NEXTIER OILFIELD SOLUTIONS INC. - Quarter Report: 2021 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2021


☐			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 001-37988

NexTier Oilfield Solutions Inc.

(Exact Name of Registrant as Specified in its Charter)


Delaware			38-4016639
(State or Other Jurisdiction of Incorporation or Organization)			(I.R.S. Employer Identification No.)

3990 Rogerdale Rd.	Houston	Texas	77042
(Address of Principal Executive Offices)			(Zip Code)

(713) 325-6000

(Registrant's Telephone Number, Including Area Code)


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol	Name of Each Exchange On Which Registered
Common Stock, $0.01, par value	NEX	New 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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ 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 Filer	☐	Accelerated Filer	☒

Non-accelerated Filer	☐	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 ☒

As of November 5, 2021, the registrant had 241,968,848 shares of common stock outstanding.

TABLE OF CONTENTS


PART I.	FINANCIAL INFORMATION	3

Item 1.	Condensed Consolidated Financial Statements (Unaudited)	4

	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Operations and Comprehensive Loss	6
	Condensed Consolidated Statements of Changes in Stockholders' Equity	7
	Condensed Consolidated Statements of Cash Flows	9
	Notes to the Unaudited Condensed Consolidated Financial Statements	11

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	47

PART II.	OTHER INFORMATION	48

Item 1.	Legal Proceedings	48

Item 1A.	Risk Factors	48

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48

Item 3.	Defaults Upon Senior Securities	48

Item 4.	Mine Safety Disclosures	48

Item 5.	Other Information	49

Item 6.	Exhibits	50

	Signatures	51

REFERENCES WITHIN THIS QUARTERLY REPORT

As used in this Quarterly Report on Form 10-Q, unless the context otherwise requires, references to (i) the terms “Company,” “NexTier,” “we,” “us” and “our” refer to NexTier Oilfield Solutions Inc. and its consolidated subsidiaries; (ii) the term “Keane Group” refers to Keane Group Holdings, LLC and its consolidated subsidiaries; (iii) the term “Keane Investor” refers to Keane Investor Holdings LLC; (iv) the term “Cerberus” refers to Cerberus Capital Management, L.P. and its controlled affiliates and investment funds; (v) the term “C&J” refers to C&J Energy Services, Inc.; (vi) the term “C&J Merger” refers to the consummation of the transactions described in that certain Agreement and Plan of Merger, dated as of June 16, 2019 (the “Merger Agreement”), by and among the C&J, us and King Merger Sub Corp., one of our wholly owned subsidiaries; and (v) the term "Alamo" refers to Alamo Pressure Pumping, LLC and its consolidated subsidiaries. As used in this Quarterly Report on Form 10-Q, capacity in the hydraulic fracturing business refers to the total number of hydraulic horsepower, regardless of whether such hydraulic horsepower is active and deployed, active and not deployed or inactive. While the equipment and amount of hydraulic horsepower required for a customer project varies, we calculate our total number of fleets, as used in this Quarterly Report on Form 10-Q, by dividing our total hydraulic horsepower by approximately 49,000 hydraulic horsepower.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS AND INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, which are subject to risks and uncertainties. All statements other than statements of historical facts contained in this Quarterly Report on Form 10-Q, including statements regarding our future operating results and financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. Our forward-looking statements are generally accompanied by words such as "may," "should," "expect," "believe," "plan," "anticipate," "could," "intend," "target," "goal," "project," "contemplate," "believe," "estimate," "predict," "potential," or "continue," or the negative of these terms or other similar expressions. Any forward-looking statements contained in this Quarterly Report on Form 10-Q speak only as of the date on which we make them and are based upon our historical performance and on current plans, estimates and expectations. Except as required by law, we have no obligation to update any forward-looking statements made in this Quarterly Report on Form 10-Q to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q or to reflect new information or the occurrence of unanticipated events. Forward-looking statements contained in this Quarterly Report on Form 10-Q include, but are not limited to, statements about:

•the impact of the COVID-19 pandemic and the evolving response thereto, including the impact of social distancing, shelter-in-place, shutdowns of non-essential businesses, extended absences and similar measures imposed or undertaken by governments, private businesses or others;

