RANGER OIL CORP Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-K)
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto included in Part II, Item 8, "Financial Statements and Supplementary Data." All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain amounts for the prior period have been reclassified to conform to the current period presentation. This section of the Form 10-K discusses the results of operations for the year ended
December 31, 2021compared to the year ended December 31, 2020. The results of operations of Lonestar are reflected in our accompanying consolidated financial statements from the closing date of the Lonestar Acquisition through December 31, 2021. Results for the periods prior to October 5, 2021reflect the financial and operating results of Ranger Oiland do not include the financial and operating results of Lonestar. As such, our historical results of operations are not comparable from period to period and may not be comparable to our financial results of operations in future periods. The results of operations for the year ended December 31, 2020compared to the year ended December 31, 2019that are not included in this Form 10-K are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.
Overview and Executive Summary
We are an independent oil and gas company focused on the onshore development and production of crude oil, NGLs, and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the
Eagle Ford Shalein South Texas.
Main developments in 2021
The acquisition of
October 5, 2021, the Company acquired Lonestar Resources US Inc., a Delawarecorporation ("Lonestar"), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of Ranger Oil(the "Lonestar Acquisition"). Lonestar's oil and gas properties are located in the Eagle Ford Shalein South Texas. In accordance with the terms of the Lonestar Acquisition, Lonestar shareholders received 0.51 shares of our common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition. Based on the closing price of our common stock on October 5, 2021of $30.19, the total value of our 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 Lonestar Acquisition, the Company changed its name from Penn Virginiato Ranger Oil Corporation, and its Class A Common Stock began trading on the Nasdaq under the ticker symbol "ROCC" on October 18, 2021. See Note 4 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information.
Funding and Coverage Updates
9.25% Senior Notes and Debt Repayments
August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC(the "Escrow Issuer") completed an offering of $400 millionaggregate 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. Upon the closing of the Lonestar Acquisition, Penn Virginia Holdings, LLC("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 $249.8 millionof Lonestar's long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of $146.2 millionwas used to repay the Second Lien Term Loan (the "Second Lien Term Loan") including a prepayment premium, accrued interest and related expenses. Obligations under the 9.25% Senior Notes due 2026 are guaranteed by the subsidiaries of Holdings that guarantee our revolving credit facility (the "Credit Facility").
Increase in the borrowing base of the credit facility
Upon closing of the Lonestar Acquisition, our borrowing base under the Credit Facility increased to
$600 millionwith aggregate elected commitments of $400 million. Effective December 31, 2021the borrowing base was further increased to $725 million, with aggregate elected commitments remaining at $400 million. See Note 9 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information on our debt. 45
Immediately after acquiring Lonestar, we paid approximately
Recapitalization of the common shares of the Company
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, a new class of capital stock of the Company, was authorized, (iv) all outstanding shares of the Series A Preferred Stock ("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 15 to the consolidated financial statements included in Part II, Item 8, “Financial statements and additional data” for additional information.
January 2021, we consummated the Juniper Transactions whereby affiliates of Juniper contributed $150 millionin cash and certain oil and gas assets in Lavacaand FayetteCounties in Texasto 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 Class A Common Stock (after post-closing adjustments). For additional information regarding the Juniper Transactions, see Note 4 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data."
Industry environment and recent operational and financial highlights
Commodity prices and other economic conditions
As an oil and gas development and production company, we are exposed to a number of risks and uncertainties that are inherent to our industry. In addition to such industry-specific risks, the global public health crisis associated with COVID-19 continues to create uncertainty for global economic activity. Beginning in
March 2020, the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy, which directly impacted our industry and the Company. Over the past year, however, increased mobility, deployment of vaccines and other factors has resulted in increased oil demand and commodity prices. A high level of uncertainty remains regarding the volatility of energy supply and demand as OPEC+ continued to execute its strategy throughout 2021 to gradually increase production. In its most recent March 2022meeting, OPEC+ reconfirmed the agreement to increase output for the month of April 2022by 400,000 bbls/day. Most recently, WTI crude oil prices have jumped to over $120/bbl as a result of the Russia- Ukraineconflict and related sanctions. Higher energy prices, along with the global supply chain issues and other factors, have increased inflationary pressures, which has led or may lead to increased costs of services and certain materials necessary for our operations. Our crude oil production is sold at a premium or deduct differential to the prevailing NYMEX West Texas Intermediate ("NYMEX WTI") price. The differential reflects adjustments for location, quality and transportation and gathering costs, as applicable. In 2021, we sold 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 price differentials is provided in the “Results of Operations – Realized Differentials” discussion below.
In addition to the volatility of commodity prices, we are subject to inflationary and other factors that have resulted in higher costs for products, materials and services that we utilize in both our capital projects and with respect to our operating expenses. In 2021, we took certain actions with vendors and other service providers to secure products and services at fixed prices and to pay for certain materials and services in advance in order to lock in favorable costs but we have continued to experience higher costs and this may be exacerbated in the future. 46
Capital expenditure, development progress and production
We currently operate two drilling rigs and during the year ended
December 31, 2021, incurred capital expenditures of approximately $266.5 million, substantially all of which was directed to drilling and completion projects. During the fourth quarter 2021, a total of 12 gross (10.4 net) wells were completed and turned in line. As of March 4, 2022, we turned an additional 8 gross (6.7 net) wells in line and 3 gross (1.4 net) wells were completing and 7 gross (5.2 net) wells were in progress.
