UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)
x☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172022
or
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-32886

____________________________________
clr-20220930_g1.jpg
CONTINENTAL RESOURCES, INC.INC
(Exact name of registrant as specified in its charter)

____________________________________
Oklahoma73-0767549
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
20 N. Broadway,Oklahoma City, OklahomaOklahoma73102
(Address of principal executive offices)(Zip Code)
(405) 234-9000
(Registrant’s telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par valueCLRNew York Stock Exchange
____________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes x    No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes x    No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerxAccelerated filer☐
Non-accelerated filer☐Smaller reporting company☐
Emerging growth company☐
Large accelerated filerxAccelerated filer¨
Non-accelerated filer
¨  (Do not check if a smaller reporting company)
Smaller reporting company¨
Emerging growth company¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ¨☐    No x
375,208,904363,019,728 shares of our $0.01 par value common stock were outstanding on October 31, 2017.12, 2022.





Table of Contents
Item 1.
1
Condensed Consolidated Balance Sheets
1
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)Operations
2
Unaudited Condensed Consolidated StatementStatements of Shareholders’ Equity
3
Unaudited Condensed Consolidated Statements of Cash Flows
45
Notes to Unaudited Condensed Consolidated Financial Statements
56
Item 2.
1923
Item 3.
3338
Item 4.
3539
Item 1.
3640
Item 1A.
3640
Item 2.
3641
Item 3.
3641
Item 4.
3641
Item 5.
3641
Item 6.
3742
3843
When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.





Glossary of Crude Oil and Natural Gas Terms


The terms defined in this section may be used throughout this report:
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
“DD&A” Depreciation, depletion, amortization and accretion.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.
“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“formation” A layer of rock which has distinct characteristics that differs from nearby rock.
"gross acres" or "gross wells" Refers to the total acres or wells in which a working interest is owned.
“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
“MMBoe” One million Boe.
“MMBtu” One million British thermal units.
“MMcf” One million cubic feet of natural gas.
“net acres” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.
"Net crude oil, natural gas, and natural gas liquids sales" Represents total crude oil, natural gas, and natural gas liquids sales less total transportation expenses. Net crude oil, natural gas, and natural gas liquids sales presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
"Net sales price" Represents the average net wellhead sales price received by the Company for its sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period. Net sales prices presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
“NGL” or "NGLs" Refers to natural gas liquids, which are hydrocarbon products that are separated during natural gas processing and include ethane, propane, isobutane, normal butane, and natural gasoline.
i

“NYMEX” The New York Mercantile Exchange.
“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.

i


“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basinBasin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.
"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
 



ii


Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
•the take-private transaction described in Note 1. Organization and Nature of Business—Recent Developments, the Company's plans for financing the purchase of outstanding shares pursuant to the transaction, the potential impact of the transaction on the Company's future operating expenses, potential litigation, and the impact on the Company's share price if the transaction fails to close;
•our strategy;
•our business and financial plans;
•our future operations;
•our crude oil and natural gasproved reserves and related development plans;
•technology;
•future crude oil, natural gas liquids, and natural gascommodity prices and differentials;
•the timing and amount of future production of crude oil, natural gas liquids, and natural gas and flaring activities;
•the amount, nature and timing of capital expenditures;
•estimated revenues, expenses and results of operations;
•drilling and completing of wells;
competition;•shutting in of production and the resumption of production activities;
•competition;
•marketing of crude oil, natural gas, and natural gas;gas liquids;
•transportation of crude oil, natural gas, liquids, and natural gas liquids to markets;
•property exploitation, property acquisitions and dispositions, strategic investments, or joint development opportunities;
•costs of exploiting and developing our properties and conducting other operations;operations, including any impacts from inflation;
•our financial position;position, debt borrowings or repayments, share repurchases, or income tax payments;
general economic conditions;•geopolitical events and conditions in, or affecting other, crude oil-producing and natural gas-producing nations;
•credit markets;
•our liquidity and access to capital;
•the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;
•our future operating and financial results;
•our future commodity or other hedging arrangements; and
•the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.
Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2016,2021, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report or our Annual Report on Form 10-K for the year ended December 31, 2021 occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.
Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

iii

PART I. Financial Information

ITEM 1.Financial Statements
ITEM 1.    Financial Statements
Continental Resources, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
September 30, 2022December 31, 2021
In thousands, except par values and share data(Unaudited) 
Assets
Current assets:
Cash and cash equivalents$1,813,182 $20,868 
Receivables:
Crude oil, natural gas, and natural gas liquids sales1,500,426 1,122,415 
Joint interest and other429,531 278,753 
Allowance for credit losses(2,940)(2,814)
Receivables, net1,927,017 1,398,354 
Derivative assets14,149 22,334 
Inventories162,375 105,568 
Prepaid expenses and other47,038 17,266 
Total current assets3,963,761 1,564,390 
Net property and equipment, based on successful efforts method of accounting18,249,221 16,975,465 
Investment in unconsolidated affiliates152,972 — 
Operating lease right-of-use assets25,507 16,370 
Derivative assets, noncurrent2,034 13,188 
Other noncurrent assets18,281 21,698 
Total assets$22,411,776 $18,591,111 
Liabilities and equity
Current liabilities:
Accounts payable trade$940,902 $582,317 
Revenues and royalties payable951,029 627,171 
Accrued liabilities and other380,136 285,740 
Current portion of income tax liabilities62,893 — 
Derivative liabilities334,450 899 
Current portion of operating lease liabilities4,110 1,674 
Current portion of long-term debt637,739 2,326 
Total current liabilities3,311,259 1,500,127 
Long-term debt, net of current portion5,663,533 6,826,566 
Other noncurrent liabilities:
Deferred income tax liabilities, net2,564,973 2,139,884 
Asset retirement obligations, net of current portion250,596 215,701 
Derivative liabilities, noncurrent253,250 318 
Operating lease liabilities, net of current portion20,400 13,800 
Other noncurrent liabilities36,018 38,390 
Total other noncurrent liabilities3,125,237 2,408,093 
Commitments and contingencies (Note 9)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding— — 
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 363,022,746 shares issued and outstanding at September 30, 2022; 364,297,520 shares issued and outstanding at December 31, 20213,630 3,643 
Additional paid-in capital1,058,633 1,131,602 
Retained earnings8,872,930 6,340,211 
Total shareholders’ equity attributable to Continental Resources9,935,193 7,475,456 
Noncontrolling interests376,554 380,869 
Total equity10,311,747 7,856,325 
Total liabilities and equity$22,411,776 $18,591,111 
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
  September 30, 2017 December 31, 2016
In thousands, except par values and share data (Unaudited)  
Assets    
Current assets:    
Cash and cash equivalents $10,765
 $16,643
Receivables:    
Crude oil and natural gas sales 471,533
 404,750
Affiliated parties 56
 99
Joint interest and other, net 451,977
 364,850
Derivative assets 11,197
 4,061
Inventories 105,210
 111,987
Prepaid expenses and other 10,237
 10,843
Total current assets 1,060,975
 913,233
Net property and equipment, based on successful efforts method of accounting 12,919,202
 12,881,227
Other noncurrent assets 14,910
 17,316
Total assets $13,995,087
 $13,811,776
     
Liabilities and shareholders’ equity    
Current liabilities:    
Accounts payable trade $670,966
 $476,342
Revenues and royalties payable 264,289
 217,425
Payables to affiliated parties 146
 148
Accrued liabilities and other 190,646
 176,770
Derivative liabilities 1,144
 59,489
Current portion of long-term debt 2,268
 2,219
Total current liabilities 1,129,459
 932,393
Long-term debt, net of current portion 6,612,281
 6,577,697
Other noncurrent liabilities:    
Deferred income tax liabilities, net 1,860,094
 1,890,305
Asset retirement obligations, net of current portion 101,673
 94,436
Other noncurrent liabilities 14,801
 14,949
Total other noncurrent liabilities 1,976,568
 1,999,690
Commitments and contingencies (Note 7)   

Shareholders’ equity:    
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding —
 —
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 375,196,507 shares issued and outstanding at September 30, 2017; 374,492,357 shares issued and outstanding at December 31, 2016 3,752
 3,745
Additional paid-in capital 1,396,854
 1,375,290
Accumulated other comprehensive income (loss) 269
 (260)
Retained earnings 2,875,904
 2,923,221
Total shareholders’ equity 4,276,779
 4,301,996
Total liabilities and shareholders’ equity $13,995,087
 $13,811,776




Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)Operations
 Three months ended September 30,Nine months ended September 30,
In thousands, except per share data2022202120222021
Revenues:
Crude oil, natural gas, and natural gas liquids sales$2,767,262 $1,456,181 $7,870,696 $3,986,628 
Loss on derivative instruments, net(337,778)(127,110)(1,009,460)(232,795)
Crude oil and natural gas service operations17,747 12,341 52,707 38,519 
Total revenues2,447,231 1,341,412 6,913,943 3,792,352 
Operating costs and expenses:
Production expenses166,322 103,222 456,840 292,791 
Production and ad valorem taxes200,593 102,398 563,204 280,667 
Transportation, gathering, processing, and compression85,650 53,969 236,851 156,670 
Exploration expenses2,809 2,534 20,460 9,470 
Crude oil and natural gas service operations10,356 4,884 29,361 15,037 
Depreciation, depletion, amortization and accretion490,523 465,357 1,396,185 1,446,823 
Property impairments12,794 7,945 52,868 30,991 
General and administrative expenses68,687 58,421 206,098 166,822 
Net (gain) loss on sale of assets and other(618)(3,029)(773)(3,496)
Total operating costs and expenses1,037,116 795,701 2,961,094 2,395,775 
Income from operations1,410,115 545,711 3,952,849 1,396,577 
Other income (expense):
Interest expense(70,717)(59,894)(215,508)(185,796)
Gain (loss) on extinguishment of debt— — (403)(290)
Other4,490 345 4,503 895 
(66,227)(59,549)(211,408)(185,191)
Income before income taxes1,343,888 486,162 3,741,441 1,211,386 
Provision for income taxes(323,390)(115,641)(903,745)(291,116)
Income before equity in net loss of affiliate1,020,498 370,521 2,837,696 920,270 
Equity in net loss of affiliate(660)— (736)— 
Net income1,019,838 370,521 2,836,960 920,270 
Net income attributable to noncontrolling interests6,731 1,193 17,349 1,975 
Net income attributable to Continental Resources$1,013,107 $369,328 $2,819,611 $918,295 
Net income per share attributable to Continental Resources:
Basic$2.83 $1.02 $7.88 $2.54 
Diluted$2.80 $1.01 $7.79 $2.52 
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
  Three months ended September 30, Nine months ended September 30,
In thousands, except per share data 2017 2016 2017 2016
Revenues:        
Crude oil and natural gas sales $704,818
 $505,892
 $1,965,216
 $1,435,194
Gain (loss) on crude oil and natural gas derivatives, net 8,602
 15,668
 83,482
 (24,477)
Crude oil and natural gas service operations 13,323
 4,639
 24,959
 19,867
Total revenues 726,743
 526,199
 2,073,657
 1,430,584
         
Operating costs and expenses:        
Production expenses 84,514
 67,022
 239,842
 219,745
Production taxes 51,264
 34,583
 134,462
 104,216
Exploration expenses 1,389
 3,987
 9,591
 8,726
Crude oil and natural gas service operations 3,349
 2,605
 10,664
 9,224
Depreciation, depletion, amortization and accretion 420,243
 414,671
 1,198,169
 1,320,423
Property impairments 35,130
 57,689
 209,819
 202,728
General and administrative expenses 44,006
 44,389
 130,413
 113,043
Net (gain) loss on sale of assets and other (4,905) (5,564) 764
 (104,690)
Total operating costs and expenses 634,990
 619,382
 1,933,724
 1,873,415
Income (loss) from operations 91,753
 (93,183) 139,933
 (442,831)
Other income (expense):        
Interest expense (74,756) (82,074) (218,672) (244,949)
Other 394
 360
 1,209
 1,178

 (74,362) (81,714) (217,463) (243,771)
Income (loss) before income taxes 17,391
 (174,897) (77,530) (686,602)
(Provision) benefit for income taxes (6,770) 65,276
 25,063
 259,254
Net income (loss) $10,621
 $(109,621) $(52,467) $(427,348)
Basic net income (loss) per share $0.03
 $(0.30) $(0.14) $(1.15)
Diluted net income (loss) per share $0.03
 $(0.30) $(0.14) $(1.15)
         
Comprehensive income (loss):        
Net income (loss) $10,621
 $(109,621) $(52,467) $(427,348)
Other comprehensive income, net of tax:        
Foreign currency translation adjustments 202
 418
 529
 869
Total other comprehensive income, net of tax 202
 418
 529
 869
Comprehensive income (loss) $10,823
 $(109,203) $(51,938) $(426,479)



Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated StatementStatements of Shareholders’ Equity

Three Months Ended September 30, 2022
Shareholders’ equity attributable to Continental Resources
In thousands, except share dataShares
outstanding		Common
stock		Additional
paid-in
capital		Treasury
stock		Retained
earnings		Total shareholders’ equity of Continental ResourcesNoncontrolling
interests		Total equity
Balance at June 30, 2022363,002,130 $3,630 $1,042,891 $— $7,961,406 $9,007,927 $377,897 $9,385,824 
Net income— — — — 1,013,107 1,013,107 6,731 1,019,838 
Cash dividends declared— — — — (101,639)(101,639)(101,639)
Change in dividends payable— — — — 56 56 — 56 
Stock-based compensation— — 16,664 — — 16,664 — 16,664 
Restricted stock:
Granted107,134 1 — — — 1 — 1 
Repurchased and canceled(13,420)— (922)— — (922)— (922)
Forfeited(73,098)(1)— — — (1)— (1)
Contributions from noncontrolling interests— — — — — — 4,329 4,329 
Distributions to noncontrolling interests— — — — — — (12,403)(12,403)
Balance at September 30, 2022363,022,746 $3,630 $1,058,633 $— $8,872,930 $9,935,193 $376,554 $10,311,747 
Nine Months Ended September 30, 2022
Shareholders’ equity attributable to Continental Resources
In thousands, except share dataShares
outstanding		Common
stock		Additional
paid-in
capital		Treasury
stock		Retained
earnings		Total shareholders’ equity of Continental ResourcesNoncontrolling
interests		Total equity
Balance at December 31, 2021364,297,520 $3,643 $1,131,602 $— $6,340,211 $7,475,456 $380,869 $7,856,325 
Net income— — — — 2,819,611 2,819,611 17,349 2,836,960 
Cash dividends declared— — — — (287,036)(287,036)— (287,036)
Change in dividends payable— — — — 144 144 — 144 
Common stock repurchased— — — (99,855)— (99,855)— (99,855)
Common stock retired(1,842,422)(18)(99,837)99,855 — — — — 
Stock-based compensation— — 60,751 — — 60,751 — 60,751 
Restricted stock:
Granted1,539,017 15 — — — 15 — 15 
Repurchased and canceled(605,162)(6)(33,883)— — (33,889)— (33,889)
Forfeited(366,207)(4)— — — (4)— (4)
Contributions from noncontrolling interests— — — — — — 8,135 8,135 
Distributions to noncontrolling interests— — — — — — (29,799)(29,799)
Balance at September 30, 2022363,022,746 $3,630 $1,058,633 $— $8,872,930 $9,935,193 $376,554 $10,311,747 
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Equity (Continued)

In thousands, except share data Shares
outstanding		 Common
stock		 Additional
paid-in
capital		 Accumulated
other
comprehensive
income (loss)		 Retained
earnings		 Total
shareholders’
equity
Balance at December 31, 2016 374,492,357
 $3,745
 $1,375,290
 $(260) $2,923,221
 $4,301,996
Cumulative effect adjustment from adoption of ASU 2016-09 (unaudited) (see Note 2) —
 —
 —
 —
 5,150
 5,150
Net loss (unaudited) —
 —
 —
 —
 (52,467) (52,467)
Other comprehensive income, net of tax (unaudited) —
 —
 —
 529
 —
 529
Stock-based compensation (unaudited) —
 —
 32,547
 —
 —
 32,547
Restricted stock:            
Granted (unaudited) 1,518,824
 15
 —
 —
 —
 15
Repurchased and canceled (unaudited) (241,060) (2) (10,983) —
 —
 (10,985)
Forfeited (unaudited) (573,614) (6) —
 —
 —
 (6)
Balance at September 30, 2017 (unaudited) 375,196,507
 $3,752
 $1,396,854
 $269
 $2,875,904
 $4,276,779
Three Months Ended September 30, 2021
Shareholders’ equity attributable to Continental Resources
In thousands, except share dataShares
outstanding		Common
stock		Additional
paid-in
capital		Treasury
stock		Retained
earnings		Total shareholders’ equity of Continental ResourcesNoncontrolling
interests		Total equity
Balance at June 30, 2021367,563,899 $3,676 $1,226,223 $— $5,356,189 $6,586,088 $369,586 $6,955,674 
Net income— — — — 369,328 369,328 1,193 370,521 
Cash dividends declared— — — — (55,132)(55,132)— (55,132)
Change in dividends payable— — — — 93 93 — 93 
Common stock repurchased— — — (65,256)— (65,256)— (65,256)
Common stock retired(1,916,069)(19)(65,237)65,256 — — — — 
Stock-based compensation— — 14,506 — — 14,506 — 14,506 
Restricted stock:
Granted47,701 — — — — — — — 
Repurchased and canceled(19,003)— (737)— — (737)— (737)
Forfeited(80,128)(1)— — — (1)— (1)
Contributions from noncontrolling interests— — — — — — 6,788 6,788 
Distributions to noncontrolling interests— — — — — — (5,390)(5,390)
Balance at September 30, 2021365,596,400 $3,656 $1,174,755 $— $5,670,478 $6,848,889 $372,177 $7,221,066 


Nine Months Ended September 30, 2021
Shareholders’ equity attributable to Continental Resources
In thousands, except share dataShares
outstanding		Common
stock		Additional
paid-in
capital		Treasury
stock		Retained
earnings		Total shareholders’ equity of Continental ResourcesNoncontrolling
interests		Total equity
Balance at December 31, 2020365,220,435 $3,652 $1,205,148 $— $4,847,646 $6,056,446 $366,279 $6,422,725 
Net income— — — — 918,295 918,295 1,975 920,270 
Cash dividends declared— — — — (95,561)(95,561)— (95,561)
Change in dividends payable— — — — 98 98 — 98 
Common stock repurchased— — — (65,256)— (65,256)— (65,256)
Common stock retired(1,916,069)(19)(65,237)65,256 — — — — 
Stock-based compensation— — 45,024 — — 45,024 — 45,024 
Restricted stock:
Granted2,900,923 29 — — — 29 — 29 
Repurchased and canceled(426,255)(4)(10,180)— — (10,184)— (10,184)
Forfeited(182,634)(2)— — — (2)— (2)
Contributions from noncontrolling interests— — — — — — 21,263 21,263 
Distributions to noncontrolling interests— — — — — — (17,340)(17,340)
Balance at September 30, 2021365,596,400 $3,656 $1,174,755 $— $5,670,478 $6,848,889 $372,177 $7,221,066 