•changing regional, national or global economic conditions, including oil and gas supply and demand, trucking and logistics issues, labor market and inflation;

•our business strategy;

•our plans, objectives, expectations and intentions;

•the competitive nature of the industry in which we conduct our business, including pricing pressures;

•our future operating results;

•crude oil and natural gas commodity prices;

•demand for services in our industry;

•our ability to maintain the right level of commitments under our supply agreements;

•the market price and availability of materials or equipment, including loss of equipment due to age, maintenance downtime, casualty event or longer lead times (due to shipping delays, shortages of components, or other);

•the effect of a loss of, or interruption in operations of, one or more key suppliers;

•the impact of pipeline and storage capacity constraints;

•the impact of adverse weather conditions;

•the effects of government regulation and administrative or political policies;

•changes in tax laws;

•legal proceedings, liability claims and effect of external investigations;

•the effect of a loss of, or the financial distress of, one or more customers;

•our ability to obtain or renew customer contracts;

•our ability to recover insurance proceeds, including those related to a casualty event;

•our ability to employ a sufficient number of skilled and qualified workers, including any related wage inflation;

•our ability to obtain permits, approvals and authorizations from governmental and third parties;

•planned acquisitions, divestitures, and future capital expenditures;

•the impact of new technology;

•our ability to maintain effective information technology security systems;

•our ability to maintain an effective system of internal controls over financial reporting;

•our ability to service our debt obligations;

•financial strategy, liquidity or capital required for our ongoing operations and acquisitions, and our ability to raise additional capital;

•the market volatility of our stock;

•our ability or intention to pay dividends or to effectuate repurchases of our common stock;

•the impact of ownership by Cerberus (through Keane Investor); and

•the impact of our corporate governance structure.

We caution you that the foregoing list may not contain all of the forward-looking statements made in this Quarterly Report on Form 10-Q.

You should not rely upon forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this Quarterly Report on Form 10-Q primarily on our current expectations and projections about future events and trends that we believe may affect our business, financial condition, results of operations and prospects. The outcome of the events described in these forward-looking statements is subject to risks, uncertainties and other factors described in the section entitled Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2020. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks and uncertainties that could have an impact on the forward-looking statements contained in this Quarterly Report on Form 10-Q. We cannot assure you that the results, events, circumstances, plans, intentions or expectations reflected in any forward-looking statements will be achieved or occur. Actual results, events or circumstances could differ materially from those described in such forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures or investments we may make, except as specifically set forth herein.

This Quarterly Report on Form 10-Q includes market and industry data and certain other statistical information based on third-party sources including independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. Some data is also based on our own good faith estimates, which are supported by our management's knowledge of and experience in the markets and businesses in which we operate.

While we are not aware of any misstatements regarding any market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed above and in Part I, "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2020.

PART I

Item 1. Condensed Consolidated Financial Statements (Unaudited)

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Amounts in thousands)


	September 30, 2021		December 31, 2020
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	135,525	$	275,990
Trade and other accounts receivable, net	265,388		122,584
Inventories, net	38,108		30,068
Assets held for sale	6,495		126
Prepaid and other current assets	51,352		58,011
Total current assets	496,868		486,779
Operating lease right-of-use assets	22,980		37,157
Finance lease right-of-use assets	35,746		1,132
Property and equipment (net of accumulated depreciation of $964,005 and $929,290)	592,112		470,711
Goodwill	192,446		104,198
Intangible assets (net of accumulated amortization of $54,159 and $46,496)	69,527		51,182
Other noncurrent assets	8,296		6,729
Total assets	$	1,417,975	$	1,157,888

Liabilities and Stockholders' Equity

Current liabilities:
Accounts payable	$	179,203	$	61,259
Accrued expenses	222,720		134,230
Customer contract liabilities	26,798		266
Current maturities of long-term operating lease liabilities	8,725		18,551
Current maturities of long-term finance lease liabilities	10,438		606
Current maturities of long-term debt	11,186		2,252
Other current liabilities	2,543		2,993
Total current liabilities	461,613		220,157
Long-term operating lease liabilities, less current maturities	20,580		24,232
Long-term finance lease liabilities, less current maturities	25,053		504
Long-term debt, net of unamortized deferred financing costs and unamortized debt discount, less current maturities	361,836		333,288
Other noncurrent liabilities	20,722		22,419
Total noncurrent liabilities	428,191		380,443
Total liabilities	889,804		600,600