Total sales volume for the fourth quarter 2021 was 3,702 Mboe, or 40,236 boe/d, with approximately 68%, or 2,532 Mbbls, of sales volume from crude oil, 17% from NGLs and 15% from natural gas.
Commodity Hedging Program
March 4, 2022, we have hedged a portion of our estimated future crude oil and natural gas production through the second quarter of 2024. The following table, inclusive of January and February 2022production months, summarizes our hedge positions for the periods presented: 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 3,806 3,000 3,000 3,000 2,500 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl) $ 76.35 $ 74.12 $ 73.01 $ 69.20 $ 54.40 $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75NYMEX WTI Crude Collars Average Volume Per Day (bbl) 18,750 17,720 12,636 9,375 6,250 6,181 1,630 1,630 Weighted Average Purchased Put Price ($/bbl) $ 58.39 $ 59.12 $ 54.84 $ 52.17 $ 50.67 $ 50.67 $ 60.00 $ 60.00Weighted Average Sold Call Price ($/bbl) $ 72.75 $ 77.01 $ 73.83 $ 67.57 $ 65.65 $ 65.65 $ 76.12 $ 76.12NYMEX WTI Purchased Puts 1 Average Volume Per Day (bbl) 12,778 Weighted Average Purchased Put Price ($/bbl) $ 73.37NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 14,444 20,879 14,674 14,674 Weighted Average Swap Price ($/bbl) $ 0.898 $ 1.120 $ 1.172 $ 1.172NYMEX HH Swaps Average Volume Per Day (MMBtu) 17,500 12,500 12,500 12,500 10,000 7,500 Weighted Average Swap Price ($/MMBtu) $ 4.349 $ 3.727 $ 3.745 $ 3.793 $ 3.620 $ 3.690NYMEX HH Collars Average Volume Per Day (MMBtu) 3,333 13,187 13,043 13,043 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu) $ 4.150 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328Weighted Average Sold Call Price ($/MMBtu) $ 5.750 $ 3.220 $ 3.220 $ 3.220 $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000OPIS 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
1 1Q2022 NYMEX WTI Sales purchases consisting of 850,000 barrels in
The following table sets forth certain historical summary operating and financial statistics for the periods presented:
(in thousands except
unit measures, sales volume, wells and reserves)
Three Months Ended Year Ended December 31, September 30, December 31, December 31, 2021 2021 2020 2021 2020 Total sales volume (Mboe) 1 3,702 2,344 1,978 10,155 8,887 Average daily sales volume (boe/d) 1 40,236 25,483 21,502 27,822 24,281 Crude oil sales volume (Mbbl) 1 2,532 1,879 1,538 7,711 6,829 Crude oil sold as a percent of total 1 68 % 80 % 78 % 76 % 77 % Product revenues
$ 224,594 $ 140,133 $ 66,491 $ 576,824 $ 270,792Crude oil revenues $ 191,079$
Crude oil revenues as a percentage of total
85 % 91 % 92 % 90 % 93 % Realized prices: Crude oil ($/bbl) $ 75.48
$ 68.10 $ 39.66 $ 67.09 $ 36.86NGLs ($/bbl) $ 29.91 $ 27.24 $ 10.71 $ 25.23 $ 7.68Natural gas ($/Mcf) $ 4.54 $ 4.11 $ 2.45 $ 3.89 $ 1.88Aggregate ($/boe) $ 60.67 $ 59.77 $ 33.61 $ 56.80 $ 30.47Realized prices, including effects of derivatives, net 2 Crude oil ($/bbl) $ 64.50 $ 57.15 $ 48.84 $ 56.15 $ 50.55NGLs ($/bbl) $ 29.91 $ 25.77 $ 10.71 $ 24.86 $ 7.68Natural gas ($/Mcf) $ 2.99 $ 3.44 $ 1.95 $ 3.01 $ 1.88Aggregate ($/boe) $ 51.77 $ 50.49 $ 40.46 $ 47.87 $ 40.98Production and lifting costs: Lease operating ($/boe) $ 4.38 $
Collection, processing and transportation ($/boe)
$ 2.19 $
Production and ad valorem taxes ($/boe) $3.05
General and administrative ($/boe) 3 $9.57
Depreciation, depletion and amortization ($/boe)
$ 12.97 $
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 Price realized, including the effects of derivatives, net is a non-GAAP measure (see discussion and reconciliation to GAAP measure below in “Results of Operations – Effects of Derivatives” which follows) .
