CONTINENTAL RESOURCES, INC Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-K)
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes included elsewhere in this report. Results attributable to noncontrolling interests are not material relative to consolidated results and are not separately presented or discussed below. The following discussion and analysis includes forward-looking statements and should be read in conjunction with Part I, Item 1A. Risk Factors in this report, along with Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements. Overview We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products. Additionally, we pursue the acquisition and management of perpetually owned minerals located in our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. We are the largest leaseholder and the largest producer in the Bakken field ofNorth Dakota andMontana . We also have significant positions in the SCOOP and STACK plays inOklahoma and recently acquired positions in thePermian Basin ofTexas andPowder River Basin ofWyoming . Our common stock trades on theNew York Stock Exchange under the symbol "CLR" and our corporate internet website is www.clr.com. 2021 Highlights Financial and operating highlights for 2021 are summarized below. Our 2021 results underscore our continued focus on maximizing cash flow generation, maintaining low-cost capital efficient operations in an environmentally responsible manner, achieving consistent asset performance, and delivering capital and corporate returns to shareholders. •Generated$1.25 billion in operating cash flows in the fourth quarter, bringing year-to-date operating cash flows to a Company record$3.97 billion ; •Completed strategic acquisitions to expand our operations into thePermian Basin for cash consideration of$3.06 billion and thePowder River Basin for cash consideration totaling$453 million ; •Sequentially increased our quarterly fixed dividend throughout year, paying$166 million of dividends in 2021 with an additional$82 million of declared dividends to be paid in the first quarter of 2022; •Repurchased 3.2 million shares of common stock in 2021 under our share repurchase program at an aggregate cost of$124 million ; and •Continued to maintain low cost operations with production expenses averaging$3.38 per Boe for 2021. With our acquisitions in thePermian Basin andPowder River Basin in 2021 we now have substantial strategic positions in four leading basins inthe United States , providing our Company and shareholders with enhanced geologic and geographic diversity and commodity optionality. We believe these transactions will be accretive on financial metrics and will complement our existing deep portfolio of assets in the Bakken andOklahoma . We expect enhanced cash flows from the acquisitions will provide continued support for additional returns to shareholders via debt reduction, dividend increases, share repurchases, and increased returns on capital employed. See Part I, Item 1. Business-Acquisition Activities and Part II, Item 8. Notes to Consolidated Financial Statements-Note 2. Property Acquisitions and Dispositions for additional information on the acquisitions. Financial and Operating Metrics Our operating results for 2020 were severely impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices. In response to the significant reduction in crude oil prices during 2020, we curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter and significantly reduced our capital spending. InJuly 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online inSeptember 2020 . These actions resulted in material reductions in our production, revenues, and cash flows for 2020. Crude oil and natural gas prices have increased significantly in 2021 compared to 2020 levels in response to the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals. The increase in commodity prices and resumption of our operations resulted in significantly improved operating results in 2021 compared to 2020 as further described below. 43 -------------------------------------------------------------------------------- The following table contains financial and operating highlights for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes. The previously describedPermian Basin acquisition closed onDecember 21, 2021 and thus had a limited impact on fourth quarter and full year 2021 operating results given our short duration of ownership. The acquired Permian assets contributed 460 MBoe of production (42,000 Boe per day on average of which 78% was oil),$29.4 million of revenues, and$14.1 million ($0.04 per basic and diluted share) of net income to our consolidated results during the period of ownership fromDecember 21, 2021 toDecember 31, 2021 . Year ended December 31, 2021 2020 2019 Average daily production: Crude oil (Bbl per day) 160,647 160,505 197,991 Natural gas (Mcf per day) 1,014,000 837,509 854,424 Crude oil equivalents (Boe per day) 329,647 300,090 340,395 Average net sales prices: (1) Crude oil ($/Bbl)$ 64.06 $ 34.71 $ 51.82 Natural gas ($/Mcf)$ 4.88 $ 1.04 $ 1.77 Crude oil equivalents ($/Boe)$ 46.24 $ 21.47 $ 34.56 Crude oil net sales price discount to NYMEX ($/Bbl)$ (4.00)
Premium (rebate) on the net selling price of natural gas on NYMEX ($/MMcf)
$ 1.00 $ (1.10) $ (0.86) Production expenses ($/Boe)$ 3.38
Production taxes (% of net sales of crude oil and natural gas)
7.3 % 8.2 % 8.3 % DD&A ($/Boe)$ 15.76 $ 17.12 $ 16.25 Total general and administrative expenses ($/Boe)$ 1.94
(1) See the subsequent section titled Non-GAAP Financial Measures for a
discussion and calculation of net sales prices, which are non-GAAP measures.
Results of Operations
The following table presents selected financial and operating information for
the periods presented.
