RANGER OIL CORPORATION 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. This section of the Form 10-K discusses the results of operations for the year endedDecember 31, 2022 compared to the year endedDecember 31, 2021 . OnOctober 5, 2021 , the Company acquired Lonestar Resources US Inc., aDelaware corporation ("Lonestar"), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of the Company (the "Lonestar Acquisition"). Results for the periods prior toOctober 5, 2021 reflect the financial and operating results ofRanger Oil and do not include the financial and operating results of Lonestar. As such, our historical results of operations are not comparable from period to period. The results of operations for the year endedDecember 31, 2021 compared to the year endedDecember 31, 2020 that 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 endedDecember 31, 2021 .
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 theEagle Ford Shale inSouth Texas .
Key Developments
Proposed Merger with Baytex
OnFebruary 27, 2023 , we entered into the Merger Agreement for the Baytex Merger. Subject to the terms and conditions of the Merger Agreement, each share of our Class A Common Stock issued and outstanding immediately prior to the effective time of the Baytex Merger (including shares of our Class A Common Stock to be issued in connection with the exchange of the Class B Common Stock and Common Units for Class A Common Stock), will be converted automatically into the right to receive: (i) 7.49 Baytex common shares and (ii)$13.31 in cash. The transaction was unanimously approved by the board of directors of each company and JSTX andRocky Creek delivered a support agreement to vote their outstanding shares in favor of the Baytex Merger. The Baytex Merger is expected to close late in the second quarter of 2023, subject to the satisfaction of customary closing conditions, including the requisite shareholder and regulatory approvals.
Share Repurchase Program
OnApril 13, 2022 , our Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to$100 million of its outstanding Class A Common Stock throughMarch 31, 2023 . OnJuly 7, 2022 , the Board of Directors authorized an increase in the share repurchase program from$100 million to$140 million and extended the term of the program throughJune 30, 2023 . We do not intend to repurchase additional shares pending closing of the Baytex Merger. During the year endedDecember 31, 2022 , we repurchased 2,150,486 shares of our Class A Common Stock at a total cost of$75.2 million at an average purchase price of$34.95 . Subsequent toDecember 31, 2022 throughMarch 3, 2023 , we repurchased an additional 121,857 shares of our Class A Common Stock at an average price of$39.52 for a total cost of$4.8 million .
See Note 15 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information.
Dividends
OnJuly 7, 2022 andNovember 2, 2022 , the Company's Board of Directors declared cash dividends of$0.075 per share of Class A Common Stock. The dividends were paid onAugust 4, 2022 andNovember 28, 2022 to holders of record of Class A Common Stock as of the close of business onJuly 25, 2022 andNovember 16, 2022 , respectively. Additionally, onMarch 3, 2023 , the Company's Board of Directors declared a cash dividend of$0.075 per share of Class A Common Stock payable onMarch 30, 2023 to holders of record of Class A Common Stock as of the close of business onMarch 17, 2023 . 48
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Recent Acquisitions
During 2022, we closed on several acquisitions of oil and gas producing properties in theEagle Ford Shale , comprised of additional working interests in Ranger-operated wells and adjacent producing assets and undeveloped acreage for aggregate cash consideration totaling$137.5 million , including customary post-closing adjustments. See Note 4 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information on our acquisitions.
Increased Borrowing Base of Credit Facility
During 2022, the aggregate elected commitment amounts under the Credit Facility increased from$400 million to$500 million and our borrowing base increased to$950 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.
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.
There continues to be a high level of uncertainty around the volatility of energy supply and demand. OPEC+ has recently changed its strategy from one which has seen gradually increasing production throughout 2021 and most of 2022 to one of drastically cutting production. InOctober 2022 , OPEC+ announced its intent to decrease output targets by 2 Mbbls per day inNovember 2022 , after increasing output target by 100,000 bbls per day inSeptember 2022 and following the raising of output by 648,000 bbls per day in July andAugust 2022 . Additionally, certain OPEC+ members are pumping below their targeted volumes under the current agreement. At theFebruary 2023 meeting, OPEC+ reaffirmed the output targets agreed to inOctober 2022 and noted that would remain the policy moving forward in 2023. These shifts in OPEC+ production levels as well as theRussia -Ukraine war and related sanctions, which began in the first quarter of 2022, and continuing impact of the COVID-19 global public health crisis continue to contribute to volatility in commodity prices. During 2022, NYMEX West Texas Intermediate ("NYMEX WTI") crude oil and NYMEX Henry Hub ("NYMEX HH") natural gas prices ranged from highs of approximately$123 per bbl and over$9 per Mcf, respectively, to lows of approximately$71 per bbl and under$4 per Mcf, respectively, due to oil supply shortage concerns and factors discussed above. Higher commodity prices, along with the global supply chain issues and other factors, have increased inflation, which has led or may lead to increased costs of services and certain materials necessary for our operations. Governmental actions to combat inflation, including the Inflation Reduction Act passed into law inAugust 2022 as well as interest rate hikes by theFederal Reserve and increased recession fears also continue to create pricing and economic volatility in the markets. The ultimate effect of these measures on inflation and overall energy supply and demand is uncertain at this time. 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. All of our crude oil volumes are sold under Magellan East Houston ("MEH") pricing, which historically has been at a premium to NYMEX WTI. Similar to crude prices, natural gas prices remain volatile as a result of theRussia -Ukraine war and other factors discussed above, with NYMEX HH closing as low as$3.45 per Mcf and as high as$9.85 per Mcf during 2022. Subsequently, natural gas prices declined even further during 2023 with NYMEX HH closing as low as$2.08 per Mcf. 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 sold has a premium or deduct differential to the prevailing NYMEX HH price primarily due to adjustments for location and energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual interaction of supply and demand.