3 Includes combined amounts of
$7.57, $1.56, and $1.93per boe for the three months ended December 31, 2021, September 30, 2021, and December 31, 2020, respectively, and $3.92and $1.09per boe for the years ended December 31, 2021and 2020, respectively, attributable to share-based compensation and significant special charges, comprised of organizational restructuring and acquisition, divestiture and strategic transaction costs, including costs attributable to the Lonestar Acquisition during the 2021 periods and the Juniper Transaction during the 2020 periods and first quarter 2021 as described in the discussion of "Results of Operations - General and Administrative" that follows. 48
Sequential quarterly analysis
The following summarizes our key operating and financial highlights for the three months ended
December 31, 2021with comparison to the three months ended September 30, 2021. The year-over-year highlights for 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 approximately 58% to 40,236 boe per day from 25,483 boe per day due primarily to the impact of the Lonestar Acquisition which closed in October. Total sales volume increased approximately 58% to 3,702 Mboe from 2,344 Mboe due to the aforementioned factors. •Product revenues increased 60% to $224.6 millionfrom $140.1 milliondue primarily to 35% higher crude oil volume, or $44.5 millionlargely as a result of the Lonestar Acquisition in the fourth quarter of 2021, coupled with 11% higher crude oil prices, or $18.7 million. NGL revenues increased 156% due to 133% higher volume, or $9.5 millionlargely as a result of the Lonestar acquisition, as well as 10% higher prices, or $1.6 million. Natural gas revenues increased 205% due to 176% higher volume, or $8.8 millionprimarily driven by the Lonestar Acquisition in the fourth quarter of 2021 as well as 10% higher prices, or $1.4 million. •Production and lifting costs, consisting of Lease operating expenses ("LOE") and Gathering, processing and transportation expenses ("GPT"), increased on an absolute basis to $24.3 millionfrom $16.3 million, but decreased on a per unit basis to $6.57per boe from $6.97per boe due primarily the impact of the Lonestar Acquisition coupled with higher overall sales volume. •Production and ad valorem taxes increased on an absolute basis to $11.3 millionfrom $7.5 million, but decreased on a per unit basis to $3.05per boe from $3.21per boe, respectively, due primarily to the impact of the Lonestar Acquisition and higher product revenues and volumes, partially offset by the continued effect of substantially lower estimated valuations for ad valorem tax assessments. •General and administrative expenses ("G&A") increased on an absolute and per unit basis to $35.4 millionand $9.57per boe from $10.9 millionand $4.66per boe, respectively, due primarily to higher fourth quarter 2021 costs incurred in connection with the Lonestar Acquisition for legal, accounting, advisory fees, as well as acquisition-related change-in-control severance and vesting of shares held by Lonestar employees and directors. •Depreciation, depletion and amortization ("DD&A") increased on an absolute basis to $48.0 millionfrom $31.0 millionand decreased on a per unit basis from $13.21per boe to $12.97per boe due primarily to the Lonestar Acquisition, which contributed to an increase in our proved reserves at a lower relative cost per boe than our historical DD&A rate. 49
Year-over-year analysis of operating and financial results
The following tables provide a summary of our total and average daily sales volumes by product for the periods presented:
Year Ended December 31, Total Sales Volume 1 2021 2020 Change % Change Crude oil (Mbbl) 7,711 6,829 882 13 % NGLs (Mbbl) 1,326 1,165 161 14 % Natural gas (MMcf) 6,712 5,360 1,352 25 % Total (Mboe) 10,155 8,887 1,268 14 % Year Ended December 31, Average Daily Sales Volume 1 2021 2020 Change % Change Crude oil (bbl/d) 21,125 18,658 2,467 13 % NGLs (bbl/d) 3,632 3,182 450 14 % Natural gas (MMcf/d) 18 15 3 20 % Total (boe/d) 27,822 24,281 3,541 15 %
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. 2021 vs. 2020. Total sales volume increased 14% during 2021 compared to 2020 primarily driven by the Lonestar Acquisition during
October 2021. This is partially offset by the continued impact in 2021 from the temporary suspension of the drilling program in 2020 due to the global economic downturn associated with COVID-19 as our overall production levels remained depressed in early 2021. During 2021, total crude oil sales volume was approximately 76% of total sales volume compared to approximately 77% during 2020. Crude oil composition of total sales volume during 2021 was impacted by the Lonestar Acquisition in October 2021, which has a higher natural gas and NGL content.
