RANGER OIL CORPORATION The following discussion and analysis of the financial condition and results of operations ofPenn Virginia Corporation and its consolidated subsidiaries ("Penn Virginia," 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 period endedMarch 31, 2020 have been reclassified to conform to the 2021 presentation. References to "quarters" represent the three months endedMarch 31, 2021 or 2020, as applicable.
Overview
We are an independent oil and gas company focused on the onshore exploration,
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 Gonzales , Lavaca , Fayette and DeWitt Counties in South Texas .
Industry Environment and Recent Operating and Financial Highlights
Commodity Price and Other Economic Conditions
As an oil and gas exploration and development 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") has had an adverse effect on global economic
activity with the impact of travel restrictions, business closures, limitations
to person-to-person contact and the institution of quarantining and other
restrictions on movement in many communities. 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. While we have seen a relative improvement in global market stability, a
return to pre-COVID 19 levels of economic activity remains uncertain in its
magnitude and eventual timing.
In addition, global crude oil prices experienced a collapse starting in early
March 2020 as a result of the dual impact of demand deterioration and market
oversupply caused by disagreements between the Organization of the Petroleum
Exporting Countries ("OPEC") and Russia (together with OPEC , collectively
"OPEC+") with respect to production curtailments. OPEC+ ultimately agreed to
specific adjustments to production in the Spring of 2020 which, for the most
part, held for the remainder of the year and were supplemented by additional
voluntary downward adjustments, led primarily by Saudi Arabia . Collectively
these curtailments contributed to a relative stabilization of commodity prices
and rebalancing of the global crude oil markets by the end of 2020. However,
there remains a high level of uncertainty regarding the volatility of energy
supply and demand as OPEC+ announced on April 1, 2021 that it would be easing
existing limits on production beginning in May.
The combined effect of COVID-19 and the continuing energy industry instability
led to significant volatility in NYMEX West Texas Intermediate ("NYMEX WTI")
crude oil prices throughout 2020 and first quarter 2021. In the beginning of
January 2020 , crude oil prices were approximately $62 per barrel ("bbl") but
declined rapidly to end first quarter 2020 at approximately $20 per bbl, a
decrease of approximately 68 percent during the quarter. Prices began to
increase and modestly stabilized following the implementation of the
aforementioned OPEC+ production curtailments, as well as proactive economic
relief efforts in many countries, including the United States and crude oil
ended 2020 at approximately $48 per bbl. In first quarter 2021 the rebound and
stabilization continued, with crude oil averaging approximately $58 per bbl for
the quarter.
NYMEX Henry Hub ("NYMEX HH") pricing was 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, particular in
February 2021 . During the three months ended March 31, 2021 , NYMEX HH reached a
high of $23.61 per MMBtu and a low of $2.38 per MMBtu compared to a high of
$2.12 per MMBtu and a low of $1.63 per MMBtu during the three months ended March
31, 2020 .
Our crude oil production is sold at a premium or deduct differential to the
prevailing NYMEX WTI Price. The differential reflects adjustments for location,
quality and transportation and gathering costs, as applicable. Historically, our
crude oil volume sold was largely priced using either Light Louisiana Sweet
("LLS"), or Magellan East Houston ("MEH") grade differentials; however, in 2020
our contracts continued to shift more heavily to MEH pricing and by year-end
2020 we were selling all of our crude oil volumes under MEH pricing contracts.