A summary of these pricing differentials is provided in the discussion of "Results of Operations - Realized Differentials" that follows.
In addition to the volatility of commodity prices, we are subject to
inflationary and other factors that have resulted in higher costs for products,
materials and services that we utilize in both our capital projects and with
respect to our operating expenses. We continue to work with vendors and other
service providers to secure competitive pricing and fixed pricing terms whenever
favorable in an effort to resist inflationary pressures. However, supply chain
constraints may continue and exacerbate inflationary demands in the future.
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Capital Expenditures, Development Progress and Production
As ofDecember 31, 2022 , we operated three drilling rigs and during the year endedDecember 31, 2022 , we incurred capital expenditures of approximately$524.6 million , of which$513.9 million was directed to drilling and completion projects. During the fourth quarter 2022, a total of 16 gross (14.6 net) wells were completed and turned to sales. As ofMarch 3, 2023 , we turned an additional 12 gross (11.1 net) wells to sales and 5 gross (4.3 net) wells were completing and 11 gross (10.0 net) wells were in progress. As ofMarch 3, 2023 , we had approximately 187,700 gross (163,800 net) acres in theEagle Ford Shale , net of expirations, of which approximately 95% is held by production. Total sales volume for the fourth quarter 2022 was 4,069 Mboe, or 44,227 boe/d, with approximately 72%, or 2,916 Mbbls, of sales volume from crude oil, 15% from NGLs and 13% from natural gas.
Commodity Hedging Program
As ofMarch 3, 2023 , we have hedged a portion of our estimated future crude oil, NGL and natural gas production through the second quarter of 2024. The following table, inclusive of January andFebruary 2023 production months, summarizes our net hedge position for the periods presented: 1Q2023 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 2,500 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl)$ 54.40 $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75 NYMEX WTI Crude Collars Average Volume Per Day (bbl) 24,306 19,918 16,304 8,967 Weighted Average Purchased Put Price ($/bbl)$ 68.74 $ 67.45 $ 72.50 $ 72.27 Weighted Average Sold Call Price ($/bbl)$ 83.87 $ 78.70
MEH WTI CMA Crude Differential Swaps Average Volume Per Day (bbl) 7,778 13,187 Weighted Average Swap Price ($/bbl)$ 2.03 $ 2.03 NYMEX HH Swaps Average Volume Per Day (MMBtu) 10,000 7,500 Weighted Average Swap Price ($/MMBtu)$ 3.620 $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 14,617 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu)$ 6.561 $ 2.500
$ 12.334 $ 2.682
24,617 19,038 11,413 11,413
HSC Basis Average Fixed Price
($/MMBtu) $ (0.153) $ (0.153) $ (0.153) $ (0.153)
OPIS Mt. Belvieu Ethane Swaps
Average Volume per Day (gal) 98,901 34,239 34,239 34,615
Weighted Average Fixed Price
($/gal) $ 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 Year Ended December 31,
December 31, September 30, December 31,
2022 2022 2021 2022 2021
Total sales volume (Mboe) 1 4,069 3,921 3,702 14,890 10,155
Average daily sales volume (boe/d) 1 44,227 42,624 40,236 40,793 27,822
Crude oil sales volume (Mbbl) 1 2,916 2,822 2,532 10,668 7,711
Crude oil sold as a percent of total 1 72 % 72 % 68 % 72 % 76 %
Product revenues $ 268,455 $ 304,105 $ 240,397 $ 262,537
86 % 85 % 88 % 90 %
Realized prices:
Crude oil ($/bbl) $ 82.46 $ 93.03 $ 75.48 $ 94.04 $ 67.09
NGLs ($/bbl) $ 21.75 $ 31.97 $ 29.91 $ 30.59 $ 25.23
Natural gas ($/Mcf) $ 4.53 $ 7.41 $ 4.54 $ 5.86 $ 3.89
Aggregate ($/boe) $ 65.98 $ 77.55 $ 60.67 $ 76.67 $ 56.80
Realized prices, including effects of
derivatives, net 2
Crude oil ($/bbl) $ 76.43 $ 83.14 $ 64.50 $ 79.53 $ 56.15
NGLs ($/bbl) $ 21.17 $ 30.67 $ 29.91 $ 29.70 $ 24.86
Natural gas ($/Mcf) $ 2.76 $ 4.26 $ 2.99 $ 3.74 $ 3.01
Aggregate ($/boe) $ 60.15 $ 67.76 $ 51.77 $ 64.42 $ 47.87
Production and lifting costs:
Lease operating ($/boe) $ 6.06 $ 6.15 $ 2.27 $ 2.50
$ 17.96 $ 16.88
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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$0.07 ,$0.48 , and$7.57 per boe for the three months endedDecember 31, 2022 ,September 30, 2022 , andDecember 31, 2021 , respectively, and$0.49 and$3.92 per boe for the years endedDecember 31, 2022 and 2021, respectively, attributable to share-based compensation and certain special charges, comprised of organizational restructuring, including severance and acquisition, integration and strategic transaction costs, including costs attributable to the Lonestar Acquisition during those periods, the Juniper Transactions during the year ended 2021 as well as costs attributable to our 2022 acquisitions in the 2022 periods as described in the discussion of "Results of Operations - General and Administrative" that follows. 51