Revenues and product prices
The following tables provide a summary of our revenue and price per unit volume by product for the periods presented:
Year Ended December 31, Total Product Revenues 2021 2020 Change % Change Crude oil
$ 517,301 $ 251,741 $ 265,560105 % NGLs 33,443 8,948 24,495 274 % Natural gas 26,080 10,103 15,977 158 % Total $ 576,824 $ 270,792 $ 306,032113 % Year Ended December 31, Product Revenues per Unit of Volume ($ per unit of volume) 2021 2020 Change % Change Crude oil $ 67.09 $ 36.86 $ 30.2382 % NGLs $ 25.23 $ 7.68 $ 17.55229 % Natural gas $ 3.89 $ 1.88 $ 2.01107 % Total $ 56.80 $ 30.47 $ 26.3386 % 50
The following table provides an analysis of the changes in our revenues for the periods presented: Year Ended December 31, 2021 vs. Year Ended December 31, 2020 Revenue Variance Due to Volume Price Total Crude oil
$ 32,513 $ 233,047 $ 265,560NGLs 1,235 23,260 24,495 Natural gas 2,548 13,429 15,977 $ 36,296 $ 269,736 $ 306,0322021 vs. 2020. Our product revenues increased during 2021 compared to 2020 due primarily to significantly higher prices and the continued economic recovery following the easing of COVID-19 restrictions throughout the year, which resulted in increases to the NYMEX WTI benchmark price of 73% for 2021, as well as an increases in overall volumes due to the Lonestar Acquisition. Total crude oil revenues were approximately 90% and 93% of our total product revenues during 2021 and 2020, respectively. Realized Differentials The following table reconciles our realized price differentials from average NYMEX-quoted prices for WTI crude oil and HH natural gas for the periods presented: Year Ended December 31, 2021 2020 Change % Change Realized crude oil prices ($/bbl) $ 67.09 $ 36.86 $ 30.2382 % Average WTI prices 68.11 39.46 $ 28.6573 % Realized differential to WTI $ (1.02) $ (2.60) $ 1.58(61) % Realized natural gas prices ($/Mcf) $ 3.89 $ 1.88 $ 2.01107 % Average HH prices ($/MMBtu) 3.82 1.99 $ 1.8392 % Realized differential to HH $ 0.07 $ (0.11) $ 0.18(164) % 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 throughout 2021, with crude oil averaging approximately $68.11per bbl for 2021. Our realized crude oil prices for 2021 include the effect of added volumes from the Lonestar Acquisition in October 2021during a period of higher prices. Beginning in March 2020, average NYMEX HH prices were also impacted by COVID-19 and the overall industry instability noted above, as well as by the colder than normal weather during first quarter 2021 that affected most of the lower 48 states and caused significant natural gas supply and demand imbalances. Recently, demand has rebounded while supply continues to be constrained, causing a significant increase in natural gas prices compared to the prior year as noted in the table above. See also the discussion of Commodity Price and Other Economic Conditions in the Overview above. 51
Effects of derivatives
We present realized prices for crude oil, NGLs and natural gas, as adjusted for the effects of derivatives, net as we believe these measures are useful to management and stakeholders in determining the effectiveness of our price-risk management program that is designed to reduce the volatility associated with our operations. Realized prices for crude oil, natural gas liquids and natural gas, as adjusted for the effects of derivatives, net, are supplemental financial measures that are not prepared in accordance with GAAP. The following table presents the calculation of our non-GAAP realized prices for crude oil, NGLs and natural gas, as adjusted for the effect of derivatives, net and reconciles to realized prices for crude oil, NGLs and natural gas determined in accordance with GAAP: Year Ended December 31, 2021 2020 Change % Change
Realized crude oil prices ($/bbl)
$ 30.2382 % Effects of derivatives, net ($/bbl) (10.94) 13.69 (24.63) (180) % Crude oil realized prices, including effects of derivatives, net ($/bbl) $ 56.15 $ 50.55 $ 5.6011 % Realized NGL prices ($/bbl) $ 25.23 $ 7.68 $ 17.55229 % Effects of derivatives, net ($/bbl) (0.37) - (0.37) 100 % NGL realized prices, including effects of derivatives, net ($/bbl) $ 24.86 $ 7.68 $ 17.18224 %
Realized Natural Gas Prices ($/MMcf)
$ 2.01107 % Effects of derivatives, net ($/Mcf) (0.88) - (0.88) 100 % Natural gas realized prices, including effects of derivatives, net ($/Mcf) $ 3.01 $ 1.88 $ 1.1360 % Effects of derivatives, net include, as applicable to the period presented: (i) current period commodity derivative settlements; (ii) the impact of option premiums paid or received in prior periods related to current period production; (iii) the impact of prior period cash settlements of early-terminated derivatives originally designated to settle against current period production; (iv) the exclusion of option premiums paid or received in current period related to future period production; and (v) the exclusion of the impact of current period cash settlements for early-terminated derivatives originally designated to settle against future period production.
Other operating income, net
Other operating income, net, includes fees for marketing and water disposal services that we charge to third parties, net of related expenses, as well as other miscellaneous revenues and credits attributable to our current operations and gains and losses on the sale or disposition of assets other than our oil and gas properties. In addition, charges attributable to credit losses associated with our trade and joint venture partner receivables are netted within this caption. The following table sets forth the total Other operating income, net recognized for the periods presented: Year Ended December 31, 2021 2020 Change % Change Other operating income, net
$ 2,667 $ 2,476 $ 1918 % 2021 vs. 2020. Our marketing fee income increased in 2021 as compared to 2020 due primarily to higher commodity-based pricing and the recovery of certain suspended revenues attributable to prior years during 2021. The increase was partially offset by lower water disposal fees in 2021 due to lower sales volumes throughout most of the year as compared to 2020. 52
Rental operating expenses
LOE includes the costs we incur to operate our producing wells and field operations. The largest costs include gas compression and extraction, chemicals, water disposal, repairs and maintenance including downhole repairs, labor on land, well pumping and maintenance, equipment rental, utilities and supplies, among others.
The following table presents our LOE for the periods presented:
Year Ended December 31, 2021 2020 Change % Change LOE
$ 45,402 $ 37,463 $ 7,93921 % Per unit ($/boe) $ 4.47 $ 4.22 $ 0.256 % 2021 vs. 2020. LOE increased on an absolute basis and per unit basis during 2021 when compared to 2020 due primarily to a combination of higher variable costs, higher gas lift costs and the impact of the Lonestar acquisition, partially offset by continued cost-containment efforts and the application of operational improvements throughout 2021.