While both LLS and MEH have historically been at a premium to NYMEX WTI, LLS has
had a more favorable differential than MEH. During the three months ended March
31, 2021 , the average differential for NYMEX WTI versus MEH was a premium of
approximately $1.37 per bbl, compared to a premium of approximately $2.04 per
bbl and $1.85 per bbl for NYMEX WTI versus MEH and LLS, respectively, for the
same period in 2020. During the first quarter 2020 our realized crude oil price
was a slight premium to NYMEX WTI of $0.12 but
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sold at a discount of$2.38 for the three months endedMarch 31, 2021 primarily as a result of shifting fully to MEH pricing, as well as the narrowing of the MEH differential to NYMEX WTI. 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. Our realized natural gas prices of$2.80 and$1.83 per Mcf sold at discounts to NYMEX HH of$0.58 and$0.05 per MMBtu for the three months endedMarch 31, 2021 and 2020, respectively. A summary of these pricing differentials in tabular form is provided in the discussion of "Results of Operations - General and Administrative" that follows. Capital Expenditures and Development Progress We are operating two drilling rigs and during the three months endedMarch 31, 2021 , incurred capital expenditures of approximately$54.1 million with 99 percent directed to drilling and completion projects through which a total of 13 gross (11.5 net) wells were drilled, completed and turned to sales. Sequential Quarterly Analysis The following summarizes our key operating and financial highlights for the three months endedMarch 31, 2021 , with comparison to the three months endedDecember 31, 2020 as presented in the table that follows. The year-over-year highlights for the quarterly periods endedMarch 31, 2021 and 2020 are addressed in further detail in the discussions for Financial Condition and Results of Operations that follow. •Daily sales volume declined marginally to 20,534 barrels of oil equivalent ("boe") per day from 21,502 boe per day due primarily to the effect of natural well declines, as well as the impacts of Winter Storm Uri that occurred inFebruary 2021 that resulted in shut-ins of our wells for a portion of several days during the month. The declines were partially offset by new wells turned to sales during the three months endedMarch 31, 2021 . Total sales volume decreased seven percent to 1,848 thousand barrels of oil equivalent ("Mboe") from 1,978 Mboe due primarily to the impact of the aforementioned natural well declines. •Product revenues increased 33 percent to$88.3 million from$66.5 million due primarily to 41 percent higher crude oil prices, or$23.7 million , partially offset by five percent lower crude oil sales volume, or$2.7 million . NGL revenues were 34 percent higher due to 58 percent higher prices, or$1.3 million partially offset by 15 percent lower sales volume, or$0.4 million . Natural gas revenues were essentially unchanged with offsetting amounts from higher pricing and lower sales volume. •Production and lifting costs (consisting of Lease operating expenses ("LOE") and Gathering, processing and transportation expenses ("GPT")) decreased on an absolute basis to$13.5 million from$14.8 million and declined on a per unit basis to$7.31 per boe from$7.49 per boe. Contributing to this decline were lower chemicals, water disposal, repairs and maintenance and contract labor costs primarily associated with the lower crude oil sales volume, partially offset by higher gas lift and natural gas gathering costs. •Production and ad valorem taxes increased on an absolute and per unit basis to$5.5 million and$2.98 per boe from$3.5 million and$1.75 per boe, respectively, due to the overall effects of 42 percent higher aggregate realized product pricing partially offset by lower than anticipated ad valorem tax assessments. •General and administrative ("G&A") expenses increased on an absolute and per unit basis to$13.2 million and$7.13 per boe from$10.0 million and$5.05 per boe, respectively, due primarily to: (i)$1.9 million of costs associated with share-based compensation awards whose vesting was accelerated by the Juniper Transactions, (ii)$0.2 million of higher transaction costs associated with the Juniper Transactions in the three month period in 2021, (iii)$0.2 million of executive restructuring charges including severance costs and termination benefits and (iv)$0.4 million of higher employee benefits costs in the three month period in 2021. •Depreciation, depletion and amortization ("DD&A") decreased