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Sequential Quarterly Analysis
The following summarizes our key operating and financial highlights for the three months endedDecember 31, 2022 with comparison to the three months endedSeptember 30, 2022 . The year-over-year highlights for 2022 and 2021 are addressed in the discussions that follow below in Year over Year Analysis of Operating and Financial Results. •Daily sales volume and total sales volume increased approximately 4% to 44,227 boe/d and 4,069 Mboe, respectively, for the three months endedDecember 31, 2022 compared to 42,624 boe/d and 3,921 Mboe for the three months endedSeptember 30, 2022 . The increase was primarily due to 14.6 net wells turned to sales during the fourth quarter of 2022. •Product revenues decreased 12% to$268.5 million from$304.1 million as a result of 15% lower aggregate realized prices, partially offset by 4% higher total sales volumes. Crude oil revenues were 8% lower due primarily to 11% lower crude oil prices, or$30.8 million , partially offset by 3% higher volume, or$8.7 million . NGL revenues decreased 29% due to 32% lower prices, or$6.2 million , partially offset by 4% higher volume, or$0.8 million . Natural gas revenues decreased 35% due to 39% lower prices, or$9.4 million , partially offset by 6% higher volume, or$1.3 million . •Lease operating expenses ("LOE") increased slightly on an absolute basis to$24.7 million from$24.1 million primarily driven by$1.3 million of increased water disposal costs, partially offset by$0.8 million associated with less workover activity. LOE decreased on a per unit basis to$6.06 from$6.15 due to the effects of the 4% higher sales volume discussed above. •Gathering, processing and transportation expenses ("GPT") decreased on an absolute and per unit basis to$9.2 million and$2.27 per boe, respectively, from$9.8 million and$2.50 per boe, respectively, due to lower GPT costs from lower prices for crude oil and natural gas. For certain of our crude oil volumes gathered, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of$90 per bbl, the gathering rate escalates. As such, with the lower prices during the three months endedDecember 31, 2022 compared to the three months endedSeptember 30, 2022 , we incurred lower gathering costs associated with these volumes which caused a corresponding decrease on a per unit basis. •Production and ad valorem taxes decreased on an absolute basis to$14.8 million from$16.7 million and decreased on a per unit basis to$3.63 per boe from$4.26 per boe, respectively, due primarily to lower product revenues driven by lower aggregated realized prices, despite higher volumes. •General and administrative expenses ("G&A") increased on an absolute and per unit basis to$10.7 million and$2.64 per boe from$9.8 million and$2.51 per boe, respectively, due primarily to$1.2 million increase in compensation costs and$0.3 million increase in information technology costs, partially offset by$0.4 million in lower insurance costs and$0.2 million lower consulting and professional fees. •Depreciation, depletion and amortization ("DD&A") increased on an absolute and per unit basis to$73.1 million and$17.96 per boe during the fourth quarter 2022 from$66.2 million and$16.88 per boe due during the third quarter 2022 primarily due to increased future development costs associated with proved reserve additions that were at a higher relative cost per boe as compared to third quarter 2022. 52
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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:
Year Ended December 31,
Total Sales Volume 1 2022 2021 Change % Change
Crude oil (Mbbl) 10,668 7,711 2,957 38 %
NGLs (Mbbl) 2,205 1,326 879 66 %
Natural gas (MMcf) 12,100 6,712 5,388 80 %
Total (Mboe) 14,890 10,155 4,735 47 %
Year Ended December 31,
Average Daily Sales Volume 1 2022 2021 Change % Change
Crude oil (bbl/d) 29,227 21,125 8,102 38 %
NGLs (bbl/d) 6,041 3,632 2,409 66 %
Natural gas (MMcf/d) 33 18 15 83 %
Total (boe/d) 40,793 27,822 12,971 47 %
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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. 2022 vs. 2021. Total sales volume increased 47% during 2022 compared to 2021 primarily driven by the Lonestar Acquisition that closed inOctober 2021 as well as the other asset acquisitions that closed in 2022 and increased drilling activity. During 2022, total crude oil sales volume was approximately 72% of total sales volume compared to approximately 76% during 2021. The decrease in crude oil composition of total sales volume during 2022 is due primarily to higher gas content of the wells acquired in the Lonestar Acquisition in 2021.
