform a Ceiling Test in order to determine if
our oil and gas properties have been impaired. For purposes of the Ceiling Test,
estimated discounted future net revenues are determined using the prior
12-month's average price based on closing prices on the first day of each month,
adjusted for differentials, discounted at 10%. The calculation of the Ceiling
Test and provision for DD&A are based on estimates of proved reserves. There are
significant uncertainties inherent in estimating quantities of proved reserves
and projecting future rates of production, timing and plan of development. The
carrying value of our proved oil and gas properties exceeded the limit
determined by the Ceiling Test as of March 31, 2021, resulting in a $1.8 million
impairment. There was no such impairment of our proved oil and gas properties
during the second or third quarters of 2021.
                                       43

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