The accompanying notes are an integral part of these condensed consolidated financial statements.
4
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Cash Flows
 Nine months ended September 30,
In thousands20222021
Cash flows from operating activities
Net income$2,836,960 $920,270 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion1,395,312 1,445,129 
Property impairments52,868 30,991 
Non-cash loss on derivatives605,822 145,194 
Stock-based compensation60,766 44,918 
Provision for deferred income taxes425,089 291,116 
Equity in net loss of affiliate736 — 
Dry hole costs12,107 — 
Net (gain) loss on sale of assets and other(773)(3,496)
(Gain) loss on extinguishment of debt403 290 
Other, net11,544 7,465 
Changes in assets and liabilities:
Accounts receivable(527,975)(444,748)
Inventories(56,777)(47,128)
Other current assets(29,298)(1,894)
Accounts payable trade205,759 96,785 
Revenues and royalties payable322,029 183,050 
Accrued liabilities and other88,555 60,690 
Current income taxes liability62,893 — 
Other noncurrent assets and liabilities(2,049)21 
Net cash provided by operating activities5,463,971 2,728,653 
Cash flows from investing activities
Exploration and development(2,060,797)(905,974)
Purchase of producing crude oil and natural gas properties(432,651)(175,441)
Purchase of other property and equipment(53,372)(46,948)
Proceeds from sale of assets3,163 4,562 
Contributions to unconsolidated affiliates(153,665)— 
Net cash used in investing activities(2,697,322)(1,123,801)
Cash flows from financing activities
Credit facility borrowings1,916,000 1,063,000 
Repayment of credit facility(2,416,000)(1,223,000)
Redemption and repurchase of Senior Notes(31,829)(630,782)
Repayment of other debt(1,736)(1,674)
Debt issuance costs(2,016)— 
Contributions from noncontrolling interests6,720 19,812 
Distributions to noncontrolling interests(27,968)(16,535)
Repurchase of common stock(99,855)(65,256)
Repurchase of restricted stock for tax withholdings(33,889)(10,184)
Dividends paid on common stock(283,762)(94,054)
Net cash used in financing activities(974,335)(958,673)
Net change in cash and cash equivalents1,792,314 646,179 
Cash and cash equivalents at beginning of period20,868 47,470 
Cash and cash equivalents at end of period$1,813,182 $693,649 
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
  Nine months ended September 30,
In thousands 2017 2016
Cash flows from operating activities  
Net loss $(52,467) $(427,348)
Adjustments to reconcile net loss to net cash provided by operating activities:    
Depreciation, depletion, amortization and accretion 1,199,715
 1,322,280
Property impairments 209,819
 202,728
Non-cash (gain) loss on derivatives, net (65,481) 105,009
Stock-based compensation 32,490
 34,274
Benefit for deferred income taxes (25,063) (259,256)
Tax deficiency from stock-based compensation —
 9,460
Dry hole costs 157
 233
Gain on sale of assets, net (703) (103,174)
Other, net 7,705
 7,166
Changes in assets and liabilities:    
Accounts receivable (154,790) (2,634)
Inventories 6,736
 1,257
Other current assets 729
 390
Accounts payable trade 128,337
 (43,131)
Revenues and royalties payable 48,447
 (11,102)
Accrued liabilities and other 13,050
 22,411
Other noncurrent assets and liabilities (700) 5,325
Net cash provided by operating activities 1,347,981
 863,888
     
Cash flows from investing activities    
Exploration and development (1,444,991) (878,928)
Purchase of producing crude oil and natural gas properties (3,480) (29)
Purchase of other property and equipment (10,508) (5,569)
Proceeds from sale of assets 84,725
 334,305
Net cash used in investing activities (1,374,254) (550,221)
     
Cash flows from financing activities    
Credit facility borrowings 985,000
 915,000
Repayment of credit facility (952,000) (1,203,000)
Repayment of other debt (1,654) (1,601)
Debt issuance costs —
 (40)
Repurchase of restricted stock for tax withholdings (10,985) (6,540)
Tax deficiency from stock-based compensation —
 (9,460)
Net cash provided by (used in) financing activities 20,361
 (305,641)
Effect of exchange rate changes on cash 34
 7
Net change in cash and cash equivalents (5,878) 8,033
Cash and cash equivalents at beginning of period 16,643
 11,463
Cash and cash equivalents at end of period $10,765
 $19,496

Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business
Nature of Business
Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company'sCompany’s principal business is the exploration, development, management, and production of crude oil and natural gas exploration, development and productionassociated products with properties primarily located in the North, South, and East regions offour leading basins in the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 58% of the Company’s crude oil and natural gas production and approximately 67% of its crude oil and natural gas revenues for the nine months ended September 30, 2017. The Company's principal producing properties in the North region are located inStates – the Bakken field of North Dakota and Montana. In recent years,Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company has significantly expanded its operationspursues the acquisition and management of perpetually owned minerals located in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 42% of the Company's crude oil and natural gas production and approximately 33%certain of its crude oil and natural gas revenues for the nine months ended September 30, 2017.
key operating areas. For the nine months ended September 30, 2017,2022, crude oil accounted for approximately 56%50% of the Company’s total production and approximately 77%68% of its crude oil, natural gas, and natural gas liquids revenues.    
Recent Developments
On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Mr. Hamm currently serves as Chairman of the Board of Directors of the Company and he, along with certain of his family members and their affiliated entities (collectively, the “Hamm Family”), own approximately 83% of the outstanding shares of the Company’s common stock.
Pursuant to the Merger Agreement, on October 24, 2022, Merger Sub commenced a tender offer (the “Offer”) to purchase any and all of the outstanding shares of the Company’s common stock, other than: (i) shares of common stock owned by the Hamm Family and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans (collectively, the “Rollover Shares”) for $74.28 per share in cash (the “Offer Price”). The Offer is scheduled to expire one minute after 11:59 p.m., New York City time, on November 21, 2022. There are approximately 58 million shares of Continental's common stock that are subject to the Offer and approximately 5.3 million shares underlying unvested equity awards that are not held by the Hamm Family. The Offer Price includes $0.28 per share in lieu of the Company's anticipated dividend for the third quarter of 2022. Accordingly, and consistent with the Merger Agreement, the Company will not pay dividends between the signing and closing of the transaction.
The Offer is subject to certain conditions. If the conditions of the Merger Agreement are met, promptly following the consummation of the Offer, Merger Sub will merge with and into the Company (the “Merger”), with the Company continuing as the surviving corporation wholly-owned by the Hamm Family.
At the effective time of the Merger: (a) each share of Company common stock (other than the Rollover Shares and certain other excluded shares specified in the Merger Agreement) that is outstanding immediately prior to the effective time will be canceled and converted into the right to receive the Offer Price in cash; (b) each share held by a member of the Hamm Family will be converted into a newly issued share of the Company having identical rights to the previously existing share held by such holder; and (c) each unvested restricted stock award issued under the Company’s long-term incentive plans that is outstanding immediately prior to the effective time will be canceled and replaced with a restricted stock unit award issued by the Company that provides the holder of such canceled award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two, in each case, together with any unpaid dividends accrued on such restricted stock award.
Subject to the satisfaction of customary closing conditions, the above-described transaction is expected to close prior to December 31, 2022. Upon consummation of the transaction, the Company’s common stock will cease to be listed on the New York Stock Exchange and will subsequently be deregistered under the Securities Exchange Act of 1934, as amended.

6
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Basis of Presentation and Significant Accounting Policies
Basis of presentation
The condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and its subsidiaries, all ofentities in which are 100% owned, after all significant intercompanythe Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.
Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company's proportionate share of earnings, losses, contributions, and distributions as applicable. See Note 13. Equity Investment for discussion of a new strategic investment made by the Company in 2022 that is accounted for under the equity method.
This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q ("(“Form 10-Q"10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, 20162021 (“20162021 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.
The condensed consolidated financial statements as of September 30, 20172022 and for the three and nine month periods ended September 30, 20172022 and 20162021 are unaudited. The condensed consolidated balance sheet as of December 31, 20162021 was derived from the audited balance sheet included in the 20162021 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.

7
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Earnings per share
Basic net income (loss) per share is computed by dividing net income (loss)attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the three and nine months ended September 30, 20172022 and 2016.
2021.
 Three months ended September 30, Nine months ended September 30, Three months ended September 30,Nine months ended September 30,
In thousands, except per share data 2017 2016 2017 2016In thousands, except per share data2022202120222021
Net income (loss) (numerator) $10,621
 $(109,621) $(52,467) $(427,348)
Net income attributable to Continental Resources (numerator) (1)Net income attributable to Continental Resources (numerator) (1)$1,013,107 $369,328 $2,819,611 $918,295 
Weighted average shares (denominator):        Weighted average shares (denominator):
Weighted average shares - basic 371,142
 370,483
 371,029
 370,327
Weighted average shares - basic357,617 360,563 357,786 360,899 
Non-vested restricted stock (1) 1,873
 —
 —
 —
Non-vested restricted stockNon-vested restricted stock3,904 3,685 4,239 3,580 
Weighted average shares - diluted 373,015
 370,483
 371,029
 370,327
Weighted average shares - diluted361,521 364,248 362,025 364,479 
Net income (loss) per share:        
Net income per share attributable to Continental Resources: (1)Net income per share attributable to Continental Resources: (1)
Basic $0.03
 $(0.30) $(0.14) $(1.15)Basic$2.83 $1.02 $7.88 $2.54 
Diluted $0.03
 $(0.30) $(0.14) $(1.15)Diluted$2.80 $1.01 $7.79 $2.52 
(1)For the nine months ended September 30, 2017 the Company had a net loss and therefore the potential dilutive effect of approximately 2,558,900 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation. The Company also had net losses for the three and nine months ended September 30, 2016, and therefore approximately 2,176,500 and 2,083,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods.
(1)    Results for the 2022 periods include $95 million of pre-tax income recognized in the third quarter of 2022 in conjunction with the resolution of a legal matter, which resulted in an after-tax increase in net income of $72 million ($0.20 per basic and diluted share) for the 2022 periods.
Credit risk
The Company's principal exposure to credit risk is through receivables associated with the sale of its production and receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the condensed consolidated balance sheets as "Receivables—Crude oil, natural gas, and natural gas liquids sales” and "Receivables—Joint interest and other.” The Company determines its credit loss allowance for each portfolio segment by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and a party's ability to pay. Historically, the Company's credit losses have been immaterial. There were no significant write-offs, recoveries, or changes in the Company's allowance for credit losses during the three and nine month periods ended September 30, 2022 and 2021.
Inventories
Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil and natural gas inventories are valued at the lower of cost or marketnet realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.
The components of inventory as of September 30, 20172022 and December 31, 20162021 consisted of the following:
In thousandsSeptember 30, 2022December 31, 2021
Tubular goods and equipment$36,795 $12,506 
Crude oil and natural gas125,580 93,062 
Total$162,375 $105,568 


In thousands September 30, 2017 December 31, 2016
Tubular goods and equipment $16,709
 $15,243
Crude oil 88,501
 96,744
Total $105,210
 $111,987

Adoption of new accounting pronouncements
8
Stock-based compensation – In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below.
ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company's cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017.
Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $0.1 million ($0.00 per share) and $3.9 million ($0.01 per share) of tax deficiencies from stock-based compensation as income tax expense for the three and nine months ended September 30, 2017, respectively, under
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Property Acquisitions
2022
On March 25, 2022, the new standard, which are reflected in "(Provision) benefit for income taxes"Company acquired oil and gas properties in the unaudited condensed consolidated statementsPowder River Basin of comprehensive income (loss).
ASU 2016-09 also removedWyoming for cash consideration of $403 million, representing a $450 million purchase price less customary closing adjustments made pursuant to the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes.acquisition agreement. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017 has not been adjusted to conform to current period presentation.
The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards.
Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions beingacquisition was accounted for as an asset acquisitions rather than business combinations. The standard is effective for interimacquisition under ASC Topic 805 and annual periods beginning after December 15, 2017included approximately 172,000 net leasehold acres and shall be applied prospectively.producing properties with production totaling approximately 18,000 net barrels of oil equivalent per day at the time of closing. The Company early adopted ASU 2017-01recognized approximately $15.3 million of asset retirement obligations, $31.3 million of assumed production and ad valorem tax payment obligations, and $10.1 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.
On April 15, 2022, the Company acquired oil and gas properties in the Permian Basin of Texas for cash consideration of $197.0 million, consisting of a $20 million escrow deposit paid in March 2022 upon execution of the definitive purchase agreement and a $177.0 million payment made at closing in April 2022. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and was comprised primarily of January 1, 2017, which had no significant impact on the Company's financial statements as of and for the three and nine months ended September 30, 2017.
New accounting pronouncements not yet adopted
Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contractsundeveloped leasehold acreage with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate theimmaterial amount of consideration to be receivedproduction.
2021
In March 2021, the Company acquired oil and gas properties in the transaction price, allocatePowder River Basin of Wyoming for cash consideration of $206.6 million, consisting of a $21.5 million escrow deposit paid in December 2020 upon execution of the transaction price to each separate performance obligation,definitive purchase agreement and recognize revenuea $185.1 million payment made at closing in March 2021. The acquisition was accounted for as obligations are satisfied. Additionally,an asset acquisition under ASC Topic 805 and included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the standard requires expanded disclosures related to revenue recognition.
Subsequent to the issuancetime of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate.
ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented.closing. The Company plans to adopt the standard on January 1, 2018 using the modified retrospective approach.
The Company is nearing completionrecognized approximately $4.9 million of its evaluationasset retirement obligations and $8.2 million of the impact of the new standardright-of-use assets and related interpretive guidance on its financial statements, accounting policies, internal controls, and disclosures. Based on assessments performed to date, the standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures and internal controls over financial reporting. Additionally, the standard is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues andcorresponding lease liabilities associated transportation expenses for certain of the Company's operated properties being reported on a gross basis. The Company expects changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company's results of operations, net income, or cash flows. For the three and nine months ended September 30, 2017, the Company had approximately $50.3 million and $148.2 million, respectively, of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive income (loss). These amounts are not necessarily indicative of amounts to be expected in future periods. The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Ongoing interpretive developments are being monitored which may impact the Company's financial statement presentation and disclosures.
Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach.
The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company's business and industry. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain future surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time.acquired properties.
Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.
Note 3.4. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
 Nine months ended September 30,
In thousands20222021
Supplemental cash flow information:
Cash paid for interest$200,206 $164,874 
Cash paid for income taxes (1)440,145 3 
Cash received for income tax refunds16 9 
Non-cash investing activities:
Asset retirement obligation additions and revisions, net28,243 9,818 
  Nine months ended September 30,
In thousands 2017 2016
Supplemental cash flow information:    
Cash paid for interest $198,405
 $213,969
Cash paid for income taxes 2
 —
Cash received for income tax refunds 148
 174
Non-cash investing activities:    
Asset retirement obligation additions and revisions, net 5,111
 1,645
(1) Year-to-date amount for 2022 represents estimated quarterly payments for 2022 U.S. federal income taxes based on an estimate of federal taxable income for the year.

As of September 30, 20172022 and December 31, 2016,2021, the Company had $289.9had $393.6 million and $223.6 and $242.9 million, respectively, of accrued capital expenditures included in "Net“Net property and equipment" and "Accountsequipment” with an offsetting amount in “Accounts payable trade"trade” in the condensed consolidated balance sheets.
As of September 30, 2022 and December 31, 2021, the Company had $3.1 million and $1.7 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.
As of September 30, 2022 and December 31, 2021, the Company had $4.3 million and $2.5 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

9
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 5. Revenues
Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements.
Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil 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. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $67.8 million and $45.2 million for the three months ended September 30, 2022 and 2021, respectively, and $188.4 million and $129.2 million for the nine months ended September 30, 2022 and 2021, respectively.
Operated natural gas and natural gas liquids revenues – The Company sells a substantial majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream inclusive of natural gas liquids ("NGLs") at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and NGLs at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.
Under certain arrangements, the Company may elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $17.8 million and $8.7 million for the three months ended September 30, 2022 and 2021, respectively, and $48.4 million and $27.5 million for the nine months ended September 30, 2022 and 2021, respectively.
Non-operated crude oil, natural gas, and NGL revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate 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 to be received 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. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.
Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
10
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Disaggregation of revenues
The following table presents the disaggregation of the Company's crude oil and natural gas revenues by operating area for the three and nine months ended September 30, 2022 and 2021. Sales of natural gas and NGLs are combined, as a substantial majority of the Company's natural gas sales contracts represent wellhead sales of unprocessed gas.
Three months ended September 30, 2022Three months ended September 30, 2021
In thousandsCrude OilNatural Gas and NGLsTotalCrude OilNatural Gas and NGLsTotal
Bakken (1)$997,190 $376,693 $1,373,883 $709,642 $151,335 $860,977 
Anadarko Basin258,267 562,896 821,163 227,239 298,309 525,548 
Powder River Basin177,129 47,892 225,021 24,081 3,705 27,786 
Permian Basin253,863 41,167 295,030 — — — 
All other51,965 200 52,165 41,861 9 41,870 
Crude oil, natural gas, and natural gas liquids sales$1,738,414 $1,028,848 $2,767,262 $1,002,823 $453,358 $1,456,181 
Nine months ended September 30, 2022Nine months ended September 30, 2021
In thousandsCrude OilNatural Gas and NGLsTotalCrude OilNatural Gas and NGLsTotal
Bakken (1)$3,031,550 $870,168 $3,901,718 $1,947,883 $337,960 $2,285,843 
Anadarko Basin869,095 1,435,607 2,304,702 632,906 882,453 1,515,359 
Powder River Basin418,687 94,400 513,087 61,714 7,340 69,054 
Permian Basin852,778 125,850 978,628 — — — 
All other171,632 929 172,561 116,356 16 116,372 
Crude oil, natural gas, and natural gas liquids sales$5,343,742 $2,526,954 $7,870,696 $2,758,859 $1,227,769 $3,986,628 
(1) Natural gas and NGL revenues for the Bakken field for the 2022 periods include$95 million of revenues recognized in the third quarter of 2022 in conjunction with the resolution of a legal matter, which pertain almost entirely to performance obligations satisfied by the Company in periods prior to 2022.
11
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 4.6. Derivative Instruments
Crude oil and natural gas derivatives
TheFrom time to time the Company may utilize crude oil and natural gas swap and collarenters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.
The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

condensed consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on crude oil and natural gas derivatives, net”.
The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements.
    With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.
At September 30, 2017, the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the respective 2017 and 2018 periods. At September 30, 2017 the Company had no outstanding crude oil derivative contracts.
      Collars
Natural Gas - NYMEX Henry Hub Swaps Weighted Average Price Floors Ceilings
       Weighted Average Price   Weighted Average Price
Period and Type of Contract MMBtus  Range  Range 
October 2017 - December 2017            
Swaps - Henry Hub 33,120,000
 $3.39
        
Collars - Henry Hub 16,560,000
   $2.40 - $3.00 $2.47
 $2.92 - $3.88 $3.08
January 2018 - March 2018            
Swaps - Henry Hub 6,300,000
 $3.28
        