Collection, processing and transport
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 presents our GPT expenses for the periods presented:
Year Ended December 31, 2021 2020 Change % Change GPT
$ 23,647 $ 22,050 $ 1,5977 % Per unit ($/boe) $ 2.33 $ 2.48 $ (0.15)(6) % 2021 vs. 2020. GPT expense increased on an absolute basis during 2021 as compared to 2020 due primarily to higher gas gathering costs attributable to 25% higher natural gas sales volumes, including additional volumes due to the Lonestar Acquisition. Additionally, for certain of our crude oil volumes gathered, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of $90per bbl, the gathering rate escalates. As such, with the higher prices during 2021 than in 2020, we incurred higher gathering costs associated with these volumes. These unfavorable variances were partially offset by the effects of an increase in the mix of crude oil volume sold at the wellhead, including the majority of crude oil volumes from the acquired Lonestar wells, resulting in overall lower transportation costs and cost per unit.
Taxes on production and ad valorem
Production or severance taxes represent taxes imposed by the state of
Texasin which we operate, based on the market value of our crude oil, NGLs and natural gas produced. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties, in which we operate, based on the assessed value of our operating properties. The assessments for ad valorem taxes are generally based on published index prices. The following table sets forth our production and ad valorem taxes for the periods presented: Year Ended December 31, 2021 2020 Change % Change Production/severance taxes $ 27,246 $ 11,695 $ 15,551133 % Ad valorem taxes 3,795 4,924 (1,129) (23) % $ 31,041 $ 16,619 $ 14,42287 % Per unit ($/boe) $ 3.06 $ 1.87 $ 1.1964 % Production/severance tax rate as a percent of product revenues 4.7 %
2021 vs. 2020. Production taxes increased on an absolute basis and per unit basis during 2021 when compared to 2020 due primarily to the increases in aggregate commodity sales prices in 2021. Our accruals for ad valorem taxes are based on our most recent estimates for assessments which reflect lower property values in 2021. 53
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 G&A expenses for the periods presented: Year Ended December 31, 2021 2020 Change % Change Primary G&A
$ 26,753 $ 24,086 $ 2,66711 % Share-based compensation 1 15,589 3,284 12,305 375 % Significant special charges: Organizational restructuring, including severance 367 1,446 (1,079) (75) % Acquisition/integration, divestiture and strategic transaction costs 23,820 4,973 18,847 379 % Total G&A $ 66,529 $ 33,789 $ 32,74097 % Per unit ($/boe) $ 6.55 $ 3.80 $ 2.7572 %
Per unit ($/boe) excluding stock-based compensation and other material special charges identified above
$ 2.63 $ 2.71 $ (0.08)(3) %
1 Share-based compensation for the year ended
2021 vs. 2020. Our primary G&A expenses increased on an absolute and per unit basis during 2021 compared to 2020. The increase for 2021 compared to 2020 is due primarily to higher employee compensation costs. 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 16 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data". 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 millionduring the first quarter 2021. Additionally, as a result of the Lonestar Acquisition, certain RSUs of Lonestar employees and directors immediately vested and $10.4 millionwas recorded as share-based compensation related to these vestings (see table above). 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 during 2021 compared to 2020 due to higher overall incentive compensation and severance costs as well as acquisition and integration related costs associated with the Juniper Transactions and the Lonestar Acquisition, partially offset by lower organizational restructuring costs.
Depreciation, depletion and amortization (DD&A)
Depletion and amortization expense includes charges for allocating real estate costs based on production volume, amortization of fixed assets other than oil and gas assets, and the accretion of our ARO liabilities.