44
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Year Ended December 31,
In thousands, except sales price data 2021 2020 2019
Crude oil and natural gas sales $ 5,793,741 $ 2,555,434 $ 4,514,389
Gain (loss) on derivative instruments, net (128,864) (14,658) 49,083
Crude oil and natural gas service operations 54,441 45,694 68,475
Total revenues 5,719,318 2,586,470 4,631,947
Operating costs and expenses (3,257,638) (3,140,362) (3,374,535)
Other expenses, net (275,542) (220,859) (270,250)
Income (loss) before income taxes 2,186,138 (774,751) 987,162
(Provision) benefit for income taxes (519,730) 169,190 (212,689)
Net income (loss) 1,666,408 (605,561) 774,473
Net income (loss) attributable to noncontrolling
interests 5,440 (8,692) (1,168)
Net income (loss) attributable to Continental
Resources $ 1,660,968 $ (596,869) $ 775,641
Diluted net income (loss) per share attributable to
Continental Resources $ 4.56 $ (1.65) $ 2.08
Production volumes:
Crude oil (MBbl) 58,636 58,745 72,267
Natural gas (MMcf) 370,110 306,528 311,865
Crude oil equivalents (MBoe) 120,321 109,833 124,244
Sales volumes:
Crude oil (MBbl) 58,757 58,793 72,136
Natural gas (MMcf) 370,110 306,528 311,865
Crude oil equivalents (MBoe) 120,442 109,881 124,113
Year ended December 31, 2021 compared to the year ended December 31, 2020
Below is a discussion of changes in our results of operations for 2021 compared
to 2020. A discussion of changes in our results of operations for 2020 compared
to 2019 has been omitted from this Form 10-K, but may be found in Part II, Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations of our Form 10-K for the year ended December 31, 2020 as filed with
the SEC on February 16, 2021 .
Production
The following table summarizes the changes in our average daily Boe production
by major operating area for the periods presented.
Fourth Quarter Year Ended December 31,
Boe production per day 2021 2020 % Change 2021 2020 % Change
Bakken 175,585 183,141 (4 %) 169,636 158,604 7 %
Oklahoma 146,131 149,341 (2 %) 147,249 134,506 9 %
Powder River Basin 7,189 - - % 5,161 - - %
Permian Basin (1) 4,997 - - % 1,260 - - %
All other 6,266
6,825 (8 %) 6,341 6,980 (9 %) Total 340,168 339,307 - % 329,647 300,090 10 % (1)The presentation of average daily production represents production during the period from the closing of our acquisition of Permian properties onDecember 21, 2021 throughDecember 31, 2021 averaged over the respective fourth quarter and full year periods. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day based on two-stream reporting. The following tables reflect our production by product and region for the periods presented. 45 --------------------------------------------------------------------------------
Year Ended December 31, Volume
2021 2020 Volume increase percent increase
Volume Percent Volume Percent (decrease) (decrease)
Crude oil (MBbl) 58,636 49 % 58,745 53 % (109) - %
Natural gas (MMcf) 370,110 51 % 306,528 47 % 63,582 21 %
Total (MBoe) 120,321 100 % 109,833 100 % 10,488 10 %
Year Ended December 31, Volume
2021 2020 percent
MBoe Percent MBoe
Percent Volume increase increase North Region 66,105 55 % 60,591 55 % 5,514 9 % South Region 54,216 45 % 49,242 45 % 4,974 10 % Total 120,321 100 % 109,833 100 % 10,488 10 % Over the past year we increased our allocation of capital to gas-weighted projects to capitalize on improvements in market prices for natural gas and natural gas liquids. These actions contributed to an increase in our natural gas production as a percentage of total production and led to a 21% increase in natural gas production in 2021 compared to 2020. Natural gas production inOklahoma increased 37,345 MMcf, or 18%, and natural gas production in the Bakken increased 23,122 MMcf, or 23%, over the prior year. Additionally, properties acquired in thePowder River Basin in March andNovember 2021 added 2,517 MMcf to our natural gas production, while properties acquired in thePermian Basin added 614 MMcf during the short duration of our ownership of the properties in late 2021. Our crude oil production was flat in 2021 compared to 2020 resulting from our change in allocation of capital from oil-weighted projects to gas-weighted projects over the past year and the timing of well completions. Crude oil production in the Bakken was flat between years, while oil production inOklahoma decreased 1,708 MBbls, or 12%, compared to 2020. This decrease was offset by new production added from our 2021 acquisitions. Properties acquired in thePowder River Basin in March andNovember 2021 added 1,464 MBbls to our crude oil production, while properties acquired in thePermian Basin added 357 MBbls during the short duration of our ownership of the properties in late 2021. Revenues Our revenues consist of sales of crude oil and natural gas, gains and losses resulting from changes in the fair value of our derivative instruments, and revenues associated with crude oil and natural gas service operations. Net crude oil and natural gas sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for discussion and calculation of these measures. Net crude oil and natural gas sales. Net crude oil and natural gas sales for 2021 totaled$5.57 billion , a 136% increase compared to net sales of$2.36 billion for 2020 due to significant increases in net sales prices and natural gas sales volumes as discussed below. Total sales volumes for 2021 increased 10,561 MBoe, or 10%, compared to 2020, reflecting reduced sales in the prior period from the previously described production curtailments in the second and third quarters of 2020 and our subsequent resumption of usual operations. For 2021, our crude oil sales volumes were flat compared to 2020, while our natural gas sales volumes increased 21% driven by our increased allocation of capital toward gas-weighted projects over the past year. Our crude oil net sales prices averaged$64.06 per barrel for 2021, an increase of 85% compared to$34.71 per barrel for 2020 due to a significant increase in market prices driven by improved supply and demand fundamentals along with improved price differentials. The differential between NYMEX West Texas Intermediate calendar month crude oil prices and our realized crude oil net sales prices averaged$4.00 per barrel in 2021 compared to$5.80 per barrel in 2020. Crude oil prices for 2020 were severely impacted by adverse changes in supply and demand fundamentals from the economic effects of the COVID-19 pandemic, which negatively impacted location differentials and price realizations in the 2020 period with no similar impacts in 2021. Our natural gas net sales prices averaged$4.88 per Mcf for 2021 compared to$1.04 per Mcf for 2020 due to a significant increase in market prices and improved price differentials. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a premium of$1.00 per Mcf for 2021 compared to a discount of$1.10 per Mcf for 2020. 46 -------------------------------------------------------------------------------- InFebruary 2021 , severe winter weather and freezing temperatures in the southernUnited States led to a period of increased spot prices for residue natural gas that resulted in a significant improvement in our price realizations in the 2021 first quarter compared to the prior year. Additionally, prices for natural gas liquids have increased significantly in 2021 compared to 2020 levels in conjunction with increased crude oil prices and other factors, resulting in improved price realizations for our natural gas sales stream. For the fourth quarter of 2021, the difference between our net sales prices and NYMEX Henry Hub prices was a premium of$0.49 per Mcf. Derivatives. The significant improvement in commodity prices in 2021 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of$128.9 million for the year, representing$149.7 million of cash losses partially offset by$20.8 million of unsettled non-cash gains. For 2020, we recognized negative revenue adjustments of$14.7 million resulting from changes in market prices that had an unfavorable impact on the fair value of our derivatives. Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities increased$8.7 million , or 19%, from$45.7 million for 2020 to$54.4 million for 2021 due to increased water handling activities resulting from increases in completion activities and production volumes compared to 2020. Operating Costs and Expenses Production expenses. Production expenses increased$47.6 million , or 13%, to$406.9 million for 2021 compared to$359.3 million for 2020 primarily due to the previously described 10% increase in total sales volumes. Production expenses on a per-Boe basis averaged$3.38 per Boe for 2021, consistent with$3.27 per Boe for 2020. Production taxes. Production taxes increased$211.6 million , or 110%, to$404.4 million for 2021 compared to$192.7 million for 2020 due to the previously described increase in crude oil and natural gas sales partially offset by a decrease in our average production tax rate. Our production taxes as a percentage of net crude oil and natural gas sales decreased to 7.3% for 2021 compared to 8.2% for 2020 primarily resulting from an increase in the proportion of our revenues being generated inOklahoma in the current period, which has lower production tax rates compared toNorth Dakota . Depreciation, depletion, amortization and accretion ("DD&A"). Total DD&A amounted to$1.90 billion for 2021, consistent with$1.88 billion for 2020, reflecting a 10% increase in total sales volumes the impact of which was nearly offset by a decrease in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented. Year ended December 31, $/Boe 2021 2020 Crude oil and natural gas properties$ 15.45 $ 16.84 Other equipment 0.22 0.19 Asset retirement obligation accretion 0.09 0.09
Depreciation, depletion, amortization and accretion
Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required bySEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases. Our proved reserves were revised upward in 2021 prompted by significant increases in first-day-of-the-month commodity prices and other factors, which resulted in a decrease in our DD&A rate for crude oil and natural gas properties in the current period. As a result of these upward revisions, our DD&A rate decreased to$14.34 per Boe for the 2021 fourth quarter compared to$19.01 per Boe for the 2020 fourth quarter, the impact of which helped offset higher DD&A recognized in 2021 from increased sales volumes. NYMEX WTI crude oil andHenry Hub natural gas first-day-of-the-month commodity prices forJanuary 1, 2022 andFebruary 1, 2022 averaged$81.71 per barrel and$4.65 per MMBtu, respectively, which are notably higher than average prices in 2021. If commodity prices remain at current levels for an extended period, additional upward price-related revisions of proved reserves may occur in the future, which may be significant and could result in a further decrease in our DD&A rate relative to the 2021 fourth quarter. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on our future DD&A rate. 47 -------------------------------------------------------------------------------- Property impairments. Property impairments decreased$239.6 million to$38.4 million for 2021 compared to$277.9 million for 2020, primarily reflecting lower proved property impairments in the current period. No proved property impairments were recognized in 2021 as estimated future net cash flows were determined to be in excess of cost basis due to improved commodity prices, while proved property impairments totaled$207.1 million in 2020. Additionally, impairments of unproved properties decreased$32.5 million in 2021 compared to 2020 reflecting a decrease in the amortization of undeveloped leasehold costs from changes in management's estimates of properties not expected to be developed before lease expiration in response to significantly improved commodity prices compared to the prior year. Our unamortized balance of unproved properties increased significantly in late 2021 in connection with our 2021 fourth quarter property acquisitions and now totals$1.36 billion atDecember 31, 2021 . Accordingly, our amortized impairments of unproved property costs are expected to increase in 2022 relative to 2021 levels, the amount of which is uncertain. General and administrative ("G&A") expenses. G&A expenses increased$37.0 million , or 19%, to$233.6 million for 2021 compared to$196.6 million for 2020. Total G&A expenses include non-cash charges for equity compensation of$63.2 million and$64.6 million for 2021 and 2020, respectively. G&A expenses other than equity compensation totaled$170.4 million for 2021, an increase of$38.4 million , or 29%, compared to$132.0 million for 2020 due to an increase in employee benefits partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to 2020. The following table shows the components of G&A expenses on a unit of sales basis for the periods presented. Year ended December