Crude oil and natural gas derivative gains and losses
Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
  Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Cash received (paid) on derivatives:        
Natural gas fixed price swaps $12,893
 $5,174
 $25,080
 $83,141
Natural gas collars (612) —
 (10,068) —
Cash received on derivatives, net 12,281
 5,174
 15,012
 83,141
Non-cash gain (loss) on derivatives:        
Crude oil written call options —
 —
 —
 38
Natural gas fixed price swaps (8,026) 5,298
 27,390
 (93,617)
Natural gas collars 4,347
 5,196
 41,080
 (14,039)
Non-cash gain (loss) on derivatives, net (3,679) 10,494
 68,470
 (107,618)
Gain (loss) on crude oil and natural gas derivatives, net $8,602
 $15,668
 $83,482
 $(24,477)
Diesel fuel derivatives
The Company has entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately three million gallons of diesel fuel over the period from October 2017 to December 2017 at a weighted average price of $1.45
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.
The Company recognizes its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, markscalculation of the derivative instruments to fair value and recognizesof collars requires the changes in fair valueuse of an option-pricing model. See Note 7. Fair Value Measurements.
At September 30, 2022 the Company had outstanding derivative contracts as set forth in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Operating coststables below. 
Natural gas derivatives
Weighted Average Hedge Price ($/MMBtu)
Period and Type of ContractAverage Volumes HedgedBasis SwapsSwapsSold PutFloorCeiling
October 2022 - December 2023
Basis Swaps - NGPL TXOK75,000 MMBtus/day$(0.17)
October 2022 - December 2022
Swaps - Henry Hub160,000 MMBtus/day$4.48 
Collars - Henry Hub360,000 MMBtus/day$3.88 $5.45 
Three-way collars - Henry Hub50,000 MMBtus/day$3.00 $4.07 $5.00 
Swaps - WAHA45,000 MMBtus/day$3.41 
January 2023 - December 2023
Swaps - Henry Hub308,000 MMBtus/day$3.49 
Collars - Henry Hub139,000 MMBtus/day$3.62 $4.95 
Three-way collars - Henry Hub12,500 MMBtus/day$3.00 $4.32 $5.00 
Swaps - WAHA40,000 MMBtus/day$2.69 
January 2024 - December 2024
Swaps - Henry Hub310,500 MMBtus/day$3.26 
Collars - Henry Hub50,000 MMBtus/day$3.12 $4.09 
January 2025 - December 2025
Swaps - Henry Hub37,000 MMBtus/day$3.39 
Crude oil derivatives
Period and Type of ContractAverage Volumes HedgedWeighted Average Hedge Price Differential ($/Bbl)
October 2022 - December 2022
NYMEX Roll Swaps55,500 Bbls/day$1.77 
January 2023 - December 2023
NYMEX Roll Swaps12,000 Bbls/day$1.07 
Derivative gains and expenses—Net (gain) loss on sale of assetslosses
Cash receipts and other.”
Cash receiptspayments in the following table reflect the gains or losses on diesel fuel derivativesderivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of diesel fuel derivativesderivative instruments which continuecontinued to be held at period end and the reversal of previously recognized non-cash gains or losses on
12
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
derivative contracts that matured during the period.
  Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Cash received on diesel fuel derivatives $603
 $100
 $1,522
 $100
Non-cash gain (loss) on diesel fuel derivatives 740
 (531) (2,989) 2,609
Gain (loss) on diesel fuel derivatives, net $1,343
 $(431) $(1,467) $2,709
 Three months ended September 30,Nine months ended September 30,
In thousands2022202120222021
Cash received (paid) on derivatives:
Crude oil fixed price swaps$— $— $— $(44,462)
Crude oil collars— — — (9,365)
Crude oil NYMEX roll swaps(5,836)(156)(12,908)966 
Natural gas basis swaps (NGPL TXOK)2,843 — $4,335 $— 
Natural gas fixed price swaps (WAHA)(15,536)— (15,536)— 
Natural gas fixed price swaps (HH)(185,463)(31,361)(327,047)(27,411)
Natural gas collars (HH)(22,106)(10,563)$(36,023)$(7,329)
Natural gas 3-way collars (HH)— — $(16,459)$— 
Cash received (paid) on derivatives, net(226,098)(42,080)(403,638)(87,601)
Non-cash gain (loss) on derivatives:
Crude oil collars— — — 227 
Crude oil NYMEX roll swaps19,789 3,506 3,630 180 
Natural gas basis swaps (NGPL TXOK)6,981 — 11,773 — 
Natural gas fixed price swaps (WAHA)2,159 — (11,914)— 
Natural gas fixed price swaps (HH)(52,118)(33,947)(420,613)(68,503)
Natural gas collars (HH)(78,501)(11,411)(168,758)(29,101)
Natural gas 3-way collars (HH)(9,990)(43,178)(19,940)(47,997)
Non-cash gain (loss) on derivatives, net(111,680)(85,030)(605,822)(145,194)
Loss on derivative instruments, net$(337,778)$(127,110)$(1,009,460)$(232,795)
Balance sheet offsetting of derivative assets and liabilities
The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”,assets,” “Derivative liabilities”,assets, noncurrent,” “Derivative liabilities,” and “Noncurrent derivative liabilities”,“Derivative liabilities, noncurrent” as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.
The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.
In thousandsSeptember 30, 2022December 31, 2021
Commodity derivative assets:
Gross amounts of recognized assets$22,176 $42,903 
Gross amounts offset on balance sheet(5,993)(7,381)
Net amounts of assets on balance sheet16,183 35,522 
Commodity derivative liabilities:
Gross amounts of recognized liabilities(593,693)(8,598)
Gross amounts offset on balance sheet5,993 7,381 
Net amounts of liabilities on balance sheet$(587,700)$(1,217)
13
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
In thousands September 30, 2017 December 31, 2016
Commodity derivative assets:    
Gross amounts of recognized assets $12,229
 $4,061
Gross amounts offset on balance sheet (1,032) —
Net amounts of assets on balance sheet 11,197
 4,061
Commodity derivative liabilities:    
Gross amounts of recognized liabilities (2,176) (59,489)
Gross amounts offset on balance sheet 1,032
 —
Net amounts of liabilities on balance sheet $(1,144) $(59,489)
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.
In thousandsSeptember 30, 2022December 31, 2021
Derivative assets$14,149 $22,334 
Derivative assets, noncurrent2,034 13,188 
Net amounts of assets on balance sheet16,183 35,522 
Derivative liabilities(334,450)(899)
Derivative liabilities, noncurrent(253,250)(318)
Net amounts of liabilities on balance sheet(587,700)(1,217)
Total derivative assets (liabilities), net$(571,517)$34,305 
In thousands September 30, 2017 December 31, 2016
Derivative assets $11,197
 $4,061
Noncurrent derivative assets —
 —
Net amounts of assets on balance sheet 11,197
 4,061
Derivative liabilities (1,144) (59,489)
Noncurrent derivative liabilities —
 —
Net amounts of liabilities on balance sheet (1,144) (59,489)
Total derivative assets (liabilities), net $10,053
 $(55,428)
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 5.7. Fair Value Measurements
The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
•Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
•Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
•Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers 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. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
14
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
The following tables summarize the valuation of financialderivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of September 30, 20172022 and December 31, 2016.2021.
 Fair value measurements at September 30, 2022 using: 
In thousandsLevel 1Level 2Level 3Total
Derivative assets (liabilities):
Natural gas fixed price swaps (WAHA)$— $(11,914)$— $(11,914)
Natural gas fixed price swaps (HH)— (393,005)— (393,005)
Natural gas basis swaps (NGPL TXOK)— 11,596 — 11,596 
Natural gas collars (HH)— (164,773)— (164,773)
Natural gas 3-way collars (HH)— (18,008)— (18,008)
Crude oil NYMEX roll swaps— 4,587 — 4,587 
Total$— $(571,517)$— $(571,517)
 Fair value measurements at September 30, 2017 using:   Fair value measurements at December 31, 2021 using: 
In thousands Level 1 Level 2 Level 3 TotalIn thousandsLevel 1Level 2Level 3Total
Derivative assets (liabilities):        Derivative assets (liabilities):
Swaps $—
 $12,104
 $—
 $12,104
Collars —
 (2,051) —
 (2,051)
Natural gas fixed price swaps (HH)Natural gas fixed price swaps (HH)$— $27,608 $— $27,608 
Natural gas basis swaps (NGPL TXOK)Natural gas basis swaps (NGPL TXOK)— (177)— $(177)
Natural gas collars (HH)Natural gas collars (HH)— 3,986 — $3,986 
Natural gas 3-way collars (HH)Natural gas 3-way collars (HH)— 1,931 — $1,931 
Crude oil NYMEX roll swapsCrude oil NYMEX roll swaps— 957 — $957 
Total $—
 $10,053
 $—
 $10,053
Total$— $34,305 $— $34,305 
        
 Fair value measurements at December 31, 2016 using:  
In thousands Level 1 Level 2 Level 3 Total
Derivative liabilities:        
Swaps $—
 $(12,297) $—
 $(12,297)
Collars —
 (43,131) —
 (43,131)
Total $—
 $(55,428) $—
 $(55,428)
Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Asset Impairmentsimpairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. 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. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. TheSignificant unobservable inputs (Level 3) utilized in the determination of discounted cash flow method estimates future net cash flows based on the Company's estimates ofinclude future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a risk-adjusted10% discount rate. The fair value of proved crude oilAt September 30, 2022, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2026 and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.
Unobservable InputAssumption
Future productionFuture production estimates for each property
Forward commodity pricesForward NYMEX strip prices through 2021 (adjusted for differentials), escalating 3% per year thereafter
Operating costsEstimated costs for the current year, escalating 3% per year thereafter
Productive life of fieldRanging from 0 to 39 years
Discount rate10%
were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2023.
Unobservable inputs to the Company's fair value assessmentassessments are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gascommodity prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
For the nine months ended September 30, 2017 and 2016,2022, the Company determined the carrying amountsamount of certain proved properties werea property in an emerging play was not recoverable from future cash flows and therefore were impaired. Impairmentswas impaired in the amount of proved properties amounted to $82.3$11.8 million, forall of which was recognized in the 2022 first quarter. For the three and nine months ended September 30, 2017, all of which were recognized prior to the 2017 third quarter. For the three months ended September 30, 2017,2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company’sCompany's proved crude oil and natural gas properties for that period. The 2017 year to date impairments reflect fair value adjustments primarily concentrated in the Arkoma Woodford field ($81.2 million, all in the second quarter) and various non-core areas in the North and South regions ($1.1 million). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million.2021 periods.
Impairments of proved properties totaled $2.9 million for year to date 2016, all of which were recognized in the 2016 third quarter primarily for properties in a non-core area of the North region. The impaired properties were written down to their estimated fair value at the time of impairment of approximately $0.7 million.
Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 20172022 and 2016,2021, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects 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.
15
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive income (loss).
  Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Proved property impairments $—
 $2,895
 $82,340
 $2,895
Unproved property impairments 35,130
 54,794
 127,479
 199,833
Total $35,130
 $57,689
 $209,819
 $202,728
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

operations.
 Three months ended September 30,Nine months ended September 30,
In thousands2022202120222021
Proved property impairments$— $— $11,821 $— 
Unproved property impairments12,794 7,945 41,047 30,991 
Total$12,794 $7,945 $52,868 $30,991 
Financial Instruments Not Recorded at Fair Value
The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.
 September 30, 2017 December 31, 2016 September 30, 2022December 31, 2021
In thousands Carrying
Amount		 Estimated Fair Value Carrying
Amount		 Estimated Fair ValueIn thousandsCarrying
Amount		Estimated Fair ValueCarrying
Amount		Estimated Fair Value
Debt:  Debt:
Revolving credit facility $938,000
 $938,000
 $905,000
 $905,000
Term loan 499,329
 500,000
 498,865
 500,000
Note payable 10,531
 10,500
 12,176
 10,200
5% Senior Notes due 2022 1,997,476
 2,030,700
 1,997,188
 2,020,400
Credit facilityCredit facility$— $— $500,000 $500,000 
Notes payableNotes payable20,627 18,800 22,356 22,000 
4.5% Senior Notes due 2023 1,486,134
 1,508,900
 1,484,524
 1,474,800
4.5% Senior Notes due 2023635,351 632,900 648,078 670,200 
3.8% Senior Notes due 2024 991,764
 968,400
 990,964
 929,400
3.8% Senior Notes due 2024891,110 866,100 908,061 950,000 
2.268% Senior Notes due 20262.268% Senior Notes due 2026793,698 681,600 792,621 795,200 
4.375% Senior Notes due 20284.375% Senior Notes due 2028992,772 894,900 991,880 1,082,100 
5.75% Senior Notes due 20315.75% Senior Notes due 20311,483,453 1,351,800 1,482,319 1,769,600 
2.875% Senior Notes due 20322.875% Senior Notes due 2032792,057 583,000 791,521 780,500 
4.9% Senior Notes due 2044 691,315
 635,400
 691,199
 607,600
4.9% Senior Notes due 2044692,204 505,200 692,056 781,500 
Total debt $6,614,549
 $6,591,900
 $6,579,916
 $6,447,400
Total debt$6,301,272 $5,534,300 $6,828,892 $7,351,100 
The fair valuesvalue of revolving credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.
The fair value of the notenotes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notenotes payable and an assumed discount rate. The fair value of the notenotes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the notenotes payable is classified as Level 3 in the fair value hierarchy.
The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”)Company's senior notes are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
16
Note 6. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $34.0 million and $37.3 million at September 30, 2017 and December 31, 2016, respectively, consists of the following.
In thousands September 30, 2017 December 31, 2016
Revolving credit facility $938,000
 $905,000
Term loan 499,329
 498,865
Note payable 10,531
 12,176
5% Senior Notes due 2022 1,997,476
 1,997,188
4.5% Senior Notes due 2023 1,486,134
 1,484,524
3.8% Senior Notes due 2024 991,764
 990,964
4.9% Senior Notes due 2044 691,315
 691,199
Total debt $6,614,549
 $6,579,916
Less: Current portion of long-term debt 2,268
 2,219
Long-term debt, net of current portion $6,612,281
 $6,577,697
Revolving Credit Facility
The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at September 30, 2017, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. Debt
The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $48.6 million and $54.2 million at September 30, 2022 and December 31, 2021, respectively, consists of the following.
In thousandsSeptember 30, 2022December 31, 2021
Credit facility$— $500,000 
Notes payable20,627 22,356 
4.5% Senior Notes due 2023 (1)635,351 648,078 
3.8% Senior Notes due 2024891,110 908,061 
2.268% Senior Notes due 2026793,698 792,621 
4.375% Senior Notes due 2028992,772 991,880 
5.75% Senior Notes due 20311,483,453 1,482,319 
2.875% Senior Notes due 2032792,057 791,521 
4.9% Senior Notes due 2044692,204 692,056 
Total debt$6,301,272 $6,828,892 
Less: Current portion of long-term debt (1)637,739 2,326 
Long-term debt, net of current portion$5,663,533 $6,826,566 
(1) The Company's 2023 Notes, which have a face value of $636.0 million at September 30, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of September 30, 2022 along with the current portion of the Company's notes payable.

Credit Facility
On August 24, 2022, the Company amended its credit facility to increase the amount of aggregate commitments by $255 million from $2.0 billion to $2.255 billion and to replace LIBOR as a benchmark reference rate with Term SOFR, with all other terms, conditions, and covenants remaining substantially unchanged. The Company's credit facility, which matures in October 2026, is unsecured and has no borrowing base requirement subject to redetermination.
The Company had no outstanding borrowings on its credit facility at September 30, 2022.
Credit facility borrowings, if any, bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at September 30, 2017 was 2.99%.
The Company had approximately $1.81 billion of borrowing availability on its revolving credit facility at September 30, 2017 and incurs commitment fees based on currently assigned credit ratings of 0.30%0.20% per annum on the daily average amount of unused borrowing availability under its revolving credit facility.availability.
The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at September 30, 2017.2022.
Senior Notes
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at September 30, 2017.2022. 
2023 Notes2024 Notes2026 Notes2028 Notes2031 Notes2032 Notes2044 Notes
Face value (in thousands)$636,000$893,126$800,000$1,000,000$1,500,000$800,000$700,000
Maturity dateApril 15, 2023June 1, 2024November 15, 2026January 15, 2028January 15, 2031April 1, 2032June 1, 2044
Interest payment datesApril 15, Oct 15June 1, Dec 1May 15, Nov 15Jan 15, July 15Jan 15,
Jul 15		April 1, Oct 1June 1, Dec 1
Make-whole redemption period (1)Jan 15, 2023Mar 1, 2024Nov 15, 2023Oct 15, 2027Jul 15, 2030January 1. 2032Dec 1, 2043
17
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
  2022 Notes (1) 2023 Notes 2024 Notes 2044 Notes
Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $700,000
Maturity date  Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044
Interest payment dates  March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1
Make-whole redemption period (2)  — Jan 15, 2023 Mar 1, 2024 Dec 1, 2043
(1)At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
(1)The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.
(2)At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The indentures governing the Company'sCompany’s senior notes contain covenants that, among other things, limit the Company'sCompany’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. The senior noteThese covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at September 30, 2017. Three2022.
The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned subsidiaries Banner(Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations,SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, and Parsley SoDe Water LLC) fully and unconditionally guarantee the senior notes on a joint and several basis. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company’s other subsidiaries, the value of whose assets, equity, and results of operations attributable to the Company are minor,not material, do not guarantee the senior notes.
Term LoanRetirement of Senior Notes
2022
In November 2015,the second quarter of 2022, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions, including $13.6 million face value of its 2023 Notes at an aggregate cost of $13.9 million and $17.9 million face value of its 2024 Notes at an aggregate cost of $18.3 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax losses on extinguishment of debt totaling $0.4 million related to the repurchases, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the repurchased notes. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the unaudited condensed consolidated statements of operations.
2021
In January 2021, the Company redeemed $400.0 million principal amount of its outstanding 2022 Notes and subsequently redeemed the remaining $230.8 million principal amount of its 2022 Notes in April 2021. The Company recognized pre-tax losses on extinguishment of debt totaling $0.3 million related to the redemption, which included the pro-rata write-off of deferred financing costs and unamortized debt premium associated with the redeemed notes.
Notes payable
In June 2020, the Company borrowed $500an aggregate of $26.0 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at September 30, 2017 was 2.76%.
The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at September 30, 2017.
Note Payable
In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under atwo 10-year amortizing term loanloans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The
Continental Resources, Inc. loans mature in May 2030 and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