The following table sets forth total and per unit costs for DD&A for the periods presented: Year Ended December 31, 2021 2020 Change % Change DD&A
$ 131,657 $ 140,673 $ (9,016)(6) % DD&A rate ($/boe) $ 12.96 $ 15.83 $ (2.87)(18) % 2021 vs. 2020. DD&A decreased on an absolute and a per unit basis during 2021 when compared to 2020. Higher production volume provided for an increase of $20.1 millionwhile lower DD&A rates in 2021 provided for a decrease of $29.1 million. The lower DD&A rate in 2021 was primarily attributable to the effect of adding additional reserves in 2021, including reserves associated with the Lonestar Acquisition, as well as the effect of the impairments recorded in the latter part of 2020 and in first quarter of 2021, as referenced and discussed further below. 54
We assess our oil and gas properties on a quarterly basis based on the results of a Ceiling Test in accordance with the full cost method of accounting for oil and gas properties. Year Ended December 31, 2021 2020 Change % Change
Impairments of oil and gas properties
$ (390,038)(100) % 2021 vs. 2020. During 2021 and 2020, we recorded impairments of our oil and gas properties as a 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. See Note 7 for more discussion. Interest Expense Interest expense includes charges for outstanding borrowings under the Credit Facility and Second Lien Term Loan, 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 Term Loan prior to repayment and the 9.25% Senior Notes due 2026 and the amortization of issuance costs capitalized attributable to the Credit Facility, the Second Lien Term Loan and the 9.25% Senior Notes due 2026. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage. The following table summarizes the components of our interest expense for the periods presented: Year Ended December 31, 2021 2020 Change % Change Interest on borrowings and related fees $ 34,02929,851 $ 4,17814 % Amortization of debt issuance costs 2,248 3,339 (1,091) (33) % Accretion of original issue discount 487 811 (324) (40) % Capitalized interest (3,603) (2,744) (859) 31 % Total interest expense, net of capitalized interest $ 33,161 $ 31,257 $ 1,9046 % 2021 vs. 2020. The increase in interest expense during 2021 is substantially attributable to interest incurred in the amount of $14.8 millionfor the 9.25% Senior Notes due 2026. This is offset by decreased interest expense attributable to the Credit Facility and Second Lien Term Loan during 2021 as compared to 2020 due primarily to the effect of lower outstanding balances during 2021 and lower interest rates associated with the Credit Facility, resulting from lower applicable margins based on lower utilization levels and the payoff of the Second Lien Term Loan upon the closing of the Lonestar Acquisition. The weighted-average balances under the Credit Facility were lower in 2021 by approximately $111 million. The weighted-average interest rates during the same periods were lower by 40 basis points. The accretion of OID is attributable to the Second Lien Term Loan prior to repayment and 9.25% Senior Notes due 2026 and the amortization of debt issuance costs includes amounts attributable to the Credit Facility, Second Lien Term Loan and 9.25% Senior Notes due 2026. We capitalized a larger portion of interest during 2021 as we maintained a higher portion of unproved property as compared to 2020 due primarily to the acquisition of unproved properties in the Juniper Transactions and the Lonestar Acquisition coupled with the impact of additional interest related to the 9.25% Senior Notes due 2026. 55
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: Year Ended December 31, 2021 2020 Change % Change Commodity derivative gains (losses)
$ (136,997) $ 95,932 $ (232,929)(243) % Interest rate swap gains (losses) (2) (7,510) 7,508 (100) % Total $ (136,999) $ 88,422 $ (225,421)(255) % 2021 vs. 2020. In 2021, commodity prices recovered to levels that were significantly higher on an average aggregate basis than those during 2020. Accordingly, the derivative losses in 2021 reflect the decline in the mark-to-market values consistent with the increase in prices attributable to open positions. The effect in 2020 was in the opposite direction as the mark-to-market gains were attributable to the substantial decline 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 $77.1 millionduring 2021 as compared to realized settlement receipts, net of $80.3 millionduring 2020. In 2020, we began hedging a portion of our exposure to variable interest rates associated with our Credit Facility and Second Lien Term Loan. During 2021 and 2020, we paid $3.8 millionand $2.2 millionof net settlements from our interest rate swaps, respectively.
Income taxes represent our income tax provision as determined in accordance with generally accepted accounting principles. It considers taxes attributable to our obligations for federal taxes under the Internal Revenue Code as well as to the various states in which we operate, primarily
Texas, or otherwise have continuing involvement. The following table summarizes our income tax provision for the periods presented: Year Ended December 31, 2021 2020 Change % Change Income tax (expense) benefit $ (1,560) $ 2,303 $ (3,863)(168) % Effective tax rate (1.6) % (0.7) % (0.9) % 129 % 2021. The provision for the year ended December 31, 2021includes a deferred state tax expense of $1.2 millionattributable to property and equipment and $0.3 millionof current state expense attributable to the Texasmargin tax for the year ended December 31, 2021for an overall effective tax rate of 1.6%. 2020. The provision for the year ended December 31, 2020includes current federal benefits of $1.2 millionattributable to refundable alternative minimum tax, or AMT, credits for the 2020 tax year, which when combined with the amounts attributable to 2019 that had been recognized on our consolidated balance sheets as of December 31, 2019as a current asset, were received in 2020 as an acceleration of all AMT credits in connection with certain provisions of the CARES Act. This AMT benefit was offset by a corresponding decrease in the deferred tax asset associated with AMT credit carryforwards giving rise to deferred federal expense for the year ended December 31, 2020. In addition, we recognized a deferred state tax benefit of $2.7 millionattributable to property and equipment and $0.4 millionof current state expense attributable to the Texasmargin tax for the year ended December 31, 2020for an overall effective tax rate of 0.7%. 56
Cash and capital resources
Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. As of
December 31, 2021, we had liquidity of $214.8 million, comprised of cash and cash equivalents of $23.7 millionand availability under our Credit Facility of $191.1 million(factoring in letters of credit). Additionally, following the closing of the Lonestar Acquisition, the borrowing base under the Credit Facility was increased to $600 million, with aggregate elected commitments of $400 million. Effective December 31, 2021, the borrowing base was further increased to $725 million, with aggregate elected commitments remaining at $400 million. On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC(the "Escrow Issuer") completed an offering of $400 millionaggregate 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 Lonestar Acquisition. Upon the closing of the Lonestar Acquisition, 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 Term Loan including a prepayment premium, accrued interest and related expenses. See Note 9 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" 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 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 2024. The level of our hedging activity and duration of the financial instruments employed depends on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.