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:
Year Ended December 31,
Total Product Revenues 2022 2021 Change % Change
Crude oil $ 1,003,255 $ 517,301 $ 485,954 94 %
NGLs 67,453 33,443 34,010 102 %
Natural gas 70,895 26,080 44,815 172 %
Total $ 1,141,603 $ 576,824 $ 564,779 98 %
Year Ended December 31,
Realized Prices ($ per unit of volume) 2022 2021 Change % Change
Crude oil $ 94.04 $ 67.09 $ 26.95 40 %
NGLs $ 30.59 $ 25.23 $ 5.36 21 %
Natural gas $ 5.86 $ 3.89 $ 1.97 51 %
Total $ 76.67 $ 56.80 $ 19.87 35 %
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The following table provides an analysis of the changes in our revenues for the
periods presented:
Year Ended December 31, 2022 vs.
Year Ended December 31, 2021
Revenue Variance Due to
Volume Price Total
Crude oil $ 198,394 $ 287,560 $ 485,954
NGLs 22,188 11,822 34,010
Natural gas 20,935 23,880 44,815
$ 241,517 $ 323,262 $ 564,779
2022 vs. 2021. Our product revenues increased during 2022 compared to 2021 due
primarily to significantly higher prices stemming from macroeconomic factors and
volatility in the global commodity markets as a result of continued economic
recovery, as well as supply concerns resulting from the Russia -Ukraine war.
These factors resulted in an increase to the NYMEX WTI benchmark price of 38%
for 2022 as compared to 2021. Also contributing to the higher product revenues
was an increase in volumes across commodities as discussed above, with overall
increase in Mboe of 47% for 2022. Total crude oil revenues were approximately
88% and 90% of our total product revenues during 2022 and 2021, 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,
2022 2021 Change % Change
Average WTI prices ($/bbl) $ 94.33 $ 68.11 $ 26.22 38 %
Realized differential to WTI (0.29) (1.02) 0.73 72 %
Realized crude oil prices ($/bbl) $ 94.04 $ 67.09 $ 26.95 40 %
Average HH prices ($/MMBtu) $ 6.38 $ 3.82 $ 2.56 67 %
Realized differential to HH (0.52) 0.07 (0.59) (843) %
Realized natural gas prices ($/Mcf) $ 5.86 $ 3.89 $ 1.97 51 %
Our differential to NYMEX WTI for 2022 improved by 72% compared to 2021 due to
more favorable NYMEX Calendar Month Average contractual pricing and more
favorable pricing negotiated with certain crude purchasers effective early in
first quarter 2022. Our differential to NYMEX HH was negatively impacted for
2022 as compared to 2021 due to more unfavorable location basis differentials.
See also the discussion of Commodity Price and Other Economic Conditions in the
Overview above.
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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, NGLs 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,
2022 2021 Change % Change
Realized crude oil prices ($/bbl)
$ 26.95 40 % Effects of derivatives, net ($/bbl) (14.51) (10.94) (3.57) (33) % Crude oil realized prices, including effects of derivatives, net ($/bbl)$ 79.53 $ 56.15 $ 23.38 42 % Realized NGL prices ($/bbl)$ 30.59 $ 25.23 $ 5.36 21 % Effects of derivatives, net ($/bbl) (0.89) (0.37) (0.52) (141) % NGL realized prices, including effects of derivatives, net ($/bbl)$ 29.70 $ 24.86 $ 4.84 19 %
Realized natural gas prices ($/Mcf)
$ 1.97 51 % Effects of derivatives, net ($/Mcf) (2.12) (0.88) (1.24) (141) % Natural gas realized prices, including effects of derivatives, net ($/Mcf)$ 3.74 $ 3.01 $ 0.73 24 % 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,
2022 2021 Change % Change
Other operating income, net $ 3,586 $ 2,667 $ 919 34 %
2022 vs. 2021. Our marketing fee income increased in 2022 as compared to 2021
due primarily to higher commodity-based pricing, higher water disposal fees in
2022 due to higher sales volumes, gains on sales of field materials and fixed
assets in 2022, partially offset by higher credit losses in 2022 and
miscellaneous income recognized in 2021.
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Lease Operating Expenses
LOE include costs that we incur to operate our producing wells and field operations. The most significant costs include compression for gas lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, equipment rentals, utilities and supplies, among others.
The following table sets forth our LOE for the periods presented:
Year Ended December 31,
2022 2021 Change % Change
Lease operating $ 85,792 $ 45,402 $ 40,390 89 %
Per unit ($/boe) $ 5.76 $ 4.47 $ 1.29 29 %
2022 vs. 2021. LOE increased on an absolute basis and per unit basis during 2022
when compared to 2021 due primarily to the Lonestar Acquisition and the other
asset acquisitions that closed in 2022, increased workover activity and higher
fuel, service and equipment costs driven by higher sales volume coupled with
inflationary pressures throughout 2022.