loan bearsbear interest at a fixed rate of 3.14%3.50% per annum.annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.3and, accordingly, $2.4 million is reflectedincluded as a current liability underin the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of September 30, 2017.2022 associated with the loans.
Note 7.9. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of September 30, 2017. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.
Drilling commitments – As of September 30, 2017, the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future commitments as of September 30, 2017 total approximately $117 million, of which $26 million is expected to be incurred in the remainder of 2017, $61 million in 2018, $29 million in 2019, and $1 million in 2020.
Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. TheCertain of the commitments, which have varying terms extending as far as 2028,2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of September 30, 20172022 under the arrangements amount to approximately $1.2$1.13 billion, of which $57$72 million is expected to be incurred in the remainder of 2017, $2492022, $282 million in 2018, $2342023, $262 million in 2019, $1012024, $164 million in 2020, $892025, $139 million in 2021,2026, and $424$214 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
Litigation– In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack These commitments do not qualify as leases under ASC Topic 842 and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that didare not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearingrecognized on the “hybrid” class certification was held on June 1 and 2, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017, to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” The case remains stayed and briefing on the Second Amended motion is not anticipated in the immediate future. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. It is reasonably possible one or more events may occur in the near term that could impact the Company’s ability to estimate the potential effect this matter could have, if any, on its financial condition, results of operations or cash flows. Plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes the case meets the requirements for a class action and continues to vigorously defend the case. An unsuccessful mediation was conducted on December 7, 2015. The parties continue to negotiate a possible resolution to the case. However, it is unclear and unforeseeable whether the parties' efforts will result in settlement and the Company will continue to defend the case on all merits and certification issues and, absent settlement, intends to defend the case to a final judgment.Company's balance sheet.
18
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Strategic investment – See Note 13. Equity Investment for discussion of future spending commitments associated with a strategic investment announced by the Company in the first quarter of 2022.
Litigation
In December 2017, the Company filed an action in Garfield County, Oklahoma state court against Hiland Partners Holdings, LLC (“Hiland”), a subsidiary of Kinder Morgan, Inc. The Company alleged breach of contract and fraud. The parties entered into a settlement agreement in June 2018, under which Continental agreed to release its claims in exchange for Hiland’s construction of certain infrastructure projects by November 1, 2020. After such deadline passed, Continental filed an amended petition asserting the original claims and additional claims for breach of contract. On September 14, 2022, the parties entered into a confidential settlement agreement, including an unconditional release and dismissal of the litigation with prejudice.
In March 2022, the Company was named as a defendant in a case filed in the U.S. District Court for the Northern District of California by gasoline consumer plaintiffs alleging that, beginning in March 2020, the Company and the other named defendants conspired with Russia, OPEC and others to raise the price of oil and gasoline by reducing the supply of these products. The plaintiffs are seeking unspecified damages and injunctive relief. On July 1, 2022, the Company, together with other named defendants, filed motions to dismiss. The Company intends to vigorously defend the case.
The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of September 30, 20172022, and December 31, 2016,2021, the Company had recordedrecognized a liability in the condensed consolidated balance sheets under the captionwithin “Other noncurrent liabilities” of $6.8$10.1 millionand $6.5$7.9 million, respectively, for various matters, none of which are believed to be individually significant.
Litigation pertaining to take-private transaction
Transactions such as the Hamm Family's proposed take-private transaction described in Note 1. Organization and Nature of Business—Recent Developments often attract litigation and demands from minority shareholders. On August 25, 2022, Walter T. Doggett, on behalf of himself and a class of all other similarly situated public shareholders of the Company (“Doggett”), filed a class action petition in the District Court of Oklahoma County in the State of Oklahoma against Harold G. Hamm, as the controlling shareholder of the Company, for alleged breaches of fiduciary duties in connection with the previously described take-private transaction. Doggett seeks, among other things: (i) an injunction against the consummation of the proposed transaction or, if the proposed transaction is consummated, monetary damages; (ii) reimbursement for the costs and disbursements of bringing the lawsuit, including reasonable attorneys’ and experts’ fees; and (iii) other equitable relief. Mr. Hamm intends to defend himself vigorously against this lawsuit.
On August 11, 2022, Pembroke Pines Firefighters & Police Officers Pension Fund (“Pembroke”), a beneficial owner of Company shares, delivered a letter (the “Request”) to the Company requesting the inspection of certain of its books and records to investigate potential breaches of fiduciary duties by the Company’s Board of Directors, senior management, and Mr. Hamm in connection with the proposed take-private transaction. On August 18, 2022, the Company responded. On October 20, 2022, Pembroke updated the Request, and the Company responded on October 27, 2022.
On October 26, 2022, Shiva Stein (“Stein”) filed a complaint in the United States District Court for the Southern District of New York against the Company, Harold G. Hamm, William B. Berry, Tim Taylor, John T. McNabb II, Lon McCain, Mark E. Monroe, and Shelly Lambertz (collectively, the “Company Parties”), for their alleged violations of Sections 14(e), 14(d), and 20(a) of the Securities Exchange Act of 1934, in connection with the proposed take-private transaction. Stein seeks, among other things: (i) an injunction against the consummation of the proposed transaction unless and until the disclosure of purported material information allegedly omitted from the Solicitation Statement; (ii) rescission of the Merger Agreement and monetary damages related thereto; (iii) an accounting of damages related to the Company Parties’ alleged wrongdoing; and (iv) the costs and disbursements of bringing the lawsuit, including reasonable attorneys’ and expert fees and expenses. The Company Parties intend to vigorously defend the lawsuit.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
19
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements
Note 8.10. Stock-Based Compensation
On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncements for a discussion of the impact of adoption.
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan as amended ("2013 Plan") as discussed below.and 2022 Long-Term Incentive Plan ("2022 Plan"). The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss),operations, was $11.9$16.7 million and $13.2$14.3 million for the three months ended September 30, 20172022 and 2016,2021, respectively, and $32.5$60.8 million and $34.3$44.9 million for the nine months ended September 30, 20172022 and 2016,2021, respectively.
In May 2013,2022, the Company adopted the 20132022 Plan and reserved 19,680,072a maximum of 15,818,785 shares of common stock that may be issued pursuant to the plan. The 2022 Plan replaced the Company's 2013 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2013 Plan. However, restricted stock awards granted under the 2013 Plan prior to the adoption of the 2022 Plan will remain outstanding in accordance with their terms. Subject to limited exceptions, the 2022 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. As of September 30, 2017,2022, the Company had 14,561,80215,657,882 shares of common stock available for long-term incentive awards to employees and directors under the 20132022 Plan.
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan, 2022 Plan, or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one1 to three3 years.
A summary of changes in non-vested restricted shares outstanding for the nine months ended September 30, 20172022 is presented below.
Number of
non-vested
shares		Weighted average
grant-date
fair value
 Number of
non-vested
shares		 Weighted average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2016 3,913,634
 $37.12
Non-vested restricted shares outstanding at December 31, 2021Non-vested restricted shares outstanding at December 31, 20215,894,508 $28.38 
Granted 1,518,824
 44.66
Granted1,539,017 56.11 
Vested (816,408) 58.17
Vested(1,678,380)36.67 
Forfeited (573,614) 37.36
Forfeited(366,207)27.49 
Non-vested restricted shares outstanding at September 30, 2017 4,042,436
 $35.67
Non-vested restricted shares outstanding at September 30, 2022Non-vested restricted shares outstanding at September 30, 20225,388,938 $33.77 
The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the nine months ended September 30, 20172022 was approximately $37.2$94 million. As of September 30, 2017,2022, there was approximately $68$95 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.41.3 years.
20
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Note 11. Shareholders' Equity
Note 9. Accumulated Other Comprehensive Income (Loss)Share Repurchases
Adjustments resulting fromIn May 2019 the processBoard approved the initiation of translating foreign functional currency financial statements into U.S. dollars are includeda share repurchase program to acquire up to $1 billion of the Company's common stock beginning in "Accumulated other comprehensive income (loss)" within shareholders’ equityJune 2019. On February 8, 2022, the Board approved an increase in the condensed consolidated balance sheetssize of the program from $1.0 billion to $1.5 billion, inclusive of cumulative amounts repurchased as of February 8, 2022.
2022
During the three months ended March 31, 2022 the Company repurchased and "Other comprehensive income, netretired approximately 1.84 million shares of tax"its common stock at an aggregate cost of $99.9 million. No additional share repurchases have been made subsequent to March 31, 2022. The Company has repurchased and retired a cumulative total of approximately 18.81 million shares at an aggregate cost of $540.9 million since the inception of its share repurchase program in the unaudited condensed consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) forJune 2019.
2021
During the three and nine months ended September 30, 20172021, the Company repurchased and 2016:retired approximately 1.9 million shares of its common stock at an aggregate cost of $65.3 million.
Dividend Payments
  Three months ended September 30, Nine months ended September 30,
In thousands 2017 2016 2017 2016
Beginning accumulated other comprehensive income (loss), net of tax $67
 $(2,903) $(260) $(3,354)
Foreign currency translation adjustments 202
 418
 529
 869
Income taxes (1) —
 —
 —
 —
Other comprehensive income, net of tax 202
 418
 529
 869
Ending accumulated other comprehensive income (loss), net of tax $269
 $(2,485) $269
 $(2,485)
2022
(1)A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income.
On February 9, 2022, the Company declared a quarterly cash dividend of $0.23 per share on its outstanding common stock, which amounted to $82.5 million and was paid on March 4, 2022 to shareholders of record as of February 22, 2022.
On April 27, 2022, the Company declared a quarterly cash dividend of $0.28 per share on its outstanding common stock, which amounted to $100.1 million and was paid on May 23, 2022 to shareholders of record as of May 9, 2022.
On July 27, 2022, the Company declared a quarterly cash dividend of $0.28 per share on its outstanding common stock, which amounted to $100.1 million and was paid on August 22, 2022 to shareholders of record as of August 8, 2022.
2021
On April 27, 2021, the Company declared a quarterly cash dividend of $0.11 per share on its outstanding common stock, which amounted to $40.0 million and was paid on May 24, 2021 to shareholders of record as of May 10, 2021.
On July 30, 2021, the Company declared a quarterly cash dividend of $0.15 per share on its outstanding common stock, which amounted to $54.1 million and was paid on August 20, 2021 to shareholders of record as of August 10, 2021.
Note 10.12. Income Taxes
The Company's provision for income taxes and resulting effective tax rates were as follows for the periods presented.
 Three months ended September 30,Nine months ended September 30,
In thousands, except tax rates2022202120222021
Current tax provision$139,831 $— $478,656 $— 
Deferred tax provision183,559 115,641 425,089 291,116 
Provision for income taxes323,390 115,641 903,745 291,116 
Effective tax rate24.1 %23.8 %24.2 %24.0 %
The Company computes its quarterly income tax provision under the effective tax rate method based on applying an anticipated annual effective tax rate to year-to-date pre-tax income, except for discrete items. Income taxes for discrete items are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amountscomputed and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in incomerecorded in the period that includesin which the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.specific transaction occurs.
The Company's (provision) benefit for income taxes totaled ($6.8) million and $25.1 million for the three and nine months ended September 30, 2017, respectively. The Company's benefit for income taxes totaled $65.3 million and $259.3 million for the three and nine months ended September 30, 2016, respectively. These amounts differeffective tax rate differs from the amounts computed by applying the United States statutory federal incomestatutory tax rate due to netthe effect of state income (loss) before income taxes. The sourcestaxes, equity compensation, changes in valuation allowances, and other tax effects of the differences areitems as reflected in the table below:below.
21
  Three months ended September 30, Nine months ended September 30,
$ in thousands 2017 Tax rate % 2016 Tax rate % 2017 Tax rate % 2016 Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate of 35% $(6,087) 35.0% $61,214
 35.0% $27,136
 35.0% $240,311
 35.0%
State income taxes, net of federal benefit (522) 3.0% 5,247
 3.0% 2,326
 3.0% 20,598
 3.0%
Tax deficiency from stock-based compensation (1) (134) 0.8% —
 — % (3,907) (5.0%) —
 — %
Canadian valuation allowance (2) (68) 0.4% (665) (0.4%) (325) (0.4%) (959) (0.1%)
Effect of differing statutory tax rate in Canada (34) 0.1% (313) (0.2%) (156) (0.3%) (437) (0.1%)
Other, net 75
 (0.4%) (207) (0.1%) (11) —% (259) — %
(Provision) benefit for income taxes $(6,770) 38.9% $65,276
 37.3% $25,063
 32.3% $259,254
 37.8%
(1)
The Company recognized $0.1 million and $3.9 million of tax deficiencies from stock-based compensation as income tax expense for the three and nine months ended September 30, 2017, respectively, in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements.
(2)Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.
Continental Resources, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

 Three months ended September 30,Nine months ended September 30,
In thousands, except tax rates2022202120222021
Income before income taxes$1,343,888 $486,162 $3,741,441 $1,211,386 
U.S. federal statutory tax rate21.0 %21.0 %21.0 %21.0 %
Expected income tax provision based on U.S. federal statutory tax rate282,216 102,094 785,703 254,391 
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit47,097 17,109 131,200 43,559 
Equity compensation(282)(11)(4,659)6,126 
Other, net(5,641)(2,086)(8,499)(7,006)
Change in valuation allowance— (1,465)— (5,954)
Provision for income taxes$323,390 $115,641 $903,745 $291,116 
Effective tax rate24.1 %23.8 %24.2 %24.0 %
Note 11. Property Dispositions13. Equity Investment
2017
In September 2017March 2022 the Company sold non-strategic propertiesbegan investing in an affiliate of Summit Carbon Solutions (“Summit”) to develop carbon capture and sequestration infrastructure. Summit was founded in 2020 with the goal of decarbonizing the biofuel and agriculture industries and seeks to lower greenhouse gas emissions by connecting industrial facilities via strategic infrastructure to capture, transport, and store carbon dioxide (“CO2”) safely and permanently in the Arkoma Woodford areaMidwestern United States.
The Company has committed to invest a third party for cash proceedstotal of $65.3 million.$250 million with Summit over 2022 and 2023 to fund a portion of Summit's development and construction of capture, transportation, and sequestration infrastructure, while also leveraging the Company's operational and geologic expertise to facilitate the underground storage of CO2. Summit intends to primarily capture CO2 from ethanol plants and other industrial sources in Iowa, Nebraska, Minnesota, North Dakota, and South Dakota, and aggregate and transport the CO2 to North Dakota via pipeline, where it will be sequestered in subsurface geologic formations. The sale included approximately 26,000 net acres of leaseholdproject is expected to become operational in Atoka, Coal, Hughes, and Pittsburg Counties of Oklahoma and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with2024.
During the transaction,nine months ended September 30, 2022, the Company recognized a pre-tax loss of $3.8 million. The disposed properties represented an immaterial portion of the Company’s proved reserves.
In September 2017 the Company reached an agreementcontributed approximately $151 million toward its $250 million commitment to sell non-core leaseholdSummit, which is included in the STACK playcaption “Investment in Blaine County, Oklahoma to a third party for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resultingunconsolidated affiliates” in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gain on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time the Company received the remaining $59.9 million of proceeds. In connection with theunaudited condensed consolidated balance sheet. Upon completion of the transaction in October 2017,Summit's ongoing equity raises, the Company expects to recognize an additional pre-tax gainhold approximately 22% ownership interest in the equity of approximately $52 million, which will be reflectedSummit Carbon Holdings, the parent company of Summit Carbon Solutions. The Company accounts for its investment in fourth quarter 2017 results.Summit under the equity method of accounting. The disposed properties represented anCompany’s share of earnings/losses from its investment was immaterial portion offor the Company’s productionthree and proved reserves.nine months ended September 30, 2022.
Additionally, in September 2017 the Company sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.5 million pre-tax gain associated with the transaction.
22
2016
In September 2016 the Company sold non-strategic properties in North Dakota and Montana to a third party for cash proceeds of $214.8 million, with no gain or loss recognized. The sale included approximately 68,000 net acres of leasehold primarily in western Williams County, North Dakota, and approximately 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also included producing properties with production totaling approximately 2,700 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves.

In April 2016 the Company sold approximately 132,000 net acres of undeveloped leasehold acreage located in Wyoming to a third party for cash proceeds of $110.0 million. In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million. The disposed properties had no production or proved reserves.


ITEM 2.
ITEM 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2016. Our operating results for the periods discussed below may not be indicative of future performance. 2021.
The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report if any, and in our Annual Report onForm 10-Q for the quarter ended June 30, 2022 and our Form 10-K for the year ended December 31, 2016,2021, 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.gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. Our operationscommon stock currently trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.
Recent developments
On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on October 24, 2022, Merger Sub commenced a tender offer to purchase any and all of the outstanding shares of the Company’s common stock, other than: (i) shares of common stock owned by the Hamm Family and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans for $74.28 per share in cash. There are primarily focused on explorationapproximately 58 million shares of Continental's common stock that are subject to the tender offer. Subject to the satisfaction of customary closing conditions, the transaction is expected to close prior to December 31, 2022. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 1. Organization and development activitiesNature of Business—Recent Developments and Liquidity and Capital Resources—Recent Developments below for additional information.
Third Quarter 2022 Highlights
Financial and operating highlights for the third quarter of 2022 are summarized below.
•Generated $2.22 billion in operating cash flows in the Bakken field2022 third quarter, bringing year to date operating cash flows to $5.46 billion.
•Exited the third quarter with approximately $4.0 billion of North Dakotaliquidity, representing $1.81 billion of cash and Montana$2.25 billion of borrowing capacity on our undrawn credit facility.
•Production averaged 414,441 Boe per day for the 2022 third quarter, a 4% sequential increase from the 2022 second quarter and 25% higher than the SCOOP2021 third quarter.

Financial and STACK areasOperating Metrics

Commodity prices have increased significantly in 2022 compared to 2021 levels resulting from the ongoing rebalancing of Oklahoma.
Business Environmentcrude oil and Outlook
natural gas supply and demand fundamentals coupled with the disruption of global hydrocarbon markets prompted by the outbreak of military conflict between Russia and Ukraine. The increase in commodity prices contributed to improved operating results and cash flows for the three and nine month periods ended September 30, 2022 compared to the comparable 2021 periods. Additionally, our property acquisitions in the Permian Basin and Powder River Basin over the past year contributed to increased production, revenues, and cash flows in 2022 compared to the 2021 periods. Commodity prices remain volatile and unpredictable dueand our operating results for the three and nine month periods ended September 30, 2022 may not be indicative of future results. Given the uncertainty surrounding the Russia/Ukraine conflict and ongoing volatility in commodity prices, we are unable to domesticpredict the extent to which the conflict or other factors will have on the Company’s future performance.
23

The following table contains financial and global supplyoperating metrics for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
 Three months ended September 30,Nine months ended September 30,
 2022202120222021
Average daily production:
Crude oil (Bbl per day)200,464 157,153 197,869 158,609 
Natural gas (Mcf per day) (1)1,283,865 1,045,521 1,190,516 1,004,954 
Crude oil equivalents (Boe per day)414,441 331,407 396,288 326,102 
Average net sales prices (2):
Crude oil ($/Bbl)$89.46 $66.48 $95.51 $60.79 
Natural gas ($/Mcf) (1)(3)$8.56 $4.62 $7.63 $4.38 
Crude oil equivalents ($/Boe)$69.91 $46.07 $70.59 $43.04 
Crude oil net sales price discount to NYMEX ($/Bbl)$(2.16)$(4.09)$(2.63)$(4.13)
Natural gas net sales price premium to NYMEX ($/Mcf) (1)(3)$0.37 $0.62 $0.74 $1.17 
Production expenses ($/Boe)$4.34 $3.39 $4.22 $3.29 
Production and ad valorem taxes (% of net crude oil and natural gas sales)7.5 %7.3 %7.4 %7.3 %
Depreciation, depletion, amortization and accretion ($/Boe)$12.79 $15.29 $12.91 $16.26 
Total general and administrative expenses ($/Boe)$1.79 $1.92 $1.91 $1.87 
 (1)     Natural gas production volumes, sales volumes, and demand factors. In light ofnet sales prices presented throughout management's discussion and analysis reflect the challenges facing our industry, our primary business strategiescombined value for 2017 focus on: (1) high-grading investments based on rates of return and opportunities to convert undeveloped acreage to acreage held by production, (2) improving cash flows through operating efficiencies, cost reductions, and optimized completions, (3) managing capital spending to minimize the incurrence of new incremental debt and maintain ample liquidity and financial flexibility, and (4) pursuing opportunities to further reduce debt using proceeds from potential sales of non-strategic assets.
2017 Highlights
Production
Crude oilnatural gas and natural gas productionliquids.
(2)    See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.
(3)     Amounts for the 2022 periods include the recognition of $95 million of natural gas revenues in the 2022 third quarter in conjunction with the resolution of a legal matter, which increased our natural gas net sales prices by $0.80 per Mcf and $0.29 per Mcf for the third quarter of 2017 averaged 242,788 Boe per day, an increase of 7% from the second quarter of 2017 and 17% higher than the third quarter of 2016. Yearyear to date production averaged 227,692 Boe per day, a 4% increase from the comparable 2016 period.periods of 2022, respectively.
Average daily crude oil production increased 21% in the third quarter of 2017Three months ended September 30, 2022 compared to the third quarterthree months ended September 30, 2021
Results of 2016, while average daily natural gas production increased 12%. Third quarter 2017 average daily crude oil production increased 12% compared to the second quarter of 2017 reflecting increased well completion activities in North Dakota Bakken, while average daily natural gas production increased 1%.Operations
Crude oil represented 58% of our productionThe following table presents selected financial and operating information for the 2017 third quarter compared to 55% for the 2017 second quarter and 56% for the 2016 third quarter.periods presented.
24

 Three months ended September 30,
In thousands20222021
Crude oil, natural gas, and natural gas liquids sales$2,767,262 $1,456,181 
Loss on derivative instruments, net(337,778)(127,110)
Crude oil and natural gas service operations17,747 12,341 
Total revenues2,447,231 1,341,412 
Operating costs and expenses(1,037,116)(795,701)
Other expenses, net(66,227)(59,549)
Income before income taxes1,343,888 486,162 
Provision for income taxes(323,390)(115,641)
Income before equity in net loss of affiliate1,020,498 370,521 
Equity in net loss of affiliate(660)— 
Net income1,019,838 370,521 
Net income attributable to noncontrolling interests6,731 1,193 
Net income attributable to Continental Resources$1,013,107 $369,328 
Production volumes:
Crude oil (MBbl)18,443 14,458 
Natural gas (MMcf)118,116 96,188 
Crude oil equivalents (MBoe)38,129 30,489 
Sales volumes:
Crude oil (MBbl)18,674 14,404 
Natural gas (MMcf)118,116 96,188 
Crude oil equivalents (MBoe)38,360 30,435 
Production
The following table summarizes the changes in our average daily Boe production by major operating area.
Boe production per day 3Q 2017 2Q 2017 % Change from 2Q 2017 3Q 2016 % Change from 3Q 2016
Bakken 136,851
 119,861
 14% 107,929
 27%
SCOOP 57,283
 61,107
 (6%) 67,462
 (15%)
STACK 35,619
 31,934
 12% 17,680
 101%
All other 13,035
 13,311
 (2%) 14,769
 (12%)
Total 242,788
 226,213
 7% 207,840
 17%
Revenues
Crude oil and natural gas revenues for the 2017 third quarter increased 39% compared to the 2016 third quarter driven by a 21% increase in realized commodity prices coupled with a 16% increase in total sales volumes.
Year to date crude oil and natural gas revenues increased 37% from the comparable 2016 period driven by a 32% increase in realized commodity prices coupled with a 3% increase in total sales volumes.