We continually evaluate potential asset sales, including certain non-strategic oil and gas properties and undeveloped acreage, among others. In addition, from time to time and under market conditions which we believe are favorable to us, we may consider transactions in the capital markets, including the offering of debt and equity securities. We maintain an effective shelf registration statement to enable optionality.
We expect 2022 capital expenditures of up to approximately
$435 million, of which approximately $425 millionis expected to be allocated to drilling and completion activities. We plan to fund our 2022 capital program and our operations for the next twelve months primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our capital spending and operations for at least the next twelve months; however, future cash flows are subject to a number of variables including the current global economic uncertainties remaining after the COVID-19 pandemic and related instability in the global energy markets and geopolitical climate. Additionally, we have other obligations primarily consisting of our outstanding debt principal and interest obligations, derivative instruments, service agreements, operating leases, and asset retirement and environmental obligations, all of which are customary in our business. See "Commitments and Contingencies" summarized below, as well as Note 6 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for more details related to these obligations. In March 2022, we announced an intention to commence a quarterly dividend on our Class A Common Stock in the third quarter of 2022. Each Common Unit in the Partnership would be entitled to a distribution in the same amount of any dividend paid on the Class A Common Stock. We expect to fund all such dividends with cash flow from operations. 57
The following table summarizes our cash flows for the periods presented:
2021 2020 Net cash provided by operating activities 289,025 222,265 Net cash used in investing activities (245,174) (168,478) Net cash provided by (used in) financing activities (33,190) (48,565) Net increase (decrease) in cash and cash equivalents $
Cash Flows from Operating Activities. The increase of
$66.8 millionin net cash from operating activities for 2021 compared to 2020 was primarily attributable to the effect of cash receipts that were derived from higher average prices and total sales volumes in 2021, net of interest rate swap settlements in the 2021 period as compared to 2020, partially offset by (i) higher net payments for commodity derivatives settlements and premiums, (ii) transaction costs paid in connection with the Juniper Transactions and Lonestar Acquisition and related integration costs, and (iii) executive restructuring costs, including severance payments. Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during 2021 compared to 2020, due primarily to the suspension of the drilling and completion program for approximately half of the year in 2020 as a result of the COVID-19 pandemic and related market instability. The following table sets forth costs related to our capital expenditure program for the periods presented: Year Ended December 31, 2021 2020 Drilling and completion $ 263,936 $ 125,626
Lease acquisitions, land costs and geological and geophysical (seismic) costs
3,773 3,789 Pipeline, gathering facilities and other equipment, net 1 (1,252) 1,193 Total capital expenditures program costs
$ 266,457 $ 130,608
1 Includes certain capital charges for our working partners for completion services.
The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures as presented in our Consolidated Statements of Cash Flows for the periods presented:
2021 2020 Total capital expenditures program costs (from above)
$ 266,457 $ 130,608
Decrease (increase) in accounts payable for fixed assets and capitalized accrued liabilities
Net purchases/(transfers) of tubular stocks and well materials 1
Down payments for drilling and completion services, net of (transfers)
(4,018) 13,608 Capitalized internal labor, capitalized interest and other 7,242 4,811 Total cash paid for capital expenditures
$ 256,343 $ 168,565
1 Includes purchases made before drilling.
Cash Flows from Financing Activities. During 2021, we received net proceeds of
$396.1 millionfrom the offering of the 9.25% Senior Notes due 2026 in connection with the Lonestar Acquisition and $151.2 millionfrom the issuance of equity in connection with the Juniper Transactions (See Note 4). The proceeds from these transactions were primarily used to: (i) repay and discharge $249.6 millionof Lonestar's outstanding long-term debt, (ii) repay the $200 millionSecond Lien Term Loan, (iii) repayments of $80.5 millionunder the Credit Facility, and (iv) pay $9.3 millionof transaction and issue costs related to Juniper. Additionally, during 2021, we had borrowings of $70.0 millionand additional repayments of $95.9 millionunder the Credit Facility and paid $14.4 millionin debt issuance costs. During 2020, we had borrowings of $51.0 millionand repayments of $99.0 millionunder the Credit Facility which were used to fund a portion of the capital program at the beginning of 2020. 58
The following table summarizes our total capitalization at the dates presented:
December 31, 2021 2020 Credit Facility borrowings
$ 208,000 $ 314,400Second Lien Term Loan, net - 195,097 9.25% Senior Notes due 2026, net 386,427 - Mortgage debt 1 8,438 - Other 2,516 - Total debt, net 605,381 509,497 Total equity 669,508 212,838 Total capitalization $ 1,274,889 $ 722,335Debt as a % of total capitalization 47 % 71 % _______________________ 1 The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on our consolidated balance sheets in our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data.". Credit Facility. As of December 31, 2021, the Credit Facility had a $1.0 billionrevolving commitment and a $725 millionborrowing base, with aggregate elected commitments of $400 millionand a $25 millionsublimit for the issuance of letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes including working capital. We had $0.9 millionand $0.4 millionin letters of credit outstanding as of December 31, 2021and 2020. The maturity date under the Credit Facility is October 6, 2025. The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar 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 December 31, 2021, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.26%. 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 December 31, 2021 $ 208,000 $ 245,661 $ 262,9003.22 % Year ended December 31, 2021 $ 208,000 $ 242,329 $ 314,4003.15 % The Credit Facility is guaranteed by all of the subsidiaries of the borrower (the "Guarantor Subsidiaries"), except for Boland Building, LLCwhich holds real estate assets that are associated with mortgage obligations assumed in the Lonestar Acquisition. The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on the ability of the borrower or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries' assets. Second Lien Term Loan. On October 5, 2021, Holdings repaid all of its outstanding obligations under the Second Lien Term Loan, and terminated the Second Lien Term Loan. In accordance with the Second Lien Term Loan, we incurred a prepayment premium of 102% as a result of repayment. In connection with the repayment of the Second Lien Term Loan, we incurred costs related to the premium and write off of unamortized discount and issuance costs of $6.9 millionrecorded as a loss on extinguishment of debt. 59
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 millionaggregate principal amount of senior unsecured notes due 2026 (the "9.25% Senior Notes due 2026") that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed by Holdings, as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility. Covenant Compliance. As of December 31, 2021, the Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset) of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00. The Credit Facility and the Indenture contains customary affirmative and negative covenants as well as events of default and remedies including certain anti-hoarding provisions. 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.