Stockholders' equity

Common stock, par value $0.01 per share (authorized 500,000 shares, issued and outstanding 241,963 and 214,440 shares, respectively)	2,420		2,144
Paid-in capital in excess of par value	1,087,618		989,995
Retained deficit	(552,018)		(421,741)
Accumulated other comprehensive loss	(9,849)		(13,110)
Total stockholders' equity	528,171		557,288
Total liabilities and stockholders' equity	$	1,417,975	$	1,157,888

See accompanying notes to unaudited condensed consolidated financial statements.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Operations and Comprehensive Loss

(Amounts in thousands, except for per share amounts)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenue	$	393,164	$	163,675	$	913,711	$	987,527
Operating costs and expenses:
Cost of services(1)	344,637		150,066		831,674		841,063
Depreciation and amortization	44,861		73,570		131,400		234,651
Selling, general and administrative expenses	37,453		25,521		74,256		120,429
Merger and integration	4,752		7,288		4,930		33,498
Gain on disposal of assets	(1,133)		(3,027)		(7,742)		(11,942)
Impairment expense	—		2,681		—		37,008
Total operating costs and expenses	430,570		256,099		1,034,518		1,254,707
Operating loss	(37,406)		(92,424)		(120,807)		(267,180)
Other income (expense):
Other income (expense), net	585		(3,978)		9,113		(1,303)
Interest expense, net	(6,701)		(5,524)		(16,633)		(16,943)
Total other expense	(6,116)		(9,502)		(7,520)		(18,246)
Loss before income taxes	(43,522)		(101,926)		(128,327)		(285,426)
Income tax expense	(472)		(507)		(1,950)		(1,251)
Net loss	(43,994)		(102,433)		(130,277)		(286,677)
Other comprehensive loss, net of tax:
Foreign currency translation adjustments	531		(157)		433		596
Hedging activities	(46)		(453)		785		(6,068)
Total comprehensive loss	$	(43,509)	$	(103,043)	$	(129,059)	$	(292,149)

Net loss per share:
Basic net loss per share	$	(0.20)	$	(0.48)	$	(0.60)	$	(1.34)
Diluted net loss per share	(0.20)		(0.48)		(0.60)		(1.34)

Weighted-average shares outstanding: basic	224,481		214,251		218,499		213,620
Weighted-average shares outstanding: diluted	224,481		214,251		218,499		213,620

(1) Cost of services during the three and nine months ended September 30, 2021 excludes depreciation of $40.5 million and $118.1 million. Cost of services during the three and nine months ended September 30, 2020 excludes depreciation of $68.9 million and $220.9 million, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Changes in Stockholders' Equity

(Amounts in thousands)

(Unaudited)


	Common stock		Paid-in capital in excess of par value		Retained deficit		Accumulated other comprehensive loss		Total
Balance as of December 31, 2020	$	2,144	$	989,995	$	(421,741)	$	(13,110)	$	557,288

Stock-based compensation	10		5,193		—		—		5,203
Shares repurchased and retired related to stock-based compensation	(1)		(1,009)		—		—		(1,010)
Other comprehensive income	—		—		—		2,349		2,349
Net loss	—		—		(54,502)		—		(54,502)
Balance as of March 31, 2021	$	2,153	$	994,179	$	(476,243)	$	(10,761)	$	509,328
Stock-based compensation	5		4,884		—		—		4,889
Shares repurchased and retired related to stock-based compensation	(1)		(435)		—		—		(436)
Other comprehensive loss	—		—		—		(267)		(267)
Net loss	—		—		(31,781)		—		(31,781)
Balance as of June 30, 2021	$	2,157	$	998,628	$	(508,024)	$	(11,028)	$	481,733
Stock-based compensation	4		7,346		—		—		7,350
Shares repurchased and retired related to stock-based compensation	(1)		(419)		—		—		(420)
Equity issued in connection with Alamo Acquisition	260		82,063		—		—		82,323
Other comprehensive loss	—		—		—		1,179		1,179
Net loss	—		—		(43,994)		—		(43,994)
Balance as of September 30, 2021	$	2,420	$	1,087,618	$	(552,018)	$	(9,849)	$	528,171