Average crude oil sales pricesarea for the third quarter and year to date periods of 2017 increased 15% and 29%, respectively, fromperiod.
Boe production per day3Q 20223Q 2021% Change
Bakken175,383 167,604 5 %
Anadarko Basin162,829 152,522 7 %
Powder River Basin31,234 4,937 533 %
Permian Basin38,948 — — %
All other6,047 6,344 (5 %)
Total414,441 331,407 25 %
The following table summarizes the comparable 2016 periods.
Crude oil sales volumeschanges in our production by product for the third quarter and year to date periods of 2017 increased 19% and decreased 3%, respectively, from the comparable 2016 periods.period.
Average natural gas sales prices for the third quarter and year to date periods of 2017 increased 36% and 77%, respectively, from the comparable 2016 periods.
 Three months ended September 30,Volume
increase		Volume
percent
increase
 20222021
 VolumePercentVolumePercent
Crude oil (MBbl)18,443 48 %14,458 47 %3,985 28 %
Natural gas (MMcf)118,116 52 %96,188 53 %21,928 23 %
Total (MBoe)38,129 100 %30,489 100 %7,640 25 %
Natural gas sales volumes for the third quarter and year to date periods of 2017 increased 12% and 13%, respectively, from the comparable 2016 periods.
Operating cash flows
Cash flows from operating activities totaled $431.4 million for the third quarter of 2017, 3% lower than operating cash flows of $446.4 million for the 2017 second quarter and 18% higher than 2016 third quarter operating cash flows of $366.2 million.
Capital expenditures and drilling activity
Non-acquisition capital expenditures totaled $520.6 million for the third quarter of 2017 bringing year to date 2017 non-acquisition capital expenditures to $1,499.5 million compared to $768.0 million for year to date 2016.
For the third quarter of 2017 we participated in the drilling and completion of 184 gross (80 net) wells, bringing our 2017 year to date total to 425 gross (163 net) wells compared to 256 gross (64 net) wells for year to date 2016.
Property dispositions
In September 2017 we sold non-strategic properties in the Arkoma Woodford area of Oklahoma to a third party for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with the transaction, we recognized a pre-tax loss of $3.8 million.
In September 2017 we reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma to a third party for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gain on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time we received the remaining $59.9 million of proceeds. In connection with the completion of the transaction in October 2017, we expect to recognize an additional pre-tax gain of approximately $52 million, which will be reflected in fourth quarter 2017 results.
In September 2017 we sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.5 million pre-tax gain associated with the transaction.
Credit facility and liquidity
At September 30, 2017, we had$10.8 millionof cash and cash equivalents and $1.81 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $938 million of outstanding borrowings on our credit facility at September 30, 2017 compared to $880 million at June 30, 2017 and $905 million at December 31, 2016.At October 31, 2017, outstanding credit facility borrowings totaled $895 million, leaving approximately $1.85 billion of borrowing availability at that date.



Financial and operating highlights
We use a variety of financial and operating measures to assess our performance. Among these measures are:
Volumes of crude oil and natural gas produced;
Crude oil and natural gas prices realized; and
Per unit operating and administrative costs.
The following table contains financial and operating highlights for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
  Three months ended September 30, Nine months ended September 30,
  2017 2016 2017 2016
Average daily production:     
 
Crude oil (Bbl per day) 140,611
 116,277
 128,476
 131,873
Natural gas (Mcf per day) 613,060
 549,374
 595,294
 524,441
Crude oil equivalents (Boe per day) 242,788
 207,840
 227,692
 219,280
Average sales prices: 
 
 
 
Crude oil ($/Bbl) $43.27
 $37.66
 $43.26
 $33.51
Natural gas ($/Mcf) $2.74
 $2.02
 $2.78
 $1.57
Crude oil equivalents ($/Boe) $31.86
 $26.42
 $31.67
 $23.91
Crude oil sales price discount to NYMEX ($/Bbl) $(4.98) $(7.27) $(6.07) $(7.44)
Natural gas sales price discount to NYMEX ($/Mcf) $(0.26) $(0.80) $(0.37) $(0.73)
Production expenses ($/Boe) $3.82
 $3.50
 $3.86
 $3.66
Production taxes (% of oil and gas revenues) 7.3% 6.8% 6.8% 7.3%
DD&A ($/Boe) $19.00
 $21.66
 $19.31
 $22.00
Total general and administrative expenses ($/Boe) (1) $1.99
 $2.32
 $2.10
 $1.88
Net income (loss) (in thousands) $10,621
 $(109,621) $(52,467) $(427,348)
Diluted net income (loss) per share $0.03
 $(0.30) $(0.14) $(1.15)
(1)
Represents cash general and administrative expenses per Boe and non-cash equity compensation expenses per Boe. See Operating Costs and Expenses—General and Administrative Expenses below for additional discussion of these components.


Three months ended September 30, 2017 compared to the three months ended September 30, 2016
Results of Operations
The following table presents selected financial and operating information for the periods presented.
  Three months ended September 30,
In thousands, except sales price data 2017 2016
Crude oil and natural gas sales $704,818
 $505,892
Gain on crude oil and natural gas derivatives, net 8,602
 15,668
Crude oil and natural gas service operations 13,323
 4,639
Total revenues 726,743
 526,199
Operating costs and expenses (634,990) (619,382)
Other expenses, net (74,362) (81,714)
Income (loss) before income taxes 17,391
 (174,897)
(Provision) benefit for income taxes (6,770) 65,276
Net income (loss) $10,621
 $(109,621)
Production volumes: 
 
Crude oil (MBbl) 12,936
 10,698
Natural gas (MMcf) 56,401
 50,542
Crude oil equivalents (MBoe) 22,337
 19,121
Sales volumes: 
 
Crude oil (MBbl) 12,722
 10,724
Natural gas (MMcf) 56,401
 50,542
Crude oil equivalents (MBoe) 22,123
 19,148
Average sales prices: 
 
Crude oil ($/Bbl) $43.27
 $37.66
Natural gas ($/Mcf) 2.74
 2.02
Crude oil equivalents ($/Boe) 31.86
 26.42
Production
The following tables reflect our production by product and region for the periods presented.
  Three months ended September 30, Volume
increase		 Volume
percent
increase
  2017 2016  
  Volume Percent Volume Percent 
Crude oil (MBbl) 12,936
 58% 10,698
 56% 2,238
 21%
Natural gas (MMcf) 56,401
 42% 50,542
 44% 5,859
 12%
Total (MBoe) 22,337
 100% 19,121
 100% 3,216
 17%
             
  Three months ended September 30, Volume
increase		 Volume
percent
increase
  2017 2016  
  MBoe Percent MBoe Percent 
North Region 13,509
 60% 11,003
 58% 2,506
 23%
South Region 8,828
 40% 8,118
 42% 710
 9%
Total 22,337
 100% 19,121
 100% 3,216
 17%
The 21%28% increase in crude oil production forin the 2022 third quarter was primarily driven by increased production from propertiesour property acquisitions in North Dakota Bakken duethe Permian Basin and Powder River Basin over the past year, which contributed to an increase in well completion activitiesour 2022 third quarter production by 2,721 MBbls and 1,481 MBbls, respectively, compared to the timing of production commencing from new pad development projects, along with strong initial production results being achieved on new wells resulting from optimized completion technologies. Crude oil production in North Dakota Bakken increased 2,260 MBbls, or 32%, from the prior year2021 third quarter. Additionally, production from our South region properties in the STACK play increased 393 MBbls, or 108%, from the prior year third quarter due to additional wells being completed and producing as a result of an increase in our drilling and completion activities in that area. TheseThese increases were partially offset by decreased production from our North region properties in Montana Bakken and the Red River units due to natural declines in production coupled with reduced drilling


activities over the past year in response to low crude oil prices. Montana Bakken production decreased 135a 475 MBbls, or 20%15%, whiledecrease in crude oil production in the Red River units decreased 82 MBbls, or 9%, from the prior year third quarter. Additionally, crude oil production in SCOOP decreased 198 MBbls, or 12%,Anadarko Basin due to natural declinesa change in productionallocation of capital from oil-weighted projects to gas-weighted projects in the play over the past year and reduced drilling activities.the timing of well completions.
25

The 12%23% increase in natural gas production forin the 2022 third quarter was driven by increased production from our propertiesdue in part to the previously described property acquisitions over the past year. Properties acquired in the STACK play duePermian Basin and new well completions increased our 2022 third quarter production by 5,175 MMcf while properties acquired in the Powder River Basin and new well completions increased our production by 5,629 MMcf compared to additional wells being completed and producing subsequent to September 30, 2016.Natural gas production in STACK increased 7,544 MMcf, or 100%, over the prior year2021 third quarter. Additionally, natural gas production in North Dakota Bakkenthe Anadarko Basin increased 3,1808,538 MMcf, or 26%13%, in conjunction with the aforementioned increase in crude oiland Bakken natural gas production increased 2,566 MMcf, or 8%, over the prior year2021 third quarter. These increases were partially offset by reduced production from our SCOOP properties, which decreased 4,431 MMcf, or 16%, along with various other areas in our North and South regionsquarter due to natural declines in production and reduced drilling activitiesnew well completions over the past year.
In September 2017 we sold substantially all of our producing properties in the Arkoma Woodford area of Oklahoma. The sold properties comprised approximately 940 MMcf of our natural gas production for the three months ended September 30, 2017.
The increase in crude oil production as a percentage of our total production from 56% in the third quarter of 2016 to 58% in the third quarter of 2017 resulted from the significant increase in North Dakota Bakken production in recent months from increased well completion activities, which contributed to a 12% increase in our average daily crude oil production for the 2017 third quarter compared to the 2017 second quarter. Our properties in North Dakota Bakken typically produce a higher concentration of crude oil compared to our Oklahoma properties. Our crude oil production is expected to continue growing in relative significance for the remainder of 2017 based on our planned well completion activities in North Dakota Bakken in the 2017 fourth quarter.
Revenues
Our revenues consist of sales ofNet crude oil, natural gas, and natural gas gainsliquids sales and losses resulting from changes inrelated net sales prices presented below are non-GAAP measures. See the fair valuesubsequent section titled Non-GAAP Financial Measures for a discussion and calculation of ourthese measures.
Net crude oil, natural gas, and natural gas derivative instruments, and revenues associated with crude oil and natural gas service operations.
Crude Oil and Natural Gas Sales. Crude oil and natural gasliquids sales. Net sales totaled $2.68 billion for the third quarter of 2017 were $704.8 million,2022, a 39%91% increase fromcompared to net sales of $505.9 million$1.40 billion for the 20162021 third quarter due to significant increases in commoditynet sales prices and total sales volumes. If commodity prices remain at current levels, we expectvolumes as discussed below.
Total sales volumes for the third quarter of 2022 increased 7,925 MBoe, or 26%, compared to the 2021 third quarter primarily due to new wells added from our 2017property acquisitions over the past year. For the third quarter of 2022, our crude oil sales volumes increased 30% and our natural gas revenues will continue to be higher than 2016 levels, the extent of which is uncertain duesales volumes increased 23% compared to the unpredictable nature of commodity prices.2021 third quarter.
Our crude oil net sales prices averaged $43.27$89.46 per barrel in the 20172022 third quarter an increase of 15% compared to $37.66$66.48 per barrel for the 20162021 third quarter due to higher crude oilthe previously described increase in market prices andalong with improved price realizations.differentials. The differential between NYMEX West Texas Intermediate (“WTI”) calendar month crude oil prices and our realized crude oil net sales prices averaged $4.98improved to an average of $2.16 per barrel for the 20172022 third quarter compared to $7.27$4.09 per barrel for the 20162021 third quarter. The improved differential was primarily due to improvedquarter, reflecting strong price realizations resulting from new pipeline takeaway capacity and additional markets becoming available in 2017 for Bakken production, along with the growth inacross our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.assets.
Our natural gas net sales prices averaged $2.74$8.56 per Mcf for the 20172022 third quarter a 36% increase compared to $2.02$4.62 per Mcf for the 20162021 third quarter primarily due to higherthe previously described increase in market prices for natural gas and natural gas liquids (“NGLs”) and improved price realizations.prices. The discountdifference between our realized natural gasnet sales prices and NYMEX Henry Hub calendar month natural gas prices improved from $0.80was a premium of $0.37 per Mcf for the 20162022 third quarter compared to $0.26a premium of $0.62 per Mcf for the 20172021 third quarter. The majority of our natural gas production is sold at our lease locations to midstream purchasers withdecrease in premium was driven by price realizations impacted by the volume and value of NGLs that purchasers extract fromvolatility, wider basis differentials between prices received in our sales stream.markets and NYMEX settlement prices, and significant improvement in Henry Hub prices as compared to increases in NGL prices, have increased over prior year levelscausing the uplift in conjunction with increased crude oil prices and other factors, resulting in improved price realizations for our naturalfull gas sales stream comparedrelative to the prior year third quarter.
Total sales volumes for the third quarter of 2017 increased 2,975 MBoe, or 16%, compared to the 2016 third quarter, reflecting an increase in our pace of drilling and completion activities in 2017. For the third quarter of 2017, our crude oil sales volumes increased 19% from the comparable 2016 period, while our natural gas sales volumes increased 12%.
At various times we have stored crude oil due to pipeline line fill requirements, low commoditybenchmark prices or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes and caused crude oil sales volumes to be lower than crude oil production by 214 MBbls forless significant in the third quarter of 2017.current period.
Derivatives. Changes in natural gas Elevated commodity prices during the third quarter of 20172022 had a favorablesignificant unfavorable impact on the fair value of our natural gas derivatives, which resulted in positivenegative revenue adjustments of $8.6totaling $337.8 million for the period, representing $12.3


$226.1 million of cash gains partially offset by $3.7losses and $111.7 million of unsettled non-cash losses. Our revenues for the remainder of 2017 may continuelosses, compared to be significantly impacted, either positively or negatively, by changesnegative revenue adjustments totaling $127.1 million in the fair valuethird quarter of our derivative instruments as a result of volatility in natural gas prices.2021.
Crude oilOperating Costs 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 and the treatment and sale of lower quality reclaimed crude oil. Revenues associated with such activitiesExpenses
Production Expenses. Production expenses increased $8.7$63.1 million, from $4.6or 61%, to $166.3 million for the third quarter of 20162022 compared to $13.3$103.2 million for the third quarter of 20172021 due to an increase in industry production activities and changes in the nature, timing and extent of handling and treatment activities between periods.
Operating Costs and Expenses
Production Expenses. Production expenses increased $17.5 million, or 26%, from $67.0 million for the third quarter of 2016 to $84.5 million for the third quarter of 2017. Production expenses on a per-Boe basis increased to $3.82 for the 2017 third quarter compared to $3.50 for the 2016 third quarter. These increases resulted from an increase in the number of producing wells an increase infrom drilling activities and property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties prompted by the favorable commodity price environment. Production expenses on a per-Boe basis averaged $4.34 per Boe for the 2022 third quarter compared to $3.39 per Boe for the 2021 third quarter, the increase of which reflects higher workover-related activities, cost inflation, and a higher portionthe addition of ouroil-weighted production coming from wellsacquired in North Dakota Bakkenthe Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to wellsgas-weighted properties in Oklahoma.the Anadarko Basin.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased $16.7$98.2 million, or 48%96%, to $51.3$200.6 million for the third quarter of 20172022 compared to $34.6$102.4 million for the third quarter of 2016 primarily2021 due to higher crude oil and natural gas revenues resulting from increasesthe previously described increase in commodity prices and total sales volumes over the prior year period. Production taxes are generally based on the wellhead values ofsales. Our production and vary by state. Production taxes as a percentage of crude oil and natural gas revenues werenet sales averaged 7.5% for the third quarter of 2022, consistent with 7.3% for the third quarter of 2017 compared to 6.8% for the third quarter of 2016, the increase of which primarily resulted from a significant increase in production and revenues being generated in North Dakota in recent months which has higher production tax rates compared to Oklahoma. The production tax rate on new wells in North Dakota is currently 10% of crude oil revenues. The production tax rate on Oklahoma wells that commenced production after July 1, 2015 is currently 2% of crude oil and natural gas revenues for the first 36 months of production and 7% thereafter. Additionally, in May 2017 new legislation was enacted in Oklahoma that increased the production tax rate from 1% to 4% on wells that began producing between July 1, 2011 and July 1, 2015. The new 4% tax rate on these wells went into effect on July 1, 2017 and contributed to the increase in our average production tax rate for the third quarter of 2017.2021.
Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods presented.
 