to$23.9 million and$12.92 per boe during the first quarter of 2021 as compared to$25.8 million and$13.03 per boe during the fourth quarter of 2020 due primarily to the lower depletion rate attributable to the impairment recorded in the fourth quarter of 2020. •We recorded an impairment of our oil and gas properties of$1.8 million during the first quarter of 2021 and$120.3 million in the fourth quarter of 2020 as the unamortized cost of our oil and gas properties, net of deferred income taxes, exceeded the sum of our estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the "Ceiling Test"). •Due to the combined impact of the matters noted in the bullets above, we recorded operating income of$30.7 million in the first quarter of 2021 compared to an operating loss of$107.4 million in fourth quarter of 2020. 25
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The following table sets forth certain historical summary operating and financial statistics for the periods presented:
Three Months Ended
March 31, December 31, March 31,
2021 2020 2020
Total sales volume (Mboe) 1 1,848 1,978 2,433
Average daily sales volume (boe/d) 1 20,534 21,502 26,740
Crude oil sales volume (Mbbl) 1 1,469 1,538 1,881
Crude oil sold as a percent of total 1 80 % 78 % 77 %
Product revenues $ 88,308 $ 66,492 $ 90,891
Crude oil revenues $ 81,913 $ 61,009 $ 86,308
Crude oil revenues as a percent of total 93 % 92 % 95 %
Realized prices:
Crude oil ($/bbl) $ 55.76 $ 39.66 $ 45.90
NGLs ($/bbl) $ 16.95 $ 10.71 $ 6.16
Natural gas ($/Mcf) $ 2.80 $ 2.45 $ 1.83
Aggregate ($/boe) $ 47.79 $ 33.61 $ 37.35
Realized prices, including effects of derivatives, net 2
Crude oil ($/bbl) $ 44.80 $ 48.84 $ 54.15
Natural gas ($/Mcf) $ 2.84 $ 1.95 $ 1.90
Aggregate ($/boe) $ 39.10 $ 40.46 $ 43.78
Production and lifting costs:
Lease operating ($/boe) $ 4.78 $ 4.83 $ 4.33
Gathering, processing and transportation ($/boe) $ 2.53 $ 2.66 $ 2.24
Production and ad valorem taxes ($/boe) $ 2.98 $ 1.75 $ 2.53
General and administrative ($/boe) 3 $ 7.13 $ 5.05 $ 2.97
Depreciation, depletion and amortization ($/boe) $ 12.92 $ 13.03 $ 16.73
Capital expenditure program costs 4 $ 54,122 $ 32,627 $ 79,220
Cash provided by operating activities 5 $ 32,211 $ 32,055 $ 72,473
Cash paid for capital expenditures 6 $ 34,758 $ 29,555 $ 62,015
Cash and cash equivalents at end of period $ 11,868 $ 13,020 $ 55,331
Debt outstanding at end of period, net 7 $ 371,062 $ 509,497 $ 592,624
Credit available under credit facility at end of period 8 $ 145,700 $ 35,200 $ 100,200
Net development wells drilled and completed 11.5 2.0 11.0
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1 All volumetric statistics presented above represent volumes of commodity production that were sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods. 2 Realized prices, including effects of derivatives, net is a non-GAAP measure (see discussion and reconciliation to GAAP measure below in "Results of Operations - Effects of Derivatives" that follows). 3 Includes combined amounts of$3.86 ,$1.93 and$0.35 per boe for the three months endedMarch 31, 2021 ,December 31, 2020 andMarch 31, 2020 , respectively, attributable to share-based compensation and significant special charges, including organizational restructuring and acquisition, divestiture and strategic transaction costs, as described in the discussion of "Results of Operations - General and Administrative" that follows. 4 Includes amounts accrued and excludes capitalized interest and capitalized labor. 5 Includes net cash received (paid) for derivative settlements and premiums received (paid) of$(7.2) million ,$12.8 million and$(0.3) million for the three months endedMarch 31, 2021 ,December 31, 2020 andMarch 31, 2020 , respectively. Reflects changes in operating assets and liabilities of$(14.4) million ,$(12.9) million and$16.0 million for the three months endedMarch 31, 2021 ,December 31, 2020 andMarch 31, 2020 , respectively. 6 Represents actual cash paid for capital expenditures including capitalized interest and capitalized labor. 7 Represents amounts net of unamortized discount and deferred issue costs of$4.7 million ,$4.9 million and$6.8 million as ofMarch 31, 2021 ,December 31, 2020 andMarch 31, 2020 , respectively. 8 The borrowing base under the credit agreement ("Credit Facility") was$375 million with availability further limited to a maximum of$350 million . 26