31,
$/Boe 2021
2020
General and administrative expenses$ 1.42 $ 1.20 Non-cash equity compensation 0.52
0.59
Total general and administrative expenses$ 1.94
Acquisition costs. We incurred$13.9 million of expenses in connection with ourDecember 2021 acquisition of properties in thePermian Basin , which are reflected in the caption "Acquisition costs" in the consolidated statements of comprehensive income (loss) for 2021. Interest expense. Interest expense decreased$6.6 million , or 3%, to$251.6 million for 2021 compared to$258.2 million for 2020 due to a decrease in our annual weighted average outstanding debt from$5.8 billion in 2020 to$5.6 billion in 2021. Our outstanding debt totaled$6.8 billion atDecember 31, 2021 , reflecting an increase of$2.1 billion in the 2021 fourth quarter due to credit facility and senior note borrowings incurred to fund a portion of ourDecember 2021 acquisition of properties in thePermian Basin . Gain (loss) on extinguishment of debt. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 8. Long-Term Debt for discussion of gains and losses recognized on debt extinguishments in 2021 and 2020. Other non-operating expense. As discussed in Part II, Item 8. Notes to Consolidated Financial Statements-Note 13. Commitments and Contingencies-Pledge commitment, we recognized a$25.0 million charge to earnings upon execution of an irrevocable ten-year pledge commitment inDecember 2021 , which is reflected in the caption "Other income (expense)-Other" in the consolidated statements of comprehensive income (loss) for 2021. Income Taxes. For 2021 and 2020 we provided for income taxes at a combined federal and state tax rate of 24.5% of pre-tax income/loss. We recorded an income tax provision of$519.7 million and an income tax benefit of$169.2 million for 2021 and 2020, respectively, which resulted in effective tax rates of 23.8% and 21.8%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in valuation allowances, and other items. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 11. Income Taxes for a summary of the sources and tax effects of items comprising our income tax provision and resulting effective tax rates for 2021 and 2020. Liquidity and Capital Resources Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity. We are committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet. 48 -------------------------------------------------------------------------------- AtJanuary 31, 2022 , we had approximately$1.76 billion of borrowing availability under our credit facility after considering outstanding borrowings and letters of credit, which represents a$260 million increase in availability compared to year-end 2021. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature untilOctober 2026 . Based on our planned capital spending, including our pending property acquisition described below, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations. Cash Flows Cash flows from operating activities Net cash provided by operating activities increased$2.55 billion , or 179%, to$3.97 billion for 2021 compared to$1.42 billion for 2020 primarily due to a$3.24 billion increase in crude oil and natural gas revenues due to the previously described increases in commodity prices and natural gas sales volumes in the current period. This increase was partially offset by a$211.6 million increase in production taxes associated with higher crude oil and natural gas revenues and a$121.5 million increase in realized cash losses on matured commodity derivatives in the current period. Additionally, we experienced an increase in certain cash operating expenses primarily due to an increase in total sales volumes, which included a$47.6 million increase in production expenses and a$28.3 million increase in transportation expenses. Cash flows used in investing activities Net cash used in investing activities totaled$4.99 billion and$1.51 billion for 2021 and 2020, respectively, the$3.48 billion increase of which reflects our 2021 property acquisition activities discussed in Part II, Item 8. Notes to Consolidated Financial Statements-Note 2. Property Acquisitions and Dispositions. Cash flows from financing activities Net cash provided by financing activities for 2021 totaled$989.1 million , primarily consisting of$1.59 billion of net proceeds received from ourNovember 2021 issuances of senior notes and$340 million of net credit facility borrowings incurred to fund a portion of ourDecember 2021 Permian Basin acquisition. These increases were partially offset by$630.8 million of senior note redemptions during the year,$123.9 million of cash used to repurchase shares of our common stock, and$165.9 million of cash dividends paid on common stock. Net cash provided by financing activities for 2020 totaled$97.1 million , primarily resulting from$1.48 billion of net proceeds received from ourNovember 2020 issuance of senior notes due 2031,$105.0 million of net credit facility borrowings, and net proceeds of$26.0 million from term loans executed during 2020. These increases were partially offset by$1.34 billion of senior note repurchases and redemptions during 2020 using available cash and proceeds from our issuance of 2031 Notes,$25.2 million of premiums and costs paid upon the redemptions and repurchases,$126.9 million of cash used to repurchase shares of our common stock, and$18.5 million of cash dividends paid on common stock. Future Sources of Financing Although we cannot provide any assurance, we believe funds from operating cash flows, our cash balance, and availability under our credit facility should be sufficient to meet our normal operating needs, debt service obligations, budgeted capital expenditures, the pending property acquisition described below, cash payments for income taxes, and dividend payments for at least the next 12 months and to meet our contractual cash commitments to third parties described under the heading Future Capital Requirements beyond 12 months. Based on current market indications, our budgeted capital spending plans for 2022 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations and business plans. We may choose to access banking or capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur. 49 -------------------------------------------------------------------------------- Credit facility We have an unsecured credit facility, maturing inOctober 2026 , with aggregate lender commitments totaling$2.0 billion . The commitments are from a syndicate of 12 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As ofJanuary 31, 2022 , we had$1.76 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances. Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 8. Long-Term Debt for a discussion of how this ratio is calculated pursuant to our credit agreement. We were in compliance with our credit facility covenants atDecember 31, 2021 and expect to maintain compliance. AtDecember 31, 2021 , our consolidated net debt to total capitalization ratio was 0.43. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business. Future Capital Requirements Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as ofDecember 31, 2021 , recognizing we may be required to meet such commitments even if our business plan assumptions were to change. Senior notes Our debt includes outstanding senior note obligations totaling$6.36 billion atDecember 31, 2021 , exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our$649.6 million of 2023 Notes due inApril 2023 . For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated Financial Statements. We were in compliance with our senior note covenants atDecember 31, 2021 and expect to maintain compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants. Credit facility borrowings As ofJanuary 31, 2022 , we had$240 million of outstanding borrowings on our credit facility, which represents a decrease of$260 million compared to$500 million outstanding at year-end 2021. Our credit facility matures inOctober 2026 . Transportation, gathering, and processing commitments We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as ofDecember 31, 2021 under the arrangements amount to approximately$1.31 billion . See Part II, Item 8. Notes to Consolidated Financial Statements-Note 13. Commitments and Contingencies for additional information. Capital Expenditures 2021 Capital Spending For the year endedDecember 31, 2021 , we invested$1.54 billion in our capital program excluding$3.58 billion of unbudgeted acquisitions, excluding$21.3 million of mineral acquisitions attributable to Franco-Nevada, and including$114.1 million of capital costs associated with increased accruals for capital expenditures as compared toDecember 31, 2020 . Our 2021 capital 50 -------------------------------------------------------------------------------- expenditures were allocated as follows by quarter. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 2. Property Acquisitions and Dispositions for discussion of our notable property acquisitions executed in 2021. In millions 1Q 2021 2Q 2021 3Q 2021 4Q 2021 Total 2021 Exploration and development drilling$ 255.6 $ 216.2 $ 312.3 $ 382.6 $ 1,166.7 Land costs 7.5 14.5 18.5 111.1 151.6 Mineral acquisitions attributable to Continental 0.2 1.3 1.5 2.9 5.9 Capital facilities, workovers, water infrastructure, and other corporate assets 27.4 57.3 51.0 68.4 204.1 Seismic 2.7 0.2 0.4 9.2 12.5 Capital expenditures attributable to Continental, excluding unbudgeted acquisitions$ 293.4 $ 289.5 $ 383.7 $ 574.2 $ 1,540.8 Acquisitions of producing properties (1) 183.3 (5.4) 0.3 2,390.3 2,568.5 Acquisitions of non-producing properties (1) 24.3 18.7 3.0 967.5 1,013.5 Total unbudgeted acquisitions 207.6 13.3 3.3 3,357.8 3,582.0 Total capital expenditures attributable to Continental 501.0 302.8 387.0 3,932.0 5,122.8 Mineral acquisitions attributable to Franco-Nevada 0.9 2.8 6.0 11.6 21.3 Total capital expenditures 501.9 305.6
393.0 3,943.6 5,144.1
(1) Fourth quarter amounts primarily represent ourDecember 2021 Permian Basin acquisition. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 2. Property Acquisitions and Dispositions for additional information. 2022 Capital Budget In 2022, we will remain committed to operating in a disciplined, capital-efficient manner to maximize cash flow generation and capital and corporate returns to shareholders. Our 2022 capital budget is expected to be allocated as reflected in the table below. Acquisition expenditures are not budgeted, with the exception of planned levels of spending for mineral acquisitions made in conjunction with our relationship with Franco-Nevada. In millions 2022 Budget Exploration and development $ 1,800 Land costs 127 Mineral acquisitions attributable to Continental (1) 23
Fixed assets, refurbishments, hydraulic infrastructures and other company assets
344 Seismic 6 2022 capital budget attributable to Continental $ 2,300 Mineral acquisitions attributable to Franco-Nevada (1) 91 Total 2022 capital budget (2) $ 2,391 (1) Represents planned spending for mineral acquisitions by TMRC II under our relationship with Franco-Nevada Corporation. Continental holds a controlling financial interest in TMRC II and therefore consolidates the financial results and capital expenditures of the entity. With a carry structure in place, Continental will fund 20% of 2022 planned spending, or$23 million , and Franco-Nevada will fund the remaining 80%, or$91 million . (2) Excludes the$450 million purchase price for our pending acquisition of properties in thePowder River Basin discussed below under the caption Pending Property Acquisition. Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices materially decrease from current levels. 51 -------------------------------------------------------------------------------- Pending Property Acquisition As discussed in Note 20. Subsequent Events in Part II, Item 8. Notes to Consolidated Financial Statements, onJanuary 24, 2022 , we executed a definitive agreement to acquire oil and gas properties in thePowder River Basin for$450 million of cash, subject to customary closing price adjustments. The properties include approximately 172,000 net leasehold acres and producing properties with production totaling approximately 16,000 barrels of oil equivalent per day based on two-stream reporting. Closing of the acquisition is expected to occur in lateMarch 2022 and remains subject to the completion of customary due diligence procedures and closing conditions. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at attractive terms. Cash Payments for Income Taxes As ofFebruary 10, 2022 , the publicly available forward commodity strip prices for the remainder of 2022 averaged$83.38 per barrel for crude oil and$4.09 per Mcf for natural gas. If commodity prices remain at these levels for the year, we could potentially utilize the full amount of our federal net operating loss carryforwards and certain state net operating loss carryforwards and generate significant taxable income in 2022, which could result in us making cash payments for income taxes in the upcoming year. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, including future commodity prices, production levels, development activities, capital spending, profitability, and general economic conditions, we cannot predict the amount of future income tax payments with certainty, but such payments could be significant. Dividend Declaration OnFebruary 9, 2022 , the Company declared a quarterly cash dividend of$0.23 per share on its outstanding common stock, which will be paid onMarch 4, 2022 to shareholders of record as ofFebruary 22, 2022 . Delivery Commitments We have various natural gas volume delivery commitments that are related to our North and South areas. We expect to primarily fulfill our contractual obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. The volumes disclosed herein represent gross production associated with properties operated by us and do not reflect our net proportionate share of such amounts. Additionally, in the South region certain of our firm sales contracts for oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual obligations with production from our proved reserves. As ofDecember 31, 2021 , we were committed to deliver the following fixed quantities of natural gas production. Year Ending Natural Gas Crude Oil December 31, Bcf MMBo 2022 146 13 2023 84 13 2024 73 3 2025 18 - 2026 15 - Derivative Instruments See Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated Financial Statements for discussion of our hedging activities, including a summary of derivative contracts in place as ofDecember 31, 2021 . BetweenJanuary 1, 2022 andFebruary 10, 2022 we entered into additional derivative instruments as summarized in the tables below. 52 --------------------------------------------------------------------------------
Natural gas derivatives
Weighted Average Hedge Price ($/MMBtu) Period and Type of Contract Average Volumes Hedged Swaps Floor CeilingApril 2022 -September 2022 Swaps - Henry Hub 200,000 MMBtus/day $ 4.03 April 2022 -September 2022 Collars - Henry Hub 110,000 MMBtus/day$ 4.50 $ 6.00 July 2022 -December 2022 Swaps - WAHA 45,000 MMBtus/day $ 3.41 October 2022 -March 2023 Collars - Henry Hub 210,000 MMBtus/day$ 4.12 $ 5.52 January 2023 -December 2023 Swaps - WAHA 40,000 MMBtus/day $ 2.69 April 2023 -September 2023 Swaps - Henry Hub 100,000 MMBtus/day $ 3.25 October 2023 -March 2024 Collars - Henry Hub 100,000 MMBtus/day$ 3.14 $ 4.00 April 2024 -December 2024 Swaps - Henry Hub 100,000 MMBtus/day $ 3.11 Crude oil derivatives Weighted Average Hedge Period and Type of Contract Average Volumes Hedged Price ($/Bbl)March 2022 -December 2022 NYMEX Roll Swaps 24,000 Bbls/day $ 1.10 Share repurchase program InMay 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to$1 billion of our common stock beginning inJune 2019 . OnFebruary 8, 2022 , our Board of Directors approved an increase in the size of the share repurchase program to$1.5 billion , inclusive of cumulative amounts repurchased to date. As of the date of this filing, we have repurchased and retired a cumulative total of approximately 17.0 million shares under the program at an aggregate cost of$441.1 million , leaving approximately$1.06 billion of authorized repurchasing capacity under the modified program. The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time. Senior note repurchases and redemptions As discussed in Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated Financial Statements, in recent years we have repurchased or redeemed a portion of our outstanding senior notes. From time to time, we may seek to execute additional repurchases or redemptions of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. Such repurchases or redemptions will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. 53 -------------------------------------------------------------------------------- Critical Accounting Policies and Estimates Our consolidated financial statements and related footnotes contain information that is pertinent to our management's discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and the disclosure and estimation of contingent assets and liabilities. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 1. Organization and Summary of Significant Accounting Policies and Note 9. Revenues for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. In management's opinion, the most significant reporting areas impacted by management's judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets, income taxes and contingent liabilities. These areas are discussed below. Management's judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters and are believed to be reasonable under the circumstances. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from the estimates as additional information becomes known. Crude Oil and Natural Gas Reserves Estimation and Standardized Measure of Future Cash Flows Our external independent reserve engineers,Ryder Scott , and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Even thoughRyder Scott and our internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company's control. Reserve estimates are updated by us at least semi-annually and take into account recent production levels and other technical information about each of our properties. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions or removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. For the years endedDecember 31, 2021 , 2020, and 2019, net upward (downward) revisions of our proved reserves totaled approximately 54 MMBoe, (505) MMBoe, and (149) MMBoe, respectively. We cannot predict the amounts or timing of future reserve revisions or removals. Estimates of proved reserves are key components of the Company's most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets. AtDecember 31, 2021 , our proved reserves totaled 1,645 MMBoe as determined using 12-month average first-day-of-the-month prices of$66.56 per barrel for crude oil and$3.60 per MMBtu for natural gas. Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil andHenry Hub natural gas first-day-of-the-month commodity prices forJanuary 1, 2022 andFebruary 1, 2022 averaged$81.71 per barrel and$4.65 per MMBtu, respectively. Holding all other factors constant, if crude oil prices used in our year-end reserve estimates were increased to$80 per barrel our proved reserves atDecember 31, 2021 could increase by approximately 21 MMBoe, or 1%. If the increase in proved reserves under this oil price sensitivity existed throughout 2021, our DD&A expense for 2021 would have decreased by approximately 2%. Holding all other factors constant, if natural gas prices used in our year-end reserve estimates were increased to$4.50 per MMBtu our proved reserves atDecember 31, 2021 could increase by approximately 8 MMBoe, or less than 1%. If the increase in proved reserves under this gas price sensitivity existed throughout 2021, our DD&A expense for 2021 would have decreased by approximately 1%. 54 -------------------------------------------------------------------------------- Our DD&A calculations for oil and gas properties are performed on a field basis and revisions to proved reserves will not necessarily be applied ratably across all fields and may not be applied to some fields at all. Further, reserve revisions in significant fields may individually affect our DD&A rate. As a result, the impact on DD&A expense from revisions in reserves cannot be predicted with certainty and may result in changes in expense that are greater or less than the underlying changes in reserves. See Part I, Item 1. Business-Crude Oil and Natural Gas Operations-Proved Reserves-Proved Reserves, Standardized Measure, and PV-10 Sensitivities for additional proved reserve sensitivities under certain increasing and decreasing commodity price scenarios for crude oil and natural gas. Revenue Recognition We derive substantially all of our revenues from the sale of crude oil and natural gas. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 9. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues. Operated crude oil and natural gas revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally marketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. At the end of each month, to record revenues we estimate the amount of production delivered and sold to customers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material. For the sale of crude oil and natural gas, we evaluate whether we are the principal, and report revenues on a gross basis (revenues presented separately from associated expenses), or an agent, and report revenues on a net basis. In this assessment, we consider if we obtain control of the products before they are transferred to the customer as well as other indicators. Judgment may be required in determining the point in time when control of products transfers to customers. Successful Efforts Method of Accounting Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available-the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements-Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting. Derivative Activities From time to time we may utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production and for other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings. In determining the amounts to be recorded for outstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party's valuation models for derivative contracts are industry-standard models that consider various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates. We validate our derivative valuations through management review and by comparison to our counterparties' valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material. 55 -------------------------------------------------------------------------------- Impairment of Assets All of our long-lived assets are monitored for potential impairment when circumstances indicate the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk-adjusted proved reserves. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions or removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods. No impairments were recognized for our proved crude oil and natural gas properties for the year endedDecember 31, 2021 as estimated future net cash flows were determined to be in excess of cost basis. Commodity price assumptions used for the year-endDecember 31, 2021 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 2026 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As ofDecember 31, 2021 , the publicly available forward commodity strip prices for the year 2026 used in our fourth quarter impairment calculations averaged$58.42 per barrel for crude oil and$3.03 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, impairments of producing properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any. Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties' costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. The estimated timing and rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available. Income Taxes Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance. We believe our net deferred tax assets will ultimately be realized. During 2020, a$14.5 million valuation allowance was established for the deferred tax asset associated with a portion of ourOklahoma state net operating loss carryforwards. In 2021, we reassessed the realizability of the deferred tax asset related toOklahoma state net operating loss carryforwards, and based on current year activity, determined it was more likely than not that such assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released in 2021. We will continue to evaluate both the 56 -------------------------------------------------------------------------------- positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to our deferred tax assets. Contingent Liabilities A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management's judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management's decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information. New Accounting Pronouncement See Part II, Item 8. Notes to Consolidated Financial Statements-Note 1. Organization and Summary of Significant Accounting Policies-Adoption of new accounting pronouncement for a discussion of the new income tax accounting standard adopted onJanuary 1, 2021 , which did not have a material impact on our financial position, results of operations, or cash flows. Legislative and Regulatory Developments The crude oil and natural gas industry inthe United States is subject to various types of regulation at the federal, state and local levels. InJanuary 2021 ,President Biden issued executive orders that, among other things, establish new greenhouse gas emission standards for the oil and gas sector. Additionally, theBiden Administration is pursuing legislative changes to eliminate or defer certain keyU.S. federal income tax deductions historically available to oil and gas exploration and production companies, as well as other tax policy changes including a proposed increase in theU.S. corporate income tax rate, among other things. These changes, if enacted, could have a material adverse effect on our results of operations and cash flows.President Biden may continue to issue additional executive orders in pursuit of his regulatory agenda and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry. See Part I, Item 1. Business-Regulation of the Crude Oil and Natural Gas Industry for further discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate. Inflation Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in recent years as service providers reduced their costs in response to reduced demand arising from historically low crude oil prices. However, inflationary pressures returned in 2021 and are expected to continue in 2022 in conjunction with the significant improvement in commodity prices over the past year in response to the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals. Additionally, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and resulting increases in material and labor costs. If these supply chain disruptions persist or worsen, and commodity prices continue to remain at attractive levels that stimulate increased industry activity, we may face shortages of service providers, equipment, and materials. Such shortages could result in increased competition which may lead to further increases in costs. Non-GAAP Financial Measures Net crude oil and natural gas sales and net sales prices Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Part II, Item 8. Notes to Consolidated Financial Statements-Note 9. Revenues. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance withU.S. GAAP using gross presentation for some revenues and net presentation for others. 57 -------------------------------------------------------------------------------- In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we have presented crude oil and natural gas sales net of transportation expenses in Management's Discussion and Analysis of Financial Condition and Results of Operations, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis. The following table presents a reconciliation of total Company crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for 2021, 2020, and 2019.Total Company Year EndedDecember 31, 2021 Year EndedDecember 31, 2020 Year EndedDecember 31, 2019 In thousands Crude oil Natural gas Total Crude oil Natural gas Total Crude oil Natural gas Total Crude oil and natural gas sales (GAAP)$ 3,949,294 $ 1,844,447
Less: Freight costs
(185,130) (39,859) (224,989) (158,989) (37,703) (196,692) (191,998) (33,651) (225,649) Net crude oil and natural gas sales (non-GAAP)$ 3,764,164 $ 1,804,588
Sales volumes (MBbl/MMcf/MBoe)
58,757 370,110 120,442 58,793 306,528 109,881 72,136 311,865 124,113 Net sales price (non-GAAP)$ 64.06 $ 4.88 $ 46.24 $ 34.71 $ 1.04 $ 21.47 $ 51.82 $ 1.77 $ 34.56 The following tables present reconciliations of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for NorthDakota Bakken and SCOOP for 2021, 2020, and 2019 as presented in Part I, Item 1.Business-Crude Oil and Natural Gas Operations-Production and Price History. NorthDakota Bakken Year EndedDecember 31, 2021 Year EndedDecember 31, 2020 Year EndedDecember 31, 2019 In thousands Crude oil Natural gas Total Crude oil Natural gas Total Crude oil Natural gas Total Crude oil and natural gas sales (GAAP)$ 2,695,738 $ 549,932
Less: Freight costs
(154,359) (4,831) (159,190) (127,036) (2,580) (129,616) (157,076) (2,530) (159,606) Net crude oil and natural gas sales (non-GAAP)$ 2,541,379 $ 545,101
Sales volumes (MBbl/MMcf/MBoe)
40,186 120,517 60,272 40,040 97,532 56,295 52,374 98,186 68,738 Net sales price (non-GAAP)$ 63.24 $ 4.52 $ 51.21 $ 33.53 $ 0.23 $ 24.24 $ 50.96 $ 1.28 $ 40.66 SCOOP Year EndedDecember 31, 2021 Year EndedDecember 31, 2020 Year EndedDecember 31, 2019 In thousands Crude oil Natural gas Total Crude oil Natural gas Total Crude oil Natural gas Total Crude oil and natural gas sales (GAAP)$ 756,596 $ 980,323
Less: Freight costs (2,854)
(23,808) (26,662) (5,275) (21,909) (27,184) (3,539) (14,795) (18,334) Net crude oil and natural gas sales (non-GAAP)$ 753,742 $ 956,515 $ 1,710,257 $ 480,801 $ 224,216 $ 705,017 $ 636,558 $ 262,435 $ 898,993 Sales volumes (MBbl/MMcf/MBoe) 11,341 179,553 41,267 12,694 136,410 35,429 11,592 111,436 30,164
Net selling price (non-GAAP)
$ 41.44 $ 37.88 $ 1.64 $ 19.90 $ 54.92 $ 2.36 $ 29.80 58
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PV-10
Our PV-10 value, a non-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed usingU.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. AtDecember 31, 2021 , our PV-10 totaled approximately$20.49 billion . The standardized measure of our discounted future net cash flows was approximately$16.64 billion atDecember 31, 2021 , representing a$3.86 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance withU.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. 59
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