Three months ended September 30,
In thousands
2017
2016
Geological and geophysical costs $1,389
 $3,960
Exploratory dry hole costs —
 27
Exploration expenses $1,389
 $3,987
The decrease in geological and geophysical expenses in 2017 was due to changes in the timing and amount of costs incurred by the Company and billed to joint interest owners between periods.
Depreciation, Depletion, Amortization and Accretion (“DD&A”).Accretion. Total DD&A increased $5.5$25.1 million, or 1%5%, to $420.2$490.5 million for the third quarter of 20172022 compared to $414.7$465.4 million for the third quarter of 20162021 primarily due to anthe previously described 26% increase in total sales volumes which waslargely offset by the impact from an increasea decrease in the volume of proved reserves over which costs are depletedour 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.
26


Three months ended September 30, Three months ended September 30,
$/Boe
2017 2016$/Boe20222021
Crude oil and natural gas $18.70
 $21.20
Crude oil and natural gas$12.51 $14.98 
Other equipment 0.23
 0.38
Other equipment0.20 0.22 
Asset retirement obligation accretion 0.07
 0.08
Asset retirement obligation accretion0.08 0.09 
Depreciation, depletion, amortization and accretion $19.00
 $21.66
Depreciation, depletion, amortization and accretion$12.79 $15.29 
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 by SEC 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. Upward revisions to
Our proved reserves in


2017 duehave been revised upward over the past year prompted by significant increases in part to an improvement infirst-day-of-the-month commodity prices contributed toand other factors, which, when coupled with improvements in capital efficiency and strong well productivity, resulted in a decrease in our DD&A rate for crude oil and natural gas properties in the third quarter of 20172022 compared to the third quarter of 2016. Additionally, improvements2021 and helped offset the additional DD&A recognized in drilling efficiencies and optimized completion technologies over the past year have resulted in a significant improvement in the quantity of proved reserves found and developed per dollar invested, which also contributed to the reduction in our DD&A rate in the current period.2022 from increased sales volumes.
Property Impairments. Total property impairments decreased $22.6increased $4.8 million or 39%, to $35.1$12.8 million for the 2017 third quarter of 2022 compared to $57.7$7.9 million for the 2016 third quarter primarily due to a decreaseof 2021, reflecting an increase in non-producing property impairments.
Impairments of non-producing properties decreased $19.7 million, or 36%, to $35.1 million for the 2017 third quarter compared to $54.8 million for the 2016 third quarter. The decrease was due to a lower balance of unamortized leasehold costs in the current year due to property dispositions and reduced land capital expenditures in recent years, along with changes in the timing and magnitude of amortization of undeveloped leasehold costs between periodsdriven by an increase in our balance of unproved properties resulting from changes inproperty acquisitions over the Company's estimates of undeveloped properties not expected to be developed before lease expiration.
past year. There were no proved property impairments recognized in the 2017 third quarter compared to $2.9 millionperiods of such impairments for the third quarter of 2016.2022 and 2021.
General and Administrative (“G&A”) Expenses. Total G&A expenses decreased $0.4increased $10.3 million, or 1%18%, from $44.4to $68.7 million for the third quarter of 20162022 compared to $44.0$58.4 million for the third quarter of 2017.2021. Total G&A expenses include non-cash charges for equity compensation of $11.9$16.7 million and $13.2$14.3 million for the third quarters of 20172022 and 2016,2021, respectively.
G&A expenses other than equity compensation included in the total G&A expense figure above totaled $32.1$52.0 million for the 20172022 third quarter, an increase of $0.9$7.9 million or 3%, compared to $31.2$44.1 million for the 20162021 third quarter. This increase resulted from an increase in employee compensation and benefits in 2017 in responsequarter primarily due to the stabilizationgrowth of our operations and improvementincreases in commodity prices in late 2016,payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities overcompared to the prior period.2021 third quarter. Additionally, G&A expenses for the 2022 third quarter include $7.0 million ($0.18 per Boe) of expenses consisting primarily of fees and expenses of the legal and financial advisors engaged by the Special Committee of our Board of Directors that was established to, among other things, review and evaluate the terms and conditions of, and to determine the advisability of, the Hamm Family's take-private transaction. We expect to incur additional transaction-related fees, some of which are contingent and payable if and when the take-private transaction is consummated, which is currently expected to occur by December 31, 2022.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.
 Three months ended September 30,
$/Boe20222021
General and administrative expenses$1.36 $1.45 
Non-cash equity compensation0.43 0.47 
Total general and administrative expenses$1.79 $1.92 
 
Three months ended September 30,
$/Boe
2017 2016
General and administrative expenses $1.45
 $1.63
Non-cash equity compensation 0.54
 0.69
Total general and administrative expenses $1.99
 $2.32
The decreaseAs discussed in G&A expenses other than equityNotes to Unaudited Condensed Consolidated Financial Statements–Note 1. Organization and Nature of Business—Recent Developments, as of the effective time of the Merger, each unvested restricted stock award issued under the Company’s long-term incentive plans that is outstanding immediately prior to the effective time will be canceled and replaced with a restricted stock unit award issued by the Company that provides the holder of such canceled award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two. Upon such event, the Company plans to remeasure the cumulative compensation expense recognized on a per-Boe basis was driven by a 16% increasethe modified awards pursuant to U.S. GAAP, which we estimate is expected to result in total sales volumes from new well completions with no comparable increase in G&A expenses.
The decrease inthe recognition of additional non-cash equity compensation expense on a per-Boe basis resulted from changes in the timing and magnitude of forfeitures of unvested restricted stock between periods, coupled withtotaling approximately $160 million, reflecting the increase in sales volumesthe value of the awards from new well completions with no comparable increase in equity compensation expense.the original grant date to the subsequent modification date.
27

Interest Expense. Interest expense decreased $7.3increased $10.8 million, or 9%18%, to $74.8$70.7 million for the third quarter of 20172022 compared to $82.1$59.9 million for the third quarter of 2016 due to a decrease in outstanding debt primarily as a result of the November 2016 redemptions of our $200 million of 2020 Notes and $400 million of 2021 Notes. Our weighted average outstanding long-term debt balance for the 2017 third quarter was approximately $6.7 billion with a weighted average interest rate of 4.1%, compared to averages of $7.1 billion and 4.4% for the 2016 third quarter. The lower interest expense associated with reduced debt was partially offset by higher interest expense being incurred on our variable-rate credit facility and term loan borrowings due to an increase in market interest rates in 2017.
Income Taxes. We recorded income tax expenseour weighted average outstanding debt balance from $4.8 billion for the third quarter of 2017 of $6.8 million compared2021 to an income tax benefit of $65.3 million$6.3 billion for the third quarter of 2016, resulting2022. This increase was driven by debt incurred in effective tax ratesthe fourth quarter of approximately 39% and 37%, respectively, after taking into account permanent taxable differences, valuation allowances, and other items.2021 to fund a portion of our December 2021 acquisition of properties in the Permian Basin.
Income Taxes. For the third quarters of 20172022 and 2016,2021 we provided for income taxes at a combined federal and state tax rate of 38%24.5% of our pre-tax income. We recorded an income (loss) generated by our operationstax provision of $323.4 million for the 2022 third quarter and an income tax provision of $115.6 million for the 2021 third quarter, which resulted in the United Stateseffective tax rates of 24.1% and 25% of pre-tax losses generated by our operations23.8%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in Canada.valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 10.12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rate for the third quarters of 2017 and 2016.

rates.

Nine months ended September 30, 20172022 compared to the nine months ended September 30, 20162021
Results of Operations
The following table presents selected financial and operating information for the periods presented.
 Nine months ended September 30,
In thousands20222021
Crude oil, natural gas, and natural gas liquids sales$7,870,696 $3,986,628 
Loss on derivative instruments, net(1,009,460)(232,795)
Crude oil and natural gas service operations52,707 38,519 
Total revenues6,913,943 3,792,352 
Operating costs and expenses(2,961,094)(2,395,775)
Other expenses, net(211,408)(185,191)
Income before income taxes3,741,441 1,211,386 
Provision for income taxes(903,745)(291,116)
Income before equity in net loss of affiliate2,837,696 920,270 
Equity in net loss of affiliate(736)— 
Net income2,836,960 920,270 
Net income attributable to noncontrolling interests17,349 1,975 
Net income attributable to Continental Resources$2,819,611 $918,295 
Production volumes:
Crude oil (MBbl)54,018 43,300 
Natural gas (MMcf)325,011 274,352 
Crude oil equivalents (MBoe)108,187 89,026 
Sales volumes:
Crude oil (MBbl)53,979 43,257 
Natural gas (MMcf)325,011 274,352 
Crude oil equivalents (MBoe)108,147 88,982 
28
  Nine months ended September 30,
In thousands, except sales price data 2017 2016
Crude oil and natural gas sales $1,965,216
 $1,435,194
Gain (loss) on crude oil and natural gas derivatives, net 83,482
 (24,477)
Crude oil and natural gas service operations 24,959
 19,867
Total revenues 2,073,657
 1,430,584
Operating costs and expenses (1) (1,933,724) (1,873,415)
Other expenses, net (217,463) (243,771)
Loss before income taxes (77,530) (686,602)
Benefit for income taxes 25,063
 259,254
Net loss $(52,467) $(427,348)
Production volumes:    
Crude oil (MBbl) 35,074
 36,133
Natural gas (MMcf) 162,515
 143,697
Crude oil equivalents (MBoe) 62,160
 60,083
Sales volumes:    
Crude oil (MBbl) 34,975
 36,080
Natural gas (MMcf) 162,515
 143,697
Crude oil equivalents (MBoe) 62,061
 60,029
Average sales prices:    
Crude oil ($/Bbl) $43.26
 $33.51
Natural gas ($/Mcf) 2.78
 1.57
Crude oil equivalents ($/Boe) 31.67
 23.91

(1) Net of gain on sale of assets of $103.2 million for the nine months ended September 30, 2016.
Production
The following tables reflecttable summarizes the changes in our average daily Boe production by major operating area for the year to date period.
Boe production per dayYTD 9/30/2022YTD 9/30/2021% Change
Bakken169,889 167,632 1 %
Anadarko Basin155,861 147,626 6 %
Powder River Basin23,438 4,477 424 %
Permian Basin40,903 — — 
All other6,197 6,367 (3 %)
Total396,288 326,102 22 %

The following table summarizes the changes in our production by product and region for the periods presented.year to date period.
 Nine months ended September 30,Volume
increase		Volume
percent
increase
 20222021
 VolumePercentVolumePercent
Crude oil (MBbl)54,018 50 %43,300 49 %10,718 25 %
Natural gas (MMcf)325,011 50 %274,352 51 %50,659 18 %
Total (MBoe)108,187 100 %89,026 100 %19,161 22 %
  Nine months ended September 30, Volume
increase (decrease)		 Volume
percent
increase (decrease)
  2017 2016  
  Volume Percent Volume Percent 
Crude oil (MBbl) 35,074
 56% 36,133
 60% (1,059) (3%)
Natural gas (MMcf) 162,515
 44% 143,697
 40% 18,818
 13%
Total (MBoe) 62,160
 100% 60,083
 100% 2,077
 3%
             
  Nine months ended September 30, Volume
increase (decrease)		 Volume
percent
increase (decrease)
  2017 2016  
  MBoe Percent MBoe Percent 
North Region 36,106
 58% 37,243
 62% (1,137) (3%)
South Region 26,054
 42% 22,840
 38% 3,214
 14%
Total 62,160
 100% 60,083
 100% 2,077
 3%
The 3% decrease25% increase in crude oil production for year to date 20172022 compared to year to date 2021 was primarily driven primarily by decreased production from our North region properties in North Dakota Bakken, Montana Bakken and the Red River units due to natural declines in production coupled with delayed completion activities in response to low crude oil prices. North Dakota Bakken crude oil production decreased 324 MBbls, or 1%, and Montana Bakken production decreased 567 MBbls, or 25%, while productionproperty acquisitions in the RedPermian Basin and Powder River units decreased 293 MBbls, or 10%, fromBasin over the priorpast year, period. The decreased crude oil production in North Dakota Bakken was mitigated by new well production generated in recent months from increased well completion activities in


2017, which resulted in a 19% sequentialcontributed to an increase in crude oilour year to date 2022 production in that play for the 2017 third quarterby 8,594 MBbls and 3,253 MBbls, respectively, compared to the 2017 second quarter. Additionally, crude oil production in SCOOP decreased 824 MBbls, or 16%, dueyear to natural declines in production and reduced drilling activities.date 2021. These decreasesincreases were partially offset by an increase of 972a 1,105 MBbls, or 105%11%, decrease in Anadarko Basin crude oil production from our STACK properties due to additional wells being completeda change in allocation of capital from oil-weighted projects to gas-weighted projects in the play over the past year and producing as a resultthe timing of an increase in our drilling and completion activities in that area.well completions.
The 13%18% increase in natural gas production for year to date 20172022 compared to year to date 2021 was primarily driven by increased production from our propertiesdue in part to the previously described property acquisitions over the past year. Properties acquired in the STACK play duePermian Basin and new well completions increased our year to additional wells being completeddate 2022 production by 15,433 MMcf while properties acquired in the Powder River Basin and producing subsequentnew well completions increased our production by 11,541 MMcf compared to September 30, 2016. Natural gas production in STACK increased 23,231 MMcf, or 127%, over the prior year period.to date 2021. Additionally, natural gas production in North Dakota Bakkenthe Anadarko Basin increased 1,52820,116 MMcf, or 4%11%, over the priorcompared to year period in conjunction with higher crude oil production in recent months arising from increased well completion activities. These increases were partially offset by reduced production from our SCOOP properties, which decreased 4,327 MMcf, or 6%, along with various other areas in our North and South regionsto date 2021 due to natural declines in production and reduced drilling activitiesnew well completions over the past year.

Revenues
In September 2017 we sold substantially all of our producing properties in the Arkoma Woodford area of Oklahoma. The sold properties comprised approximately 2,850 MMcf of ourNet crude oil, natural gas, production for the nine months ended September 30, 2017.

In conjunction with our increase in capital spending in 2017 relative to 2016, we expect our production will average between 238,000 and 242,000 Boe per day for the full year of 2017 compared to average daily production of 216,912 Boe per day for 2016.
Revenues
Crude Oil and Natural Gas Sales. Crude oil and natural gas liquids sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of these measures.
Net crude oil, natural gas, and natural gas liquids sales. Net sales for year to date 2017 were $1.972022 totaled $7.63 billion, a 37%an increase fromof 99% compared to net sales of $1.44$3.83 billion for the samecomparable 2021 period in 2016 due to a 32% increasesignificant increases in realized commoditynet sales prices coupled with a 3% increase in totaland sales volumes.volumes as discussed below.
Total sales volumes for year to date 2022 increased 19,165 MBoe, or 22%, compared to year to date 2021 primarily due to new wells added from our property acquisitions over the past year. For year to date 2022, our crude oil sales volumes increased 25% and our natural gas sales volumes increased 18% compared to year to date 2021.
Our crude oil net sales prices averaged $43.26$95.51 per barrel for year to date 2017, an increase of 29%2022 compared to $33.51$60.79 per barrel for year to date 20162021 due to higher crude oilthe previously described increase in market prices andalong with improved price realizations.differentials. The differential between NYMEX WTI calendar month average crude oil prices and our realized crude oil pricenet sales prices improved to an average of $2.63 per barrel for year to date 2017 was $6.072022 compared to $4.13 per barrel compared to $7.44 for year to date 2016. The improved differential was primarily due to improved2021, reflecting strong price realizations resulting from new pipeline takeaway capacity and additional markets becoming available in 2017 for Bakken production, along with the growth inacross our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.assets.
Our natural gas net sales prices averaged $2.78$7.63 per Mcf for year to date 2017, a 77% increase2022 compared to $1.57$4.38 per Mcf for year to date 20162021 due to higherthe previously described increase in market prices for natural gas and NGLs and improved price realizations.prices. The discountdifference between our realized natural gasnet sales prices and NYMEX Henry Hub calendar month natural gas prices improved from $0.73was a premium of $0.74 per Mcf for year to date 20162022 compared to $0.37a premium of $1.17 per Mcf for year to date 2017. 2021. The majority of our natural gas production is sold at our lease locations to midstream purchasers withdecrease in premium was driven by price realizations impacted by the volume and value of NGLs that purchasers extract fromvolatility, wider basis differentials between prices
29

received in our sales stream.markets and NYMEX settlement prices, and significant improvement in Henry Hub prices as compared to increases in NGL prices, have increased over prior year levelscausing the uplift in conjunction with increased crude oil prices and other factors, resulting in improved price realizations for our naturalfull gas sales stream comparedrelative to the prior year.
Total sales volumes for yearbenchmark prices to date 2017 increased 2,032 MBoe, or 3%, compared to year to date 2016. For year to date 2017, our crude oil sales volumes decreased 3% from the comparable 2016 period, while our natural gas sales volumes increased 13%, reflecting an increase over the past yearbe less significant in the proportion of capital spending allocated to areascurrent period.
Derivatives. The significant improvement in Oklahoma which typically have higher concentrations of natural gas compared to oil-weighted properties in North Dakota Bakken.
Derivatives. Changes in natural gascommodity prices during the nine months ended September 30, 20172022 had a favorablesignificant unfavorable impact on the fair value of our natural gas derivatives, which resulted in positivenegative revenue adjustments of $83.5 milliontotaling $1.01 billion for the period, representing $68.5 million of non-cash gains and $15.0$403.6 million of cash gains. losses and $605.8 million of unsettled non-cash losses, compared to negative revenue adjustments totaling $232.8 million in the comparable 2021 period.
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 $14.2 million, or 37%, from $38.5 million for year to date 2021 to $52.7 million for year to date 2022 primarily due to increased water handling resulting from increased drilling, completion, and production activities compared to the 2021 period, which also contributed to an increase in service-related operating expenses in the current period.
Operating Costs and Expenses
Production Expenses. Production expenses increased $20.1$164.0 million, or 9%56%, from $219.7to $456.8 million for year to date 20162022 compared to $239.8$292.8 million for year to date 2017. Production expenses on a per-Boe basis increased2021 due to $3.86 for year to date 2017 compared to $3.66 for the comparable 2016 period. These increases resulted from an increase in the number of producing wells higher costs incurred in the 2017 first quarter from severe weather conditions encountered in the North region that created a challenging operating environment,drilling activities and an increase inproperty acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties.properties prompted by the favorable commodity price environment. Production expenses on a per-Boe basis averaged $4.22 per Boe for year to date 2022 compared to $3.29 per Boe for year to date 2021, the increase of which reflects higher workover-related activities, cost inflation, and the addition of oil-weighted production acquired in the Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to gas-weighted properties in the Anadarko Basin.