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:
Year Ended December 31,
2022 2021 Change % Change
GPT $ 36,698 $ 23,647 $ 13,051 55 %
Per unit ($/boe) $ 2.46 $ 2.33 $ 0.13 6 %
2022 vs. 2021. GPT expense increased on an absolute basis during 2022 as
compared to 2021 due primarily to the Lonestar Acquisition and the other asset
acquisitions that closed in 2022, which contributed to 80% higher natural gas
sales volumes and 38% higher crude oil sales volumes for 2022. Additionally, for
certain of our crude oil volumes gathered, our rate includes an adjustment based
on NYMEX WTI prices. As crude oil prices increase, up to a cap of $90 per bbl,
the gathering rate escalates. As such, with the higher prices during 2022 as
compared to 2021, we incurred higher gathering costs associated with these
volumes which caused a corresponding increase on a per unit basis. 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, which reduces transportation costs
and cost per unit.
Production and Ad Valorem Taxes
Production or severance taxes represent taxes imposed by the states in which we
operate for the removal of resources including crude oil, NGLs and natural gas.
Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily
counties, in which we operate, based on the assessed value of our operating
properties. The assessments for ad valorem taxes are generally based on
published index prices.
The following table sets forth our production and ad valorem taxes for the
periods presented:
Year Ended December 31,
2022 2021 Change % Change
Production/severance taxes $ 52,737 $ 27,246 $ 25,491 94 %
Ad valorem taxes 8,640 3,795 4,845 128 %
Production/severance and ad valorem taxes $ 61,377 $ 31,041 $ 30,336 98 %
Per unit ($/boe) $ 4.12 $ 3.06 $ 1.06 35 %
Production/severance tax rate as a percent of
product revenues 4.6 % 4.7 % (0.1) % (2) %
2022 vs. 2021. Production and ad valorem taxes increased on an absolute basis
and per unit basis during 2022 when compared to 2021 due primarily to the impact
of higher volumes from the Lonestar Acquisition and other asset acquisitions
that closed in 2022. Additionally, production taxes increased on an absolute and
per unit basis due to higher aggregate commodity sales prices during 2022. Our
accruals for ad valorem taxes are based on our most recent estimates for
assessments which increased from the lower property values in 2021.
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General and Administrative
Our G&A expenses include employee compensation, benefits and other related costs
for our corporate management and governance functions, rent and occupancy costs
for our corporate facilities, insurance, and professional fees and consulting
costs supporting various corporate-level functions, among others. In order to
facilitate a meaningful discussion and analysis of our results of operations
with respect to G&A expenses, we have disaggregated certain costs into three
components as presented in the table below. Primary G&A encompasses all G&A
costs except share-based compensation and certain special charges that are
generally attributable to stand-alone transactions or corporate actions that are
not otherwise in the normal course.
The following table sets forth the components of G&A expenses for the periods
presented:
Year Ended December 31,
2022 2021 Change % Change
Primary G&A expenses $ 33,661 $ 26,753 $ 6,908 26 %
Share-based compensation 1 5,554 15,589 (10,035) (64) %
Special charges:
Organizational restructuring, including severance 2 (1,152) 367 (1,519) (414) %
Acquisition/integration and strategic transaction
costs 2,909 23,820 (20,911) (88) %
Total G&A expenses $ 40,972 $ 66,529 $ (25,557) (38) %
Per unit ($/boe) $ 2.75 $ 6.55 $ (3.80) (58) %
Per unit ($/boe) excluding share-based compensation
and other special charges identified above
(14) %
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1 Share-based compensation for the year ended
2 Organizational restructuring, including severance for the year ended
2022 vs. 2021. Our primary G&A expenses increased on an absolute basis during
2022 compared to 2021. The increase for 2022 compared to 2021 is due primarily
to increased headcount following the Lonestar Acquisition and the impact of
bonuses and salary increases in 2022. Primary G&A expenses decreased on a per
unit basis due to higher overall sales volumes in 2022.
Our total G&A expenses were lower on an absolute and per unit basis during 2022
compared to 2021 due to lower acquisition and integration related costs
associated with the Juniper Transactions and the Lonestar Acquisition and lower
share-based compensation costs as discussed below, partially offset by the
aforementioned increased headcount and salaries.
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, substantially all of the RSUs granted before 2019
vested and an incremental charge of approximately $1.9 million was recorded
during the first quarter 2021. Additionally, as a result of the Lonestar
Acquisition, certain RSUs of Lonestar employees and directors vested at closing
and $10.4 million was recorded as share-based compensation related to these
vestings in the fourth quarter 2021 (see table above). All of our share-based
compensation represents non-cash expenses.
Depreciation, Depletion and Amortization (DD&A)
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 ARO liabilities.
The following table sets forth total and per unit costs for DD&A expense for the
periods presented:
Year Ended December 31,
2022 2021 Change % Change
DD&A expense $ 244,455 $ 131,657 $ 112,798 86 %
DD&A rate ($/boe) $ 16.42 $ 12.96 $ 3.46 27 %
2022 vs. 2021. DD&A expense increased on an absolute and a per unit basis during
2022 when compared to 2021. Higher production volume provided for an increase of
$61.4 million while higher DD&A rates in 2022 provided for an increase of
$51.5 million . The higher DD&A rate in 2022 was primarily due to the Lonestar
Acquisition and other asset acquisitions that closed in 2022, which contributed
to an increase in our total proved reserves at a higher relative cost per boe
coupled with increased future development costs associated with proved reserve
additions as compared to 2021.