See Note 9 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information on our debt. Commitments and Contingencies Long-Term Debt We have long-term debt obligations that have various maturities and interest rates. For information on our debt obligations, see Note 9 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for more details.
We have various non-cancelable operating leases in connection with the leases of our office facilities and equipment. See Note 11 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for further information.
Commitments for collection and intermediate transport
We have agreements for gathering and intermediate pipeline transportation services for our crude oil and condensate production. For further details on these agreements, see Note 14 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data."
Asset retirement obligations
We have ORAs that primarily relate to the plugging and abandonment of oil and gas wells. For more information on our AROs, see Notes 8 and 14 to the consolidated financial statements included in Part II, Section 8, “Financial Statements and Supplementary Data”.
Critical accounting estimates
The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting estimates requiring judgment of our management.
Oil and gas reserves
Estimates of our oil and gas reserves are the most critical estimate included in our consolidated financial statements. Reserve estimates become the basis for determining depletive write-off rates and the recoverability of historical cost investments. There are many uncertainties inherent in estimating crude oil, NGL and natural gas reserve quantities, including projecting the total quantities in place, future production rates and the amount and timing of future development expenditures. In addition, reserve estimates of new discoveries are less precise than those of producing properties due to the lack of a production history. Accordingly, these estimates are subject to change as additional information becomes available. There are several factors which could change the estimates of our oil and gas reserves. Significant rises or declines in commodity product prices as well as changes in our drilling plans could lead to changes in the amount of reserves as production activities become more or less economical. An additional factor that could result in a change of recorded reserves is the reservoir decline rates differing from those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs.
We apply the full cost method to account for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of DD&A. Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case, the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. Factors we consider in our assessment include drilling results, the terms of oil and gas leases not held by production and drilling and completion capital expenditures consistent with our plans. At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes, or a Ceiling Test. The estimated after-tax 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. During the first quarter of 2021, the carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test, resulting in a
$1.8 millionimpairment. There were no other such impairments during 2021. During 2020, the carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test in the second, third and fourth quarters of 2020, resulting in a total of $391.8 millionof impairment charges recorded for the year ended December 31, 2020. 61
We utilize derivative instruments, typically swaps, put options and call options which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. All derivative instruments are recognized in our consolidated financial statements at fair value with the changes recorded currently in earnings. We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.
Provision for valuation of deferred tax assets
We record a valuation allowance to reduce our deferred tax assets to an amount that is more likely than not to be realized after consideration of expected future taxable income and reasonable tax planning strategies. In the event that we were to determine that we would not be able to realize all or a part of our deferred tax assets for which a valuation allowance had not been established, an adjustment to the deferred tax asset will be reflected in income in the period such determination is made. The most significant matter applicable to the realization of our deferred tax assets is attributable to net operating losses at the federal level as well as certain states in which we operate. Estimates of future taxable income inherently reflect a significant degree of uncertainty. As of
December 31, 2021, we believe it is more likely than not that we will not have sufficient future taxable income to realize the benefit of our gross deferred tax assets and, accordingly, have maintained a full valuation allowance.
Determination of fair value in business combinations
Accounting for the acquisition of a business requires allocation of the purchase price to the various assets acquired and liabilities assumed at their respective fair values. The determination of fair value requires the use of significant estimates and assumptions, and in making these determinations management uses all available information. If necessary, we have up to one year after the acquisition closing date to finalize these fair value determinations. For assets acquired in a business combination, the determination of fair value utilizes several valuation methodologies including discounted cash flows, which has assumptions with respect to the timing and amount of future revenue and expenses associated with an asset, and in the case of oil and gas companies, these as they relate to the reserves associated with its oil and gas properties. The assumptions made in performing these valuations include, but are not limited to, discount rate, future revenues and operating costs, projections of capital costs, and other assumptions believed to be consistent with those used by principal market participants. Due to the specialized nature of these calculations, we engage third-party specialists to assist management in evaluating our assumptions as well as appropriately measuring the fair value of assets acquired and liabilities assumed. 62
© Edgar Online, source