Production and Ad Valorem Taxes. Production and ad valorem taxes increased $30.3$282.5 million, or 29%101%, to $134.5$563.2 million for year to date 20172022 compared to $104.2$280.7 million for year to date 20162021 due to higher crude oil and natural gas revenues resulting primarily from increasesthe previously described increase in commodity prices over the prior year period.
Productionsales. Our production taxes as a percentage of crude oil and natural gas revenues were 6.8%net sales averaged 7.4% for year to date 2017 compared to2022, consistent with 7.3% for year to date 2016, the decrease2021.
Exploration expenses. Exploration expenses, which consist primarily of which resulted from significant growth over the pastexploratory geological and geophysical costs and dry hole costs that are expensed as incurred, increased $11.0 million to $20.5 million for year in our STACK operations and resulting increase in revenues coming from Oklahoma, which has lower production tax ratesto date 2022 compared to North Dakota.$9.5 million for year to date 2021. The decrease in our year-to-date average production tax rate was partially offset by higher production taxes arisingyear to date 2022 period includes $12.1 million of dry hole costs associated with an unsuccessful exploratory well with no comparable dry hole costs incurred in the 2017 third quarter as a result of increased production and revenues being generated in North Dakota in recent months from increased well completion activities, along with the enactment of new legislation in Oklahoma that increased the production tax rate, effective July 1, 2017, from 1%year to 4% on wells that began producing between July 1, 2011 and July 1, 2015. These factors contributed to a sequential increase in our average production tax rate from 6.7% in the 2017 second quarter to 7.3% in the 2017 third quarter.date 2021 period.
Exploration Expenses. The following table shows the components of exploration expenses for the periods presented.
  Nine months ended September 30,
In thousands 2017 2016
Geological and geophysical costs $9,434
 $8,493
Exploratory dry hole costs 157
 233
Exploration expenses $9,591
 $8,726
Depreciation, Depletion, Amortization and Accretion. Total DD&A decreased $122.3$50.6 million, or 9%3%, to $1.20$1.40 billion for year to date 20172022 compared to $1.32$1.45 billion for the comparable 2021 period in 2016 primarily due to anthe previously described decrease in our DD&A rate per Boe in 2022 largely offset by the 22% increase in the volume of proved reserves over which costs are depleted as further discussed below, the impact of which was partially offset by an increase in DD&A resulting from higherour total sales volumes in the current year.volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.
 Nine months ended September 30,
$/Boe20222021
Crude oil and natural gas$12.62 $15.95 
Other equipment0.20 0.22 
Asset retirement obligation accretion0.09 0.09 
Depreciation, depletion, amortization and accretion$12.91 $16.26 
  Nine months ended September 30,
$/Boe 2017 2016
Crude oil and natural gas $18.95
 $21.55
Other equipment 0.29
 0.37
Asset retirement obligation accretion 0.07
 0.08
Depreciation, depletion, amortization and accretion $19.31
 $22.00
Upward revisionsProperty Impairments. Total property impairments increased $21.9 million to proved reserves over$52.9 million for the past year to date period of 2022 compared to $31.0 million for year to date 2021 due in part to an improvement in commodity prices contributed to a decrease in our DD&A rate for crude oil and natural gas properties in 2017 compared to 2016. Additionally, improvements in drilling efficiencies and optimized completion technologies over the past year have resulted in a significant improvement$11.8 million proved property impairment recognized in the quantity of2022 first quarter on a property in an emerging play with no proved reserves found and developed per dollar invested, which also contributed to the reduction in our DD&A rateproperty impairments being recognized in the currentprior year period.
Property Impairments. Total propertyAdditionally, impairments of unproved properties increased $7.1 million, or 3%, to $209.8$10.1 million for year to date 20172022 compared to $202.7year to date 2021, reflecting an increase in the amortization of undeveloped leasehold costs driven by an increase in our balance of unproved properties resulting from property acquisitions over the past year.
General and Administrative Expenses. Total G&A expenses increased $39.3 million, or 24%, to $206.1 million for year to date 2016 primarily due2022 compared to an increase in proved property impairments partially offset by lower non-producing property impairments as discussed below.
Proved property impairments totaled $82.3$166.8 million for year to date 2017 compared to $2.9 million for year to date 2016. The proved property impairments recognized for year to date 2017, nearly all of which were recognized in the second quarter, were primarily concentrated in the Arkoma Woodford field for which we determined the carrying amount of the field was not recoverable from future cash flows, and therefore, was impaired at June 30, 2017. There were no proved property impairments recognized in the 2017 third quarter.
Impairments of non-producing properties decreased $72.3 million, or 36%, to $127.5 million for year to date 2017 compared to $199.8 million for year to date 2016. The decrease was due to a lower balance of unamortized leasehold costs in the current year due to property dispositions and reduced land capital expenditures in recent years, along with changes in the timing and magnitude of amortization of undeveloped leasehold costs between periods resulting from changes in the Company's estimates of undeveloped properties not expected to be developed before lease expiration.
General and Administrative Expenses. Total G&A expenses increased $17.4 million, or 15%, from $113.0 million for year to date 2016 to $130.4 million for year to date 2017.2021. Total G&A expenses include non-cash charges for equity compensation of $32.5$60.8 million and $34.3$44.9 million for the year to date periods of 2022 and 2021, respectively. This increase was primarily driven by approximately $10 million of incremental expenses recognized on restricted stock awards whose vesting terms were modified and accelerated in the 2022 first quarter upon the retirement of certain management personnel from the Company.
30

G&A expenses other than equity compensation totaled $145.3 million for year to date 20172022, an increase of $23.4 million compared to $121.9 million for the comparable 2021 period primarily due to the growth of our operations and yearincreases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to date 2016, respectively.the prior period. Additionally, G&A expenses other


than equity compensation included in the total G&A expense figure above totaled $97.9 million for year to date 2017, an increase2022 include $7.0 million ($0.06 per Boe) of $19.2 million, or 24%, comparedpreviously described fees and expenses related to $78.7 million for the comparable 2016 period.Hamm Family's take-private transaction.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.
 Nine months ended September 30,
$/Boe20222021
General and administrative expenses$1.35 $1.37 
Non-cash equity compensation0.56 0.50 
Total general and administrative expenses$1.91 $1.87 
  Nine months ended September 30,
$/Boe 2017 2016
General and administrative expenses $1.58
 $1.31
Non-cash equity compensation 0.52
 0.57
Total general and administrative expenses $2.10
 $1.88
The increase in G&A expenses other than equity compensation was primarilyInterest Expense. Interest expense increased $29.7 million, or 16%, to $215.5 million for year to date 2022 compared to $185.8 million for the comparable 2021 period due to an increase in employee compensation and benefits in 2017 in response to the stabilization and improvement in commodity prices in late 2016, partially offset by higher overhead recoveries from joint interest owners driven by increased completion activities over the prior period.
Interest Expense. Year to date interest expense decreased $26.2 million, or 11%, to $218.7 million compared to $244.9 million for the comparable 2016 period due to a decrease in outstanding debt primarily as a result of the November 2016 redemptions of our $200 million of 2020 Notes and $400 million of 2021 Notes. Our weighted average outstanding long-term debt balance from $5.1 billion for year to date 20172021 to $6.6 billion for year to date 2022. This increase was approximately $6.7 billion withdriven by debt incurred in the fourth quarter of 2021 to fund a weighted average interest rateportion of 4.2% compared to averagesour December 2021 acquisition of $7.2 billion and 4.3% forproperties in the comparable period in 2016. The lower interest expense associated with reduced debt was partially offset by higher interest expense being incurred on our variable-rate credit facility and term loan borrowings due to an increase in market interest rates in 2017.Permian Basin.
Income Taxes. We recorded an income tax benefit for For the nine months ended September 30, 20172022 and 2021 we provided for income taxes at a combined federal and state tax rate of $25.1 million compared to a benefit24.5% of $259.3our pre-tax income. We recorded an income tax provision of $903.7 million for the prior year to date period resultingof 2022 and an income tax provision of $291.1 million for year to date 2021, which resulted in effective tax rates of approximately 32%24.2% and 38%24.0%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 10.12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rate for the 2017 and 2016 periods.rates.
Liquidity and Capital Resources
Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of debt and equity securities. Additionally, non-strategic asset dispositions and joint development arrangements have provided a significant source of cash flow for use in reducing debt and enhancing liquidity. We intendare committed to continue pursuing opportunitiesoperating in a responsible manner to reducepreserve financial flexibility, liquidity, and the strength of our long-term debt using proceeds from additional potential sales of non-strategic assets or through joint development arrangements; however, no assurance can be given that such transactions will occur.balance sheet.
At September 30, 2017,October 31, 2022, we had $10.8 million of cashno outstanding borrowings and cash equivalents and approximately $1.81$2.25 billion of borrowing availability onunder our revolvingcredit facility. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2026.
Recent Developments
As previously described, on October 24, 2022 the Hamm Family commenced a tender offer to acquire for cash all of the outstanding shares of common stock of Continental, other than: (i) shares owned by the Hamm Family and (ii) shares underlying unvested equity awards issued pursuant to Continental’s long-term incentive plans, for a purchase price of $74.28 per share. The tender offer is scheduled to expire one minute after considering11:59 p.m., New York City time, on November 21, 2022.
There are approximately 58 million shares of Continental's common stock subject to the tender offer that are not held by the Hamm Family. The purchase of outstanding borrowingsshares not held by the Hamm Family is expected to be funded by Continental through a combination of $938 million and lettersfunding sources, including the use of credit. At October 31, 2017, outstanding borrowings decreased to $895 million, leaving approximately $1.85 billioncash on hand, utilization of borrowing availability on our credit facility at that date. We expectborrowing capacity, and an anticipated term loan facility to maintain a disciplined spending approach and plan to managebe entered into in connection with the levelclosing of our capital spending in order to minimize new incremental borrowings and maintain ample liquidity.the transaction.
Based on our planned capital spending, our forecasted cash flows, and projected levels of indebtedness, including the additional debt to be incurred by the Company to fund the take-private transaction described above, we expect to maintain compliance with the covenants under our revolving credit facility three-year term loan, and senior note indentures for at least the next 12 months.indentures. Further, based on current market indications, we expect to meet in the ordinary course of business otherour contractual cash commitments to third parties as of September 30, 2017,2022, including those subsequently described in Note 7. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statementsunder 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 if needed to fund our operations.
31

Cash Flows
Cash flows from operating activities
Our netNet cash provided by operating activities totaled $1,348.0 million and $863.9 millionincreased $2.74 billion, or 100%, to $5.46 billion for the nine months ended September 30, 2017 and 2016, respectively. Theyear to date 2022 compared to $2.73 billion for year to date 2021 driven by a $3.88 billion increase in crude oil, natural gas, and NGL revenues due to the previously described increases in commodity prices and sales volumes in the current period. This increase was partially offset by a $316 million increase in realized cash losses on matured commodity derivatives, a $440 million increase in cash payments for U.S. federal income taxes, a $283 million increase in production and ad valorem taxes associated with higher revenues, and increases in certain other cash operating cash flows wasexpenses primarily due to an increase in crude oil and natural gas revenues driven by higher realized commodity prices and total sales volumes in 2017 coupled with lower interestand growth of our Company over the past year. Increased cash operating expenses the effects of which were partially offset by increasesincluded a $164 million increase in production expenses production taxes, and generalan $80 million increase in transportation, gathering, processing, and administrative expenses and a decrease in cash gains on matured natural gas derivatives.


compression expenses.
Cash flows used infrom investing activities
During the nine months ended September 30, 2017 and 2016, we hadNet cash flows used in investing activities of $1,374.3 million and $550.2 million, respectively. These totals include capital spending of $1,459.0 million and $884.5 million, respectively, inclusive of exploration and development drilling, property acquisitions, and dry hole costs. Property acquisitions totaled $28.7 million and $22.6 millionincreased $1.57 billion to $2.70 billion for the nine months ended September 30, 2017 and 2016, respectively. Theyear to date 2022 compared to $1.12 billion for year to date 2021, reflecting our planned increase in capitalbudgeted spending was driven byand an increase in ourthe magnitude of year to date property acquisitions. Non-acquisition capital budgetexpenditures attributable to us for full year 2022 are budgeted to be between $2.6 billion and related drilling and completion activities for 2017. We expect our$2.7 billion compared to $1.54 billion of non-acquisition capital spending for full year 2021. Our investing cash flows for year to date 2022 include $403 million paid to acquire properties in the remainder of 2017 will continuePowder River Basin and $197 million paid to be higher than 2016 levels.
The use of cash for capital expendituresacquire properties in 2017 and 2016 was partially offset by proceeds received from asset dispositions, which totaled $84.7the Permian Basin as discussed in Note 3. Property Acquisitions as well as $151 million and $334.3 millionpaid for the nine months ended September 30, 2017 and 2016, respectively. See new strategic investment in an affiliate of Summit Carbon Solutions described in Note 11. Property Dispositions13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of notable dispositions, including a discussion of sales proceeds totaling $59.9 million received by the Company subsequent to September 30, 2017 in conjunction with the consummation of a property disposition in October 2017, which will be reflected in 2017 fourth quarter cash flows from investing activities..
Cash flows from financing activities
Net cash provided byused in financing activities for the nine months ended September 30, 2017year to date 2022 totaled $20.4$974 million, primarily resulting from $33consisting of $500 million of net borrowingsrepayments on our revolving credit facility, during the period$284 million of cash dividends paid on common stock, $100 million of cash used to fund operations.repurchase shares of our common stock, and $32 million of cash used to repurchase senior notes.
Net cash used in financing activities for the nine months ended September 30, 2016year to date 2021 totaled $305.6$959 million, primarily resulting fromconsisting of $631 million of cash used to redeem senior notes, $160 million of net repayments of $288 million on our revolving credit facility, during the period. The net repayments resulted from the reduction$94 million of credit facility debt using proceeds totaling $334.3cash dividends paid on common stock, and $65 million from 2016 asset dispositions completed through September 30, 2016, partially offset by borrowings incurredof cash used to fund operations.repurchase shares of our common stock.
We plan to manage our level of capital spending for the remainder of 2017 in order to minimize the incurrence of new incremental debt.
Future Sources of Financing
Although we cannot provide any assurance, we believe funds from operating cash flows, our remaining cash balance, and availability under our revolving credit facility and anticipated future term loan facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, our obligations under the Hamm Family's take-private transaction, debt service obligations, plannedbudgeted capital expenditures, and commitmentscash payments for income taxes for at least the next 12 months and to meet our contractual cash commitments to third parties beyond 12 months.
Our plannedBased on current market indications, our budgeted capital spending has been established based on an expectation of availableplans are expected to be funded from operating cash flows. Any deficiencies in operating cash flows with any cash flow deficienciesrelative to budgeted spending are expected to be funded by borrowings under our revolving credit facility or proceeds from asset sales.
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 revolving credit facility if needed to fund our operations. operations and business plans.
We may choose to access thebanking or capital markets for additional financing or capital to take advantage offund our operations or to finance business opportunities or developments that may arise. For instance, as previously described we plan to execute a new term loan facility to fund a portion of the Hamm Family's take-private transaction. Further, we may sell additional assets or enter into strategic joint development opportunities in order to obtain funding for our operations and capital program if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.
We currently anticipate we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. We intend to fund future capital expenditures primarily through cash flows from operations and through borrowings under our revolving credit facility, but we may also issue debt or equity securities, sell additional assets, or enter into joint development arrangements. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.


Revolving creditCredit facility
We have an unsecured credit facility, maturing on May 16, 2019,in October 2026, with aggregate lender commitments totaling $2.75 billion, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders.$2.255 billion. The commitments are from a syndicate of 1713 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.
As of October 31, 2017,2022, we had approximately $1.85 billion of borrowing availabilityno outstanding borrowings on our credit facility. As previously described, we plan to utilize credit facility after considering outstanding borrowings and letters of credit. Credit facility borrowings bear interest at market-based interest rates plusborrowing capacity to fund a margin based on the termsportion of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness.Hamm Family’s take-private transaction.
32

The commitments under our revolving 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 woulddo not trigger a reduction in our current credit facility commitments, nor woulddo such actions trigger a security requirement or change in covenants. The weighted-average interest rate onDowngrades of our credit facility borrowings was 2.99% at September 30, 2017rating will, however, trigger increases in our credit facility's interest rates and we incur commitment fees of 0.30% per annumpaid on the daily average amount of unused borrowing availability.availability under certain circumstances.
Our revolving 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. ThisSee Notes to Unaudited Condensed Consolidated Financial Statements–Note 8. Debt for a discussion of how this ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters ofis calculated pursuant to our credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014.agreement.
We were in compliance with our revolving credit facility covenants at September 30, 20172022 and expect to maintain compliance for at least the next 12 months.such compliance. At September 30, 2017,2022, our consolidated net debt to total capitalization ratio as defined in our revolving credit facility as amended, was 0.56 to 1.00.0.28. We do not believe the revolving credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing to a material extent if needed to support our business. At September 30, 2017,Additionally, our totalcredit facility covenants are not expected to limit our ability to incur debt would have needed to independently increase by approximately $2.9 billion abovefinance the existing level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately $1.6 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at September 30, 2017 to reach the maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.Hamm Family's take-private transaction.
Joint development agreement funding
In September 2014, we entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd ("SK") of South Korea to jointly develop a portion of the Company's STACK properties. Pursuant to the agreement SK will fund, or carry, 50% of our drilling and completion costs attributable to an area of mutual interest targeting the Woodford formation in the STACK play until approximately $270 million has been expended by SK on our behalf. As of September 30, 2017, approximately $112 million of the carry had yet to be realized and is expected to be realized through mid-2019.
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 of September 30, 2022, 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 $5.2$6.3 billion at September 30, 2017. We have no near-term senior note maturities, with our earliest scheduled senior note maturity being our $2.0 billion2022, exclusive of 2022 Notes due in September 2022.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 $636 million of 2023 Notes due in April 2023, which is reflected as a current liability in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of September 30, 2022. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the maturity date. 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 6. Long-Term8. Debtin Notes to Unaudited Condensed Consolidated Financial Statements.
We were in compliance with our senior note covenants at September 30, 20172022 and expect to maintain compliance for at least the next 12 months.such compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. financing if needed to support our business. Additionally, our senior note covenants are not expected to limit our ability to incur debt needed to finance the Hamm Family's take-private transaction.
Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt woulddo not trigger additional senior note covenants.