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Impairment of
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,
2022 2021 Change % Change
Impairments of oil and gas properties $ -
$ (1,811) (100) % 2022 vs. 2021. We did not record an impairment of our oil and gas properties during 2022 compared to an impairment of$1.8 million recorded in the first quarter 2021. The impairment in 2021 was the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by the respective quarterly Ceiling Test under the full cost method of accounting for oil and gas properties. See Note 7 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for more discussion. Interest Expense Interest expense for 2022 includes charges for outstanding borrowings under the Credit Facility derived from internationally recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. Also included are the amortization of issuance costs capitalized attributable to the Credit Facility and the 9.25% Senior Notes due 2026 and accretion of original issue discount ("OID") on the 9.25% Senior Notes due 2026. Interest expense for the periods in 2021 includes charges for outstanding borrowings under the Credit Facility and the Second Lien Credit Agreement, datedSeptember 29, 2017 (the "Second Lien Term Loan") which was repaid in full inOctober 2021 , as well as amortization of their respective issuance costs capitalized. Also included is the accretion of OID on the Second Lien Term Loan. In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage. The following table summarizes the components of our interest expense for the periods presented: Year Ended December 31, 2022 2021 Change % Change Interest on borrowings and related fees$ 49,729 34,029$ 15,700 46 % Amortization of debt issuance costs 2,861 2,248 613 27 % Accretion of original issue discount 665 487 178 37 % Capitalized interest (4,324) (3,603) (721) 20 % Total interest expense, net of capitalized interest$ 48,931 $ 33,161 $ 15,770 48 % 2022 vs. 2021. The increase in interest expense during 2022 is primarily attributable to interest incurred in the amount of$36.6 million for the 9.25% Senior Notes due 2026 and$11.8 million for the Credit Facility compared to interest incurred in 2021 of$15.0 million for the 9.25% Senior Notes due 2026,$10.6 million for the Second Lien Term Loan and$7.7 million for the Credit Facility as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during 2022, driven by higher overall weighted-average interest rates in 2022 as compared to 2021. 58
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Derivatives
The gains and losses for our derivatives portfolio reflect changes in the fair
value attributable to changes in market values relative to our hedged commodity
prices and interest rates.
The following table summarizes the gains and (losses) attributable to our
commodity derivatives portfolio and interest rate swaps for the periods
presented:
Year Ended December 31,
2022 2021 Change % Change
Commodity derivative losses $ (162,736) $ (136,997) $ (25,739) 19 %
Interest rate swap gains (losses) 64 (2) 66 (3300) %
Total $ (162,672) $ (136,999) $ (25,673) 19 %
2022 vs. 2021. In 2022, commodity prices were significantly higher on an average
aggregate basis than those during 2021. Accordingly, the derivative losses in
2022 and 2021 reflect the decline in the mark-to-market values consistent with
the increase in prices attributable to open positions. Realized settlement
payments, net for crude oil, NGL and natural gas derivatives were $182.0 million
during 2022 as compared to realized settlement payments, net of $77.1 million
during 2021. Through May 2022 , we hedged a portion of our exposure to variable
interest rates associated with our Credit Facility and, during 2021, our Second
Lien Term Loan. As of December 31, 2022 , we did not have any interest rate
derivatives. During 2022 and 2021, we paid $1.4 million and $3.8 million of net
settlements from our interest rate swaps, respectively.
Income Taxes
Income taxes represent our income tax provision as determined in accordance with generally accepted accounting principles. It considers taxes attributable to our obligations for federal taxes under the Internal Revenue Code as well as to the various states in which we operate, primarilyTexas , or otherwise have continuing involvement. The following table summarizes our income tax provision for the periods presented: Year Ended December 31, 2022 2021 Change % Change Income tax expense$ (4,186) $ (1,560) $ (2,626) 168 % Effective tax rate (0.9) % (1.6) % 0.7 % (44) % 2022. The income tax provision for the year endedDecember 31, 2022 includes a deferred state tax expense of$3.4 million attributable to property and equipment and$0.8 million of current state expense attributable to theTexas margin tax for the year endedDecember 31, 2022 . The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.9%, which is fully attributable to theState of Texas . Our net deferred income tax liability balance of$6.2 million as ofDecember 31, 2022 is also fully attributable to theState of Texas and primarily related to property. 2021. The income tax provision for the year endedDecember 31, 2021 includes a deferred state tax expense of$1.2 million attributable to property and equipment and$0.3 million of current state expense attributable to theTexas margin tax for the year endedDecember 31, 2021 . 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 1.6%, which was fully attributable to theState of Texas . 59
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Liquidity 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 ofDecember 31, 2022 , we had liquidity of$291.6 million , comprised of cash and cash equivalents of$7.6 million and availability under our Credit Facility of$284.0 million (factoring in letters of credit). The Credit Facility provides us up to$1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is$950 million with aggregate elected commitments of$500 million . Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGLs and natural gas, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been impacted by the volatility and uncertainty in the global economic markets stemming from the COVID-19 pandemic and subsequent recovery, theRussia -Ukraine war, OPEC+ production decisions and related instability in the global energy markets, as well as inflationary pressures and recession fears that impact demand. In order to mitigate this volatility, we utilize derivative contracts with a number of financial institutions, all of which are participants in our Credit Facility, hedging a portion of our estimated future crude oil, NGLs and natural gas production through the first half of 2024. The level of our hedging activity and duration of the financial instruments employed depends on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy. From time to time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities. We maintain an effective shelf registration statement to allow for optionality. Capital Resources 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 continued volatility and related instability in the global energy markets. We plan to fund our 2023 capital expenditures and our operations primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. 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 9 and Note 14 to the consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for more details related to these obligations. The Partnership is also required in certain circumstances to make certain tax distributions to its partners, which may impact cash flow from operations for the Company, as discussed below under "Tax Distributions."