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Changes in Stockholders' Equity

(Amounts in thousands)

(Unaudited)


	Common stock		Paid-in capital in excess of par value		Retained deficit		Accumulated other comprehensive loss		Total
Balance as of December 31, 2019	$	2,124	$	966,762	$	(73,333)	$	(8,781)	$	886,772

Stock-based compensation	11		6,869		—		—		6,880
Shares repurchased and retired related to stock-based compensation	(2)		(1,149)		—		—		(1,151)
Other comprehensive loss	—		—		—		(1,513)		(1,513)
Credit losses standard implementation	—		—		(1,525)		—		(1,525)
Net loss	—		—		(71,756)		—		(71,756)
Balance as of March 31, 2020	$	2,133	$	972,482	$	(146,614)	$	(10,294)	$	817,707
Stock-based compensation	12		9,511		—		—		9,523
Shares repurchased and retired related to stock-based compensation	(4)		(789)		—		—		(793)
Other comprehensive loss	—		—		—		(2,360)		(2,360)
Net loss	—		—		(112,488)		—		(112,488)
Balance as of June 30, 2020	$	2,141	$	981,204	$	(259,102)	$	(12,654)	$	711,589
Stock-based compensation	4		4,744		—		—		4,748
Shares repurchased and retired related to stock-based compensation	(1)		(48)		—		—		(49)
Other comprehensive loss	—		—		—		63		63
Net income	—		—		(102,433)		—		(102,433)
Balance as of September 30, 2020	$	2,144	$	985,900	$	(361,535)	$	(12,591)	$	613,918

See accompanying notes to unaudited condensed consolidated financial statements.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Amounts in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2021		2020
Cash flows from operating activities:
Net loss	$	(130,277)	$	(286,677)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation and amortization	131,400		234,651
Amortization of deferred financing fees	1,528		1,710

Gain on disposal of assets	(7,742)		(11,942)




Loss on impairment of assets	—		37,008
Unrealized (gain) loss on derivative recognized in other comprehensive loss	785		(6,068)
Loss on financial instrument and derivatives, net	4,142		4,109
Stock-based compensation	17,442		21,151
Gain on insurance proceeds recognized in other income	(10,409)		—


Changes in operating assets and liabilities:
Decrease (increase) in trade and other accounts receivable, net	(92,184)		208,924


Decrease (increase) in inventories	(9,046)		20,690
Increase in prepaid and other current assets	(10,138)		(607)
Decrease in other assets	14,203		20,108
Increase (decrease) in accounts payable	59,072		(65,149)
Increase (decrease) in accrued expenses	42,951		(87,736)
Increase (decrease) in customer contract liabilities	(3,468)		685
Decrease in other liabilities	(27,579)		(8,181)
Net cash provided by (used in) operating activities	(19,320)		82,676
Cash flows from investing activities:

Proceeds from sale of business	—		53,666
Purchase of property and equipment	(132,057)		(96,649)
Advances of deposit on equipment	(543)		—
Implementation of software	(2,532)		(7,191)
Proceeds from disposal of assets	24,470		24,807
Acquisition of business	(95,082)		—

Payment of consideration liability	(6,671)		—
Proceeds from settlement of WSS Notes and make-whole derivative	34,350		—
Proceeds from insurance recoveries	22,947		58

Net cash used in investing activities	(155,118)		(25,309)
Cash flows from financing activities:


Proceeds from asset-based revolver and equipment loan	39,428		175,000
Payments on the term loan facility and asset-based revolver	(2,625)		(177,625)
Payments on finance leases	(1,146)		(3,148)
Payment of debt issuance costs	(251)		—





Shares repurchased and retired related to stock-based compensation	(1,866)		(1,993)

Net cash provided by (used in) financing activities	33,540		(7,766)
Non-cash effect of foreign translation adjustments	433		596
Net increase (decrease) in cash, cash equivalents	(140,465)		50,197
Cash and cash equivalents, beginning	275,990		255,015
Cash and cash equivalents, ending	$	135,525	$	305,212

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Amounts in thousands)

(Unaudited)



Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest expense, net	$	16,469	$	16,122
Income taxes	—		1,206
Non-cash investing and financing activities:
Change in accrued capital expenditures	$	(19,763)	$	8,643
Non-cash additions to equity security investments	—		5,263
Non-cash additions to finance right-of-use assets	35,813		—
Non-cash additions to finance lease liabilities, including current maturities	(35,813)		—
Non-cash additions to operating right-of-use assets	3,352		8,715
Non-cash additions to operating lease liabilities, including current maturities	(512)		(8,676)


26,000,000 shares of NexTier common stock issued in exchange for Alamo ownership	(82,323)		—
Total contingent consideration	(45,944)
Non contingent consideration	(7,370)

See accompanying notes to unaudited condensed consolidated financial statements.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(1) Basis of Presentation and Nature of Operations

The accompanying unaudited condensed consolidated financial statements were prepared using United States Generally Accepted Accounting Principles ("GAAP") and the instructions to Form 10-Q and Regulation S-X. Accordingly, these financial statements do not include all information or notes required by GAAP for annual financial statements and should be read together with the Company's Annual Report on Form 10-K for the year ended December 31, 2020, filed with the Securities and Exchange Commission (the "SEC") on February 24, 2021.

The Company’s accounting policies are in accordance with GAAP. The preparation of financial statements in conformity with these accounting principles requires the Company to make estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenue and expenses during the reporting period. Ultimate results could differ from the Company’s estimates. Significant items subject to such estimates and assumptions include the useful lives of property and equipment and intangible assets; allowances for doubtful accounts; inventory reserves; acquisition accounting; contingent liabilities; and the valuation of property and equipment, intangible assets, equity issued as consideration in an acquisition, income taxes, stock-based incentive plan awards and derivatives.

Management believes the unaudited condensed consolidated financial statements included herein contain all adjustments necessary to present fairly the Company's financial position as of September 30, 2021 and the results of its operations and cash flows for the three and nine months ended September 30, 2021 and 2020. Such adjustments are of a normal recurring nature. All intercompany transactions and balances have been eliminated.

On October 31, 2019, the Company completed its merger (the “C&J Merger”) with C&J Energy Services, Inc. (“C&J”) and changed its name to "NexTier Oilfield Solutions Inc." Merger and integration related costs were recognized separately from the acquisition of assets and assumptions of liabilities in the C&J Merger. Merger costs consist of legal and professional fees and pre-merger notification fees. Integration costs consist of expenses incurred to integrate C&J’s operations, aligning accounting processes and procedures, and integrating its enterprise resource planning system with those of the Company. All of these costs are recorded within merger and integration costs on the Company’s Condensed Consolidated Statements of Operations and Comprehensive Loss. See Note (3) Mergers and Acquisitions in Part I, "Item 8. Financial Statements and Supplementary" of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020 for further information.

In addition, on March 9, 2020, the Company completed the divestiture of its Well Support Services Segment ("WSS Sale"). For more details regarding the WSS Sale, refer to Note (14) Business Segments.

On August 31, 2021 the Company completed its acquisition (the “Alamo Acquisition”) of Alamo Pressure Pumping, LLC and its wholly owned subsidiaries ("Alamo"). The unaudited condensed consolidated financial statements for the period from January 1, 2020 to August 31, 2021 reflect only the historical results of the Company prior to the completion of the Alamo Acquisition.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(2) Summary of Significant Accounting Policies

(a) Business Combinations and Asset Acquisitions

Business combinations are accounted for using the acquisition method of accounting in accordance with the Accounting Standards Codification (“ASC”) 805, “Business Combinations”, as amended by Accounting Standards Update (“ASU”) 2017-01, “Business Combinations (Topic 805), Clarifying the Definition of a Business.” The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 820, using discounted cash flows and other applicable valuation techniques. Every reporting period, the Company reassess the value of any contingent consideration assumed as part of a business acquisition. Any acquisition-related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in the Company’s results of operations from the date of acquisition..

Asset acquisitions are measured based on their cost to the Company, including transaction costs. Asset acquisition costs, or the consideration transferred by the Company, are assumed to be equal to the fair value of the net assets acquired. If the consideration transferred is cash, measurement is based on the amount of cash the Company paid to the seller, as well as transaction costs incurred. Consideration given in the form of non-monetary assets, liabilities incurred or equity interests issued is measured based on either the cost to the Company or the fair value of the assets or net assets acquired, whichever is more clearly evident. The cost of an asset acquisition is allocated to the assets acquired based on their estimated relative fair values. Goodwill is not recognized in an asset acquisition.