Transportation, gathering, and processing commitments

Three of our subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes as of September 30, 2017.
Term loan
We have a $500 million unsecured term loan that matures in full in November 2018entered into transportation, gathering, and bears interest at variable market-based interest rates plus a margin basedprocessing commitments to guarantee capacity on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. Downgrades or other negative rating actions with respect to our credit rating would not trigger a security requirement or change in covenants for the term loan. The interest rate on the term loan was 2.76% at September 30, 2017.
Capital expenditures
We evaluate opportunities to purchase or sell crude oil and natural gas propertiespipelines and expectnatural gas processing facilities that require us to participatepay per-unit charges regardless of the amount of capacity used. Future commitments remaining as a buyer or seller of properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunitiesSeptember 30, 2022 under the arrangements amount to expand our existing core areas. Acquisitionapproximately $1.13 billion.See Note 9. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.
Capital expenditures are not budgeted.
Our capital expenditures budget for 2017 is $1.95 billion excluding acquisitions, which2022 is expected to be allocated$2.6 billion to $2.7 billion. Costs of acquisitions and investments, such as follows:those described in Note 3. Property Acquisitions and Note 13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements, are not budgeted, with the exception of planned levels of spending for mineral acquisitions.
In millionsAmount
Exploration and development drilling$1,720
Land costs115
Capital facilities, workovers and other corporate assets105
Seismic10
Total 2017 capital budget, excluding acquisitions$1,950
For the nine months ended September 30, 2017,2022, we invested approximately $1,499.5 million$1.99 billion in our capital program excluding $28.7$705.4 million of unbudgeted acquisitions, excluding $7.9 million of mineral acquisitions attributable to Franco-Nevada, and including $66.3$150.7 million of capital costs associated with increased accruals for capital expenditures and including $2.8 million of seismic costs.as compared to December 31, 2021. Our 20172022 year to date capital expenditures were allocated as follows by quarter:shown in the table below.
33

In millions1Q 20172Q 20173Q 2017YTD 2017In millions1Q 20222Q 20223Q 2022YTD 2022
Exploration and development drilling$329.8
$471.0
$444.7
$1,245.5
Exploration and development drilling$426.2 $504.7 $686.0 $1,616.9 
Land costs68.8
49.8
47.7
166.3
Land costs24.3 31.2 30.6 86.1 
Capital facilities, workovers and other corporate assets27.4
29.3
28.2
84.9
Mineral acquisitions attributable to ContinentalMineral acquisitions attributable to Continental0.5 0.4 1.0 1.9 
Capital facilities, workovers, water infrastructure, and other corporate assetsCapital facilities, workovers, water infrastructure, and other corporate assets72.3 110.9 97.4 280.6 
Seismic1.0
1.8
—
2.8
Seismic0.6 1.3 0.9 2.8 
Capital expenditures, excluding acquisitions427.0
551.9
520.6
1,499.5
Acquisitions of producing properties0.1
0.7
2.7
3.5
Acquisitions of non-producing properties13.3
5.1
6.8
25.2
Total acquisitions13.4
5.8
9.5
28.7
Capital expenditures attributable to Continental, excluding unbudgeted acquisitionsCapital expenditures attributable to Continental, excluding unbudgeted acquisitions523.9 648.5 815.9 1,988.3 
Unbudgeted acquisitionsUnbudgeted acquisitions443.1 219.2 43.1 705.4 
Total capital expenditures attributable to ContinentalTotal capital expenditures attributable to Continental$967.0 $867.7 $859.0 $2,693.7 
Mineral acquisitions attributable to Franco-NevadaMineral acquisitions attributable to Franco-Nevada1.9 1.8 4.2 7.9 
Total capital expenditures$440.4
$557.7
$530.1
$1,528.2
Total capital expenditures$968.9 $869.5 $863.2 $2,701.6 
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, access to capital, 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 backadjust our capital spending plans should commodity prices decreasematerially change from current levels. Conversely, an increase in commodity prices from current levels could result in increased capital expenditures. 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 competitiveattractive terms.
CommitmentsStrategic Investment
Refer to See Note 7. Commitments and Contingencies 13. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statementsfor discussion of future spending commitments associated with a strategic investment made by the Company with Summit Carbon Solutions beginning in the first quarter of 2022.
Cash Payments for Income Taxes
For the nine months ended September 30, 2022, we made estimated quarterly payments for 2022 U.S. federal income taxes totaling $440 million based on an estimate of federal taxable income for the year. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending, profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2023, which would result in us continuing to make estimated tax payments on a quarterly basis in 2023 that could approximate the payments made thus far in 2022. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, we cannot predict the amount of future income tax payments with certainty.
Senior note redemptions and repurchases
In recent periods we have redeemed or repurchased a portion of our outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The timing and amount of any such redemptions or repurchases 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. Our $636 million of 2023 Notes is due in April 2023. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the maturity date.
Derivative Instruments
The fair value of our derivative instruments at September 30, 2022 was a net liability of $571.5 million. See Note 6. Derivative Instruments in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of September 30, 2022. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Item 3. Quantitative and Qualitative Disclosures About Market Risk for information on how hypothetical changes in commodity prices would impact the fair value of our derivatives as of September 30, 2022.
34

Dakota Access Pipeline
In response to a July 2020 U.S. District Court decision vacating the U.S. Army Corps of Engineers (“Corps”) grant of an easement to the Dakota Access Pipeline (“DAPL”) and issuance of an order requiring the Corps to conduct an environmental impact statement for the pipeline, the Corps is currently conducting the court-ordered environmental review to determine whether DAPL poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remains in operation. The owners of DAPL appealed the District Court decision to the U.S. Supreme Court in September 2021, but the appeal was rejected on February 22, 2022. The Corps paused performance of the environmental impact statement in mid-2022 but has since resumed working on the statement and has announced on its website that release of a draft environmental impact statement is expected to occur in the spring of 2023. Once the review is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. We are unable to determine the outcome or the impact of this matter on DAPL in the future.
We utilize DAPL to transport a portion of our Bakken crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline totals 30,000 barrels per day which will continue through February 2026 at which time the commitment decreases to 26,450 barrels per day through July 2028.
If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL’s takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.
Legislative and Regulatory Developments
The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. President Biden, in pursuit of his regulatory agenda, has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry 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. Such changes, if enacted, could have a material adverse effect on our results of operations and cash flows. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry in our Form 10-K for the year ended December 31, 2021 for a discussion of certain future commitmentssignificant 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 Reduction Act
In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”) into law, which provides various new tax provisions, incentives, and tax credits aimed at curbing inflation by lowering prescription drug costs, health care costs, and energy costs. The IRA introduces, among other things, (i) a 15% corporate alternative minimum tax on profits for corporations whose average annual adjusted financial statement income for any consecutive three-year period ending after December 31, 2021 exceeds $1 billion, (ii) a 1% excise tax on stock repurchases of more than $1 million made by publicly traded US corporations after December 31, 2022, (iii) a methane emissions charge, effective January 1, 2024, on specific types of oil and gas production facilities that report emissions in excess of applicable thresholds, and (iv) various updates to Section 45Q of the CompanyInternal Revenue Code to incentivize development of carbon sequestration projects such as our previously described investment in the project being developed by Summit Carbon Solutions, including increasing the value of September 30, 2017. Section 45Q tax credits, expanding eligibility for Section 45Q tax credits by extending project construction deadlines, and allowing taxpayers to elect for direct payment of Section 45Q tax credits.
We believeare in the process of evaluating the new legislation and are unable to estimate its future impact on our business at this time. Based on current expectations, we expect our average annual adjusted financial statement income over the three-year period including 2020, 2021, and 2022 will exceed the IRA's $1 billion threshold and, therefore, we expect to be subject to the 15% alternative minimum tax regime for the 2023 tax year. Because of the significant uncertainty inherent in numerous factors utilized in projecting financial statement income and taxable income, including those pertaining to future commodity prices, production, capital spending, profitability, and general economic conditions, we cannot predict what impact the minimum tax will have, if any, on our future operating results and cash flows with certainty.

SEC rule proposal on climate-related disclosures

In March 2022, the SEC proposed rule amendments that would create a wide range of new climate-related disclosure obligations for registrants. The proposed rules would require registrants to include certain climate-related information in registration statements and annual reports, including (i) climate-related risks and their actual or likely material impacts on the registrant’s business, strategy, and outlook; (ii) the registrant’s governance of climate-related risks and relevant risk
flows
35

management processes; (iii) information on the registrant’s greenhouse gas emissions, which, for accelerated and large accelerated filers and with respect to certain emissions, would be subject to assurance; (iv) certain climate-related financial statement metrics and related disclosures in a note to audited financial statements; and (v) information about climate-related targets, goals, and transition plans. The proposed rules have not been finalized and may be subject to challenges and litigation. Thus, the ultimate scope and impact of the proposed rules on our business remain uncertain. To the extent new rules, if finalized, impose additional reporting obligations on us, we could face increased costs.
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 operations, our remaininghistorically low crude oil prices. However, inflationary pressures returned in 2021 and continue to persist in 2022 in conjunction with the significant increase in commodity prices over the past year, labor shortages, and other factors. Additionally, supply chain disruptions have led to shortages of certain materials and equipment and resulting increases in material and labor costs. Our budgeted expenditures include an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash balance, and amounts available under our revolving credit facility will be sufficient to satisfy our commitments.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resources.
flow at current commodity price levels.
Critical Accounting Policies and Estimates
There have been no changes in our critical accounting policies and estimates from those disclosed in our 20162021 Form 10-K.
New Accounting Pronouncements
See Non-GAAP Financial Measures
Net crude oil, natural gas, and natural gas liquids sales and net sales prices
Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Notes to Unaudited Condensed Consolidated Financial Statements–Note 2. Basis5. Revenues. For non-operated properties, we receive a net payment from the operator for our share of Presentationsales 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 Significant Accounting Policiestransportation 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 with U.S. GAAP using gross presentation for some revenues and net presentation for others.
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, natural gas, and natural gas liquids 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, natural gas, and natural gas liquids sales," a non-GAAP measure. Average sales prices calculated using net 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. 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 discussionuseful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following tables present a reconciliation of crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for the impact upon adoption of new accounting pronouncements in 2017 along with a discussion of accounting pronouncements not yet adopted.three and nine months ended September 30, 2022 and 2021.
Three months ended September 30, 2022Three months ended September 30, 2021
In thousandsCrude oilNatural gas and NGLsTotalCrude oilNatural gas and NGLsTotal
Crude oil, natural gas, and NGL sales (GAAP)$1,738,414 $1,028,848 $2,767,262 $1,002,823 $453,358 $1,456,181 
Less: Transportation expenses(67,818)(17,832)(85,650)(45,241)(8,728)(53,969)
Net crude oil, natural gas, and NGL sales (non-GAAP)$1,670,596 $1,011,016 $2,681,612 $957,582 $444,630 $1,402,212 
Sales volumes (MBbl/MMcf/MBoe)18,674 118,116 38,360 14,404 96,188 30,435 
Net sales price (non-GAAP)$89.46 $8.56 $69.91 $66.48 $4.62 $46.07 

36

Nine months ended September 30, 2022Nine months ended September 30, 2021
In thousandsCrude oilNatural gas and NGLsTotalCrude oilNatural gas and NGLsTotal
Crude oil, natural gas, and NGL sales (GAAP)$5,343,742 $2,526,954 $7,870,696 $2,758,859 $1,227,769 $3,986,628 
Less: Transportation expenses(188,418)(48,433)(236,851)(129,218)(27,452)(156,670)
Net crude oil, natural gas, and NGL sales (non-GAAP)$5,155,324 $2,478,521 $7,633,845 $2,629,641 $1,200,317 $3,829,958 
Sales volumes (MBbl/MMcf/MBoe)53,979 325,011 108,147 43,257 274,352 88,982 
Net sales price (non-GAAP)$95.51 $7.63 $70.59 $60.79 $4.38 $43.04 

37

ITEM 3.Quantitative and Qualitative Disclosures About Market Risk    
ITEM 3.    Quantitative and Qualitative Disclosures About Market Risk    
General. We are exposed to a variety of market risks including commodity price risk, credit risk, and interest rate risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.
Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil, natural gas, and natural gas production.liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil and natural gas hasliquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the nine months ended September 30, 2017,2022, and excluding anythe effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $469$722 million for each $10.00 per barrel change in crude oil prices at September 30, 20172022 and $217$435 million for each $1.00 per Mcf change in natural gas prices at September 30, 2017.2022.
To reduce price risk caused by market fluctuations in crude oil and natural gascommodity prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program.program and general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidatesettle existing derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program.maturities. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements. We have hedged a portion of our future natural gas production through March 2018. Our future crude oil production, and future natural gas production beyond March 2018, is currently unhedged and directly exposed to continued volatility in market prices, whether favorable or unfavorable.
Changes in natural gas prices during the nine months ended September 30, 2017 had an overall favorable impact on the fair value of our derivative instruments. For the nine months ended September 30, 2017, we recognized cash gains on natural gas derivatives of $15.0 million and non-cash mark-to-market gains on natural gas derivatives of $68.5 million.
The fair value of our natural gas derivative instruments at September 30, 20172022 was a net assetliability of $9.0 million. An assumed increase in the forward prices used in the September 30, 2017 valuation$571.5 million, which is comprised of a $576.1 million net liability associated with our natural gas derivatives and a $4.6 million net asset associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of $1.00 per MMBtuour derivatives would change our natural gas derivative valuation to a net liabilityimpact the fair value estimates as of approximately $29 million at September 30, 2017. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would increase our natural gas derivative asset to approximately $43 million at September 30, 2017. 2022.
Hypothetical Fair Value
In thousandsChange in Forward PriceAsset (Liability)
Crude Oil-10%$5,368
Crude Oil+10%$3,806
Natural Gas-10%($402,572)
Natural Gas+10%($752,420)
Changes in the fair value of our natural gas derivatives from the above price sensitivities would produce a corresponding change in our total revenues.
Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($472 million1.5 billion in receivables at September 30, 2017);2022), and our joint interest and other receivables ($452430 million at September 30, 2017); and counterparty credit risk associated with our derivative instrument receivables ($11 million at September 30, 2017)2022).


We monitor our exposure to counterparties on crude oil and natural gasour commodity sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gascommodity sales receivables owed to us. Historically, our credit losses on crude oil and natural gascommodity sales receivables have been immaterial.
Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $55$17 million at September 30, 2017,2022, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner's interest in the well, to redirectnet production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.
Our use of derivative instruments involves the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties who we consider to be financially strong in order to minimize our exposure to credit risk with any individual counterparty.
38

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to any variable-rate borrowings we may have outstanding from time to time under our revolving credit facility and three-year term loan.facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.
We had no outstanding borrowings on our credit facility at October 31, 2022. As previously described, we plan to utilize credit facility borrowing capacity and enter into a new term loan facility to fund a portion of the Hamm Family’s take-private transaction. Such borrowings are expected to bear interest at variable rates derived from a SOFR benchmark reference rate plus a margin based on the terms of the applicable borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness.
We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.
We had an aggregate of approximately $1.40 billion of variable rate borrowings outstanding on our revolving credit facility and three-year term loan at October 31, 2017. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense of approximately $3.5 million per year and a $2.2 million decrease in net income per year.

ITEM 4.    Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of September 30, 20172022 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the three months ended September 30, 2017,2022, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Inherent Limitations on Controls and Procedures
A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.

39

PART II. Other Information
 
ITEM 1.Legal Proceedings
ITEM 1.    Legal Proceedings
See Note 7.9. Commitments and Contingencies–Contingencies—Litigation in Part I, Item I. Financial Statements–Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of a case filed in the legal matter involving the Company, Billy J. StrackNorthern District of California and Daniela A. Renner,a case filed in Oklahoma state court, which isare incorporated herein by reference.
We have received Notices of Violation from the North Dakota Department of Health ("NDDH") alleging violations of the state’s air quality and water pollution control laws and rules.  We exchanged information and engaged in discussions with NDDH aimed at resolving the allegations in August and October 2017, and anticipate further such discussions and exchanges.  Resolution of the allegationsmay result in monetary sanctions of more than $100,000.

ITEM 1A.Risk Factors
ITEM 1A.    Risk Factors
In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors discussed in Part II, Item 1A. Risk Factors in our Form 10-Q for the quarter ended June 30, 2022 and Part I, Item 1A. Risk Factors in our 20162021 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q, if any,our Form 10-Q for the quarter ended June 30, 2022, and in our 20162021 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
There have been noA discussion of material changes in our risk factors from those disclosed in our 2016 Form 10-K.10-Q for the quarter ended June 30, 2022 and our 2021 Form 10-K is as follows.

Omega Acquisition, Inc.’s acquisition of the Company’s common stock (other than the Rollover Shares) may not be completed within the expected timeframe, or at all; if the transaction is completed, the Company’s leverage is expected to increase and its liquidity is expected to decrease; and the market price of our common stock could decline significantly if the transaction is not completed within the expected timeframe, or at all.

On October 17, 2022, the Company announced that it entered into a definitive agreement with Merger Sub, an entity owned by the Company’s founder, Harold G. Hamm, whereby Merger Sub agreed to acquire all of the outstanding shares of common stock of the Company (other than the Rollover Shares) via an all-cash tender offer, followed by a second-step merger with and into the Company, in each case, on the terms and conditions set forth therein. The consummation of the transaction with Merger Sub is subject to closing conditions beyond the Company’s control, and there can be no assurance the transaction will be consummated. The consummation of the transaction may require the expenditure of significant time and resources by the Company, and the transaction may create uncertainty or be a distraction for our Board of Directors, management, employees, customers and business partners. Additionally, litigation has been instituted against the Company, members of its Board of Directors, and Mr. Hamm. Such litigation may result in further significant distraction, cost, and uncertainty regarding consummation of the transaction. Further, we anticipate funding the transaction through a combination of funding sources, including the use of cash on hand, utilization of credit facility borrowing capacity and an anticipated term loan facility to be entered into in connection with the closing of the transaction. As a result, our leverage is expected to increase and our liquidity is expected to decrease in connection with the transaction. The market price of our common stock may reflect various assumptions as to whether the transaction will occur or perceived uncertainties in our future direction and the market price of our stock may change significantly as a result of changing assumptions or perceptions regarding the transaction. Failure to consummate the transaction within the expected timeframe, or at all, could cause the market price of our common stock to decline significantly.

40

ITEM 2.Unregistered Sales of Equity Securities and Use of Proceeds

ITEM 2.    Unregistered Sales of Equity Securities and Use of Proceeds
(a)Recent Sales of Unregistered Securities – Not applicable.
(b)Use of Proceeds – Not applicable.

(a)Recent Sales of Unregistered Securities – Not applicable.
(b)Use of Proceeds – Not applicable.
(c)Purchases of Equity Securities by the Issuer and Affiliated Purchasers – The following table below provides information about purchases of shares of our common stock during the three months ended September 30, 2017:
Period Total number of shares purchased (1) Average price paid per share (2) Total number of shares purchased as part of publicly announced plans or programs Maximum number of  shares that may yet be purchased under the plans or programs
July 1, 2017 to July 31, 2017 —
 —
 —
 —
August 1, 2017 to August 31, 2017 8,629
 $33.14
 —
 —
September 1, 2017 to September 30, 2017 2,054
 $38.68
 —
 —
Total 10,683
 $34.21
 —
 —
(1)In connection with restricted stock grants under the Company's 2013 Long-Term Incentive Plan, we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased in the table above represent shares surrendered by employees to cover tax liabilities. We paid the associated taxes to the applicable taxing authorities.
(2)The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.

2022.
PeriodTotal number of shares purchasedAverage price paid per shareTotal number of shares purchased as part of publicly announced plans or programs (1)Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1)
July 1, 2022 to July 31, 2022:
Repurchases for tax withholdings (2)1,129 $63.76 — — 
August 1, 2022 to August 31, 2022:
Repurchases for tax withholdings (2)7,569 $68.03 — — 
September 1, 2022 to September 30, 2022:
Repurchases for tax withholdings (2)4,722 $70.89 — — 
Total for the quarter13,420 $68.68 — 
(1)In May 2019 the Board approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019 at times and levels deemed appropriate by management. The program was announced on June 3, 2019 and does not have a set expiration date. On February 8, 2022, the Board approved an increase in the size of the share repurchase program to $1.5 billion. As of September 30, 2022, we have repurchased a cumulative $540.9 million of our common stock since the inception of the program.
(2)Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.

ITEM 3.Defaults Upon Senior Securities
ITEM 3.    Defaults Upon Senior Securities
Not applicable.


ITEM 4.Mine Safety Disclosures
ITEM 4.    Mine Safety Disclosures
Not applicable.


ITEM 5.    Other Information
Not applicable.



41

ITEM 6.Exhibits
ITEM 6.    Exhibits
The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth below.
3.1
3.2
31.1*10.1
10.2*
31.1*
31.2*
32**
101.INS**Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document
101.SCH**Inline XBRL Taxonomy Extension Schema Document
101.CAL**Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE**Inline XBRL Taxonomy Extension Presentation Linkbase Document
*104Filed herewithCover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
**Furnished herewith



*    Filed herewith
**    Furnished herewith


42

SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
CONTINENTAL RESOURCES, INC.
Date:November 2, 2022CONTINENTAL RESOURCES, INC.
By:
Date:November 7, 2017By:/s/ John D. Hart
John D. Hart
Sr. Vice President, Chief Financial Officer and Treasurer
Executive Vice President of Strategic Planning
(Duly Authorized Officer and Principal Financial Officer)

3843