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Key Developments The following general business developments had or may have a significant impact on our results of operations, financial position and cash flows:Strategic Investment by Juniper InJanuary 2021 , we consummated the previously announced Juniper Transactions whereby affiliates of Juniper contributed$150 million in cash and certain oil and gas assets inLavaca andFayette Counties inTexas to us in exchange for equity that entitles Juniper to both vote and share in any dividend on the same basis as 22,548,109 shares of common stock. Each holder of Common Units has the right to cause the Company to redeem on or afterJuly 14, 2021 , all or a portion of its Common Units (together with one one-hundredth (1/100th) of a share of Preferred Stock for each Common Unit to be redeemed), in exchange for, at the Partnership's option, shares of Common Stock, on a one-for-one basis, or cash. Each 1/100th of a share of preferred Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Further, because Penn Virginia is a holding company with no independent means of generating revenues and the assets of the consolidated Company all reside in operating subsidiaries, the holders of Common Units would be entitled to participate in any cash distribution or dividend on the same basis as the Common Stock whether or not the Common Units and Preferred Stock are redeemed or exchanged. Because the Common Units and Preferred Stock entitle Juniper to both vote and share in any distribution or dividend on the same basis as 22,548,109 shares of common stock, we view them as common stock equivalents. For additional information regarding the Juniper Transactions, see Note 3 to the Condensed Consolidated Financial Statements included in Part I, Item 1, "Financial Statements ." Amendments to Credit Facility and Affirmation of Borrowing Base InJanuary 2021 , we entered into Amendment No. 9 to the Credit Agreement (the "Ninth Amendment") permitting the Juniper Transactions and affirming our borrowing base at$375 million with borrowings limited to a maximum of$350 million . In addition, the Ninth Amendment: (i) provides for certain minimum hedging conditions, (ii) a first lien leverage ratio covenant of 2.50 times, tested quarterly and (iii) permits amortization payments of up to$1.875 million per quarter to be made under the Second Lien Credit Agreement, dated as ofSeptember 29, 2017 (the "Second Lien Facility") untilJanuary 2022 if no default exists both before and after giving effect to the payments and thereafter using available free cash flow upon the satisfaction of certain conditions (including maintaining a leverage ratio of 2.00 to 1.00 and availability of at least 25% under the Credit Facility after giving pro forma effect to the payment). Concurrent with the Ninth Amendment, we paid down$80.5 million of outstanding borrowings under the Credit Facility plus accrued interest of$0.1 million which was funded with the proceeds from the Juniper Transactions. We incurred and capitalized$0.4 million of issue and other costs associated with the Ninth Amendment inJanuary 2021 . Amendment to the Second Lien Facility OnNovember 2, 2020 , we entered into the amendment datedNovember 2, 2020 (the "Second Lien Amendment") which became effective upon the Closing of the Juniper Transactions. The Second Lien Amendment (1) extends the maturity date of the Second Lien Facility toSeptember 29, 2024 , (2) increases the margin applicable to advances under the Second Lien Facility, (3) impose certain limitations on capital expenditures, acquisitions and investments if the Asset Coverage Ratio (as defined therein) at the end of any fiscal quarter is less than 1.25 to 1.00 and (4) requires maximum and, in certain circumstances as described therein, minimum hedging arrangements. Under the Second Lien Amendment, the Company is required to make quarterly amortization payments equal to$1,875,000 and outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 7.25% or (b) a Eurodollar rate, including LIBOR through 2021, with a floor of 1%, plus an applicable margin of 8.25%; provided that the applicable margin will increase to 8.25% and 9.25% respectively during any quarter in which the quarterly amortization payment is not made. We paid down$50.0 million of outstanding loans under the Second Lien Facility plus accrued interest of$0.2 million attributable to lenders and$1.3 million including accrued interest to a non-consenting lender inJanuary 2021 which was funded with the proceeds from the Juniper Transaction. We incurred and capitalized$1.4 million of issue and other costs and wrote-off$1.3 million of unamortized issuance costs in connection with the Second