Dividends
OnJuly 7, 2022 , the Company's Board of Directors declared an inaugural cash dividend of$0.075 per share of Class A Common Stock and onNovember 2, 2022 , a second cash dividend was declared of$0.075 per share of Class A Common Stock. The related dividends were paid onAugust 4, 2022 andNovember 28, 2022 to holders of record of Class A Common Stock as of the close of business onJuly 25, 2022 andNovember 16, 2022 , respectively. In connection with any dividend, Ranger's operating subsidiary will also make a corresponding distribution to its common unitholders. During 2022, the dividends to the holders of our Class A Common Stock and distribution to common unitholders totaled$6.3 million in the aggregate. Additionally, onMarch 3, 2023 , the Company's Board of Directors declared a cash dividend of$0.075 per share of Class A Common Stock payable onMarch 30, 2023 to holders of record of Class A Common Stock as of the close of business onMarch 17, 2023 . We expect to fund dividends and distributions from available working capital and cash provided by operating activities. 60
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Share Repurchase Program
InApril 2022 , we announced that the Board of Directors approved a share repurchase program under which we were authorized to repurchase up to$100 million of outstanding Class A Common Stock throughMarch 31, 2023 . Subsequently onJuly 7, 2022 , the Board of Directors authorized an increase in the share repurchase program from$100 million to$140 million and extended the term of the program throughJune 30, 2023 . We do not intend to repurchase additional shares pending closing of the Baytex Merger.
Subsequent to
OnAugust 16, 2022 , the Inflation Reduction Act was signed into law and imposes a 1% excise tax on the repurchase of stock by publicly tradedU.S. corporations. The excise tax is effective for stock repurchases afterDecember 31, 2022 . We are currently evaluating the impacts, if any, of this provision to our results of operations and cash flows. Tax Distributions Under its Partnership Agreement, the Partnership is required to make distributions to all of its limited partners pro rata on a quarterly basis and in such amounts as necessary to enable the Company to timely satisfy all of itsU.S. federal, state and local and non-U.S. tax liabilities. Additionally, the Partnership is required to make advances to its non-corporate partners in an amount sufficient to enable such partner to timely satisfy itsU.S. federal, state and local and non-U.S. tax liabilities (a "Tax Advance"). Any such Tax Advance will be treated as an advance against and, therefore, reduce any future distributions that such partner is otherwise entitled to receive. The Company's cash flow from operations and ability to pay cash dividends to our stockholders could be adversely impacted as a result of such cash distributions. Whether and how much Tax Advances are required to be paid is dependent upon the amount and timing of taxable income generated in the future that is allocable to partners and the federal tax rates then applicable. The Partnership was not required to make Tax Advances for the year endedDecember 31, 2022 . At this time we are unable to assess whether the Partnership will be required to make Tax Advances for the year endingDecember 31, 2023 or in future years.
Cash Flows
The following table summarizes our cash flows for the periods presented:
Year Ended
2022 2021
Net cash provided by operating activities 675,430 289,025
Net cash used in investing activities (606,598) (245,174)
Net cash used in financing activities (84,921) (33,190)
Net increase (decrease) in cash and cash equivalents $ (16,089) $ 10,661
Cash Flows from Operating Activities. The increase of $386.4 million in net cash
from operating activities for 2022 compared to 2021 was primarily attributable
to the effect of 2022 cash receipts that were derived from higher average prices
and higher total sales volume, partially offset by higher net payments for
commodity derivatives settlements and premiums. Additionally, during 2021, there
were higher acquisition, integration and strategic transaction costs and
executive restructuring costs, including severance payments.
Cash Flows from Investing Activities. Our cash payments for capital expenditures
were higher during 2022 compared to 2021 due primarily to significantly
increased development program in 2022 along with higher drilling and completion
costs associated with inflation. Additionally, our cash flow from investing
activities was impacted by cash paid for oil and gas property acquisitions which
closed in 2022.