Lien Amendment inJanuary 2021 as a loss on the extinguishment of debt. Development Plans and Production We drilled, completed and turned 13 gross (11.5 net) wells to sales during the quarter endedMarch 31, 2021 . As ofApril 30, 2021 , we turned an additional two gross (1.6 net) wells to sales and four gross (2.9 net) wells were completing and seven gross (6.3 net) wells were in progress. Total sales volume for the first quarter of 2021 was 1,848 Mboe, or 20,534 boe/d, with approximately 80 percent, or 1,469 Mbbls, of sales volume from crude oil, 11 percent from NGLs and 9 percent from natural gas, respectively. As ofMarch 31, 2021 , we had approximately 102,400 gross (90,400 net) acres in the Eagle Ford, net of expirations. Approximately 91 percent of our acreage is held by production and substantially all is operated by us. 27
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Commodity Hedging Program As ofApril 30, 2021 , we have hedged a portion of our estimated future crude oil and natural gas production fromApril 1, 2021 through the first half of 2023. The following table summarizes our net hedge positions for the periods presented: 2Q2021 3Q2021 4Q2021 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 3,297 815 815 Weighted Average Swap Price ($/bbl)$ 55.89 $ 45.54 $ 45.54 NYMEX WTI Collars Average Volume Per Day (bbl) 12,637 12,500 9,783 5,417 4,533 4,484 4,484 2,917 2,855 Weighted Average Purchased Put Price ($/bbl)$ 44.65 $ 42.87 $
42.00
$ 40.00 $ 40.00 Weighted Average Sold Call Price ($/bbl)$ 55.10 $ 55.13 $
54.92
$ 50.00 $ 50.00 NYMEX WTI Sold Puts Average Volume Per Day (bbl) 4,945 5,707
5,707
Weighted Average Sold Put Price ($/bbl)$ 29.83 $ 35.14 $
35.14
NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 18,132 17,935 17,935 Weighted Average Swap Price ($/bbl)$ 0.17 $ 0.17 $ 0.17 NYMEX HH Collars Average Volume Per Day (MMBtu) 9,890 9,783
9,783
Weighted Average Purchased Put Price($/MMBtu)$ 2.607 $ 2.607 $ 2.607 Weighted Average Sold Call Price ($/MMBtu)$ 3.117 $ 3.117 $ 3.117 NYMEX HH Sold Puts Average Volume Per Day (MMBtu) 6,593 6,522
6,522
Weighted Average Sold Put Price ($/MMBtu)$ 2.000 $ 2.000 $ 2.000 OPIS Mt Belv Ethane Swaps Average Volume per Day (gal) 36,264 35,870 Weighted Average Fixed Price ($/gal)$ 0.2263 $ 0.2288 28
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Financial Condition Liquidity Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. The Credit Facility provides us with up to$1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is$375 million with availability further limited to a maximum of$350 million . As ofApril 30, 2021 , we had$100.7 million available under the Credit Facility. 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 the 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. Capital Resources Under our 2021 capital program, we anticipate capital expenditures of up to$186 million for the remaining three quarters of the year for an estimated annual total of up to$240 million with approximately 98 percent of capital being directed to drilling and completions. 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 for the remainder of 2021, 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 on Hand and Cash From Operating Activities. For additional information and an analysis of our historical cash from operating activities, see the "Cash Flows" discussion that follows. Credit Facility Borrowings. During the three months endedMarch 31, 2021 , we repaid$85.5 million under the Credit Facility including$80.5 million funded from the capital contribution associated with the Juniper Transactions. We also borrowed$20 million inApril 2021 to fund a portion of our capital expenditures. For additional information regarding the terms and covenants under the Credit Facility, see the "Capitalization" discussion that follows. The following table summarizes our borrowing activity under the Credit Facility for the periods presented: Borrowings Outstanding Weighted- Weighted- End of Period Average Maximum Average Rate Three months ended March 31, 2021$ 228,900 $ 243,644 $ 314,400 3.18 % Proceeds from Sales of Assets. We continually evaluate potential sales of assets, including certain non-strategic oil and gas properties and undeveloped acreage, among others. For additional information and an analysis of our historical proceeds from sales of assets, see the "Cash Flows" discussion that follows. Capital Markets Transactions. 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. 29
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