The following table sets forth costs related to our capital expenditure program
for the periods presented:
Year Ended December 31,
2022 2021
Drilling and completion $ 513,943 $ 263,936 Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs
7,188 3,773
Pipeline, gathering facilities and other equipment, net 1 3,440 (1,252)
Total capital expenditures incurred $ 524,571 $ 266,457 __________________________________________________________________________________
1 Includes certain capital charges to our working interest partners for completion services.
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The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures as reported in our consolidated statements of cash flows for the periods presented:
Year Ended
2022 2021
Total capital expenditures program costs (from above) $ 524,571 $ 266,457 Increase in accounts payable for capital items and accrued capitalized costs
(46,616) (16,726)
Net purchases of tubular inventory and well materials 1 3,043 3,388
Prepayments for drilling and completion services, net of (transfers) (9,125)
(4,018)
Capitalized internal labor, capitalized interest and other 9,613 7,242
Total cash paid for capital expenditures $ 481,486 $ 256,343 __________________________________________________________________________________
1 Includes purchases made in advance of drilling.
Cash Flows from Financing Activities. During 2022, we had borrowings of$610.0 million and repayments of$603.0 million under the Credit Facility and$75.2 million of share repurchases. During 2021, we received net proceeds of$396.1 million from the offering of the 9.25% Senior Notes due 2026 and$151.2 million from the issuance of equity in connection with the Juniper Transactions (See Note 4 to our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information). The proceeds from these transactions were primarily used to: (i) repay and discharge$249.6 million of Lonestar's outstanding long-term debt in connection with the Lonestar Acquisition, (ii) repay the$200 million Second Lien Term Loan, (iii) repay$80.5 million under the Credit Facility, and (iv) pay$9.3 million of transaction and issue costs related to the Juniper Transactions. Additionally, during 2021, we had borrowings of$70.0 million and additional repayments of$95.9 million under the Credit Facility and paid$14.4 million in debt issuance costs.
Capitalization
The following table summarizes our total capitalization as of the dates presented:
December 31,
2022 2021
Credit Facility borrowings $ 215,000 $ 208,000
9.25% Senior Notes due 2026, net 388,839 386,427
Mortgage debt 1 - 8,438
Other 2 238 2,516
Total debt, net 604,077 605,381
Total equity 1,057,022 669,508
Total capitalization $ 1,661,099 $1,274,889
Debt as a % of total capitalization 36 % 47 %
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1 The mortgage debt atDecember 31, 2021 related to the corporate office building and related other assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. As ofDecember 31, 2021 , these assets were classified as Assets held for sale on the consolidated balance sheets in our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data." InJuly 2022 , the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 4 to our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" for additional information on the sale. 2 Other debt of$2.2 million atDecember 31, 2021 was extinguished during 2022 and recorded as a gain on extinguishment of debt on the consolidated statements of operations in our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data.". Credit Facility. As ofDecember 31, 2022 , the Credit Facility had a$1.0 billion revolving commitment and a$950 million borrowing base, with aggregate elected commitments of$500 million and a$25 million sublimit for the issuance of letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes including working capital. We had$1.0 million and$0.9 million in letters of credit outstanding as ofDecember 31, 2022 and 2021, respectively. The maturity date under the Credit Facility isOctober 6, 2025 . 62
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The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) effectiveJune 1, 2022 , a term Secured Overnight Financing Rate ("SOFR") reference rate (a Eurodollar rate, including LIBOR prior toJune 1, 2022 ), plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on SOFR borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. AtDecember 31, 2022 , the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 7.25%. Unused commitment fees are charged at a rate of 0.50%. The following table summarizes our borrowing activity under the Credit Facility for the periods presented: Borrowings Outstanding Weighted- Weighted- End of Period Average Maximum Average Rate Three months ended December 31, 2022$ 215,000 $ 260,978 $ 292,000 6.91 % Year ended December 31, 2022$ 215,000 $ 219,345 $ 301,000 5.25 % The Credit Facility is guaranteed by all of the subsidiaries of the borrower (the "Guarantor Subsidiaries"), except forBoland Building, LLC . The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on the ability of the borrower or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries' assets. 9.25% Senior Notes due 2026. OnAugust 10, 2021 , our indirect, wholly-owned subsidiary completed an offering of$400 million aggregate principal amount of senior unsecured notes due 2026 (the "9.25% Senior Notes due 2026") that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed byROCC Holdings, LLC (formerly,Penn Virginia Holdings, LLC , hereinafter referred to as "Holdings"), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility. Covenant Compliance. The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset) of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00. The Credit Facility and the Indenture contain customary affirmative and negative covenants as well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.
As of
See Note 9 to the consolidated financial statements included in Part II, Item 8,
"Financial Statements and Supplementary Data" for additional information on our
debt.
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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.
Leases
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.
Gathering and Intermediate Transportation Commitments
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 asset retirement obligations ("AROs") that primarily relate to the
plugging and abandonment of oil and gas wells. For information on our AROs, see
Note 8 and Note 14 to the consolidated financial statements included in Part II,
Item 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.
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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. We had no impairments of our proved oil and gas properties during 2022. 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 million impairment. 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 million of impairment charges recorded for the year endedDecember 31, 2020 .
Derivative Activities
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, at times, 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.
Deferred Tax Asset Valuation Allowance
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 ofDecember 31, 2022 , 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.
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