Since the acquisition date, Alamo has adopted all of the Company's accounting policies.

(b) Revenue Recognition

The majority of the Company’s performance obligations are satisfied over time. The Company has determined this best represents the transfer of value from its services to the customer as performance by the Company helps to enhance a customer controlled asset (e.g., unplugging a well, enabling a well to produce oil or natural gas). Measurement of the satisfaction of the performance obligation is measured using the output method, which is typically evidenced by a field ticket. A field ticket includes items such as services performed, consumables used, and man hours incurred to complete the job for the customer. Each field ticket is used to invoice customers. Payment terms for invoices issued are in accordance with a master services agreement with each customer, which typically require payment within 30 to 60 days of the invoice issuance.

A portion of the Company’s contracts contain variable consideration; however, this variable consideration is typically unknown at the time of contract inception, and is not known until the job is complete, at which time the variability is resolved. Examples of variable consideration include the number of hours that will be incurred and the amount of consumables (such as chemicals and proppants) that will be used to complete a job.

Remaining Performance Obligations

The Company invoices its customers for the services provided at contractual rates multiplied by the applicable unit of measurement, including volume of consumables used and hours incurred. In accordance with ASC 606, the Company has elected the “Right to Invoice” practical expedient for all contracts, which allows the Company to invoice its customers in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. With this election, the Company is not required to disclose information about the variable consideration related to its remaining performance obligations. The Company has also elected the practical expedient to expense immediately mobilization costs, as the amortization period would always be less than one year. For those contracts with a term of more than one year, the Company had approximately $30.7 million of unsatisfied performance obligations as of September 30, 2021, which will be recognized as services are performed over the remaining contractual terms.

The Company’s obligations for refunds as well as the warranties and related obligations stated in its contracts with its customers are standard to the industry and are related to the correction of any defectiveness in the execution of its performance obligations.

Contract Balances

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

In line with industry practice, the Company bills its customers for its services in arrears, typically when the stage or well is completed or at month-end. The majority of the Company’s jobs are completed in less than 30 days. Furthermore, it is currently not standard practice for the Company to execute contracts with prepayment features. Payment terms after invoicing are typically 30 to 60 days.

The Company does not have any significant contract costs to obtain or fulfill contracts with customers; as such, no amounts are recognized on the consolidated balance sheet. Taxes collected from customers and remitted to governmental authorities are accounted for on a net basis and, therefore, are excluded from revenues in the Condensed Consolidated Statements of Operations and Comprehensive Loss and net cash provided by operating activities in the Condensed Consolidated Statements of Cash Flows.

The following is a description of the Company’s core service lines separated by reportable segments from which the Company generates its revenue. For additional detailed information regarding reportable segments, see Note (14) Business Segments.

Revenue from the Company’s Completion Services, Well Construction and Intervention (“WC&I”), and Well Support Services segments are recognized as follows:

Completion Services

The Company provides hydraulic fracturing, wireline and pumpdown services pursuant to contractual arrangements, such as term contracts and pricing agreements. Revenue from these services are earned as services are rendered, which is generally on a per stage or fixed monthly rate. All revenue is recognized when a contract with a customer exists, the performance obligations under the contract have been satisfied over time, the amount to which the Company has the right to invoice has been determined and collectability of amounts subject to invoice is probable. Contract fulfillment costs, such as mobilization costs and shipping and handling costs, are expensed as incurred and are recorded in cost of services in the Condensed Consolidated Statements of Operations and Comprehensive Loss. To the extent fulfillment costs are considered separate performance obligations that are billable to the customer, the amounts billed are recorded as revenue in the Condensed Consolidated Statements of Operations and Comprehensive Loss.

Once a stage has been completed, a field ticket is created that includes charges for the service performed and the chemicals and proppant consumed during the course of the service. The field ticket may also include charges for the mobilization of the equipment to the location, any additional equipment used on the job and other miscellaneous items. The field ticket represents the amounts to which the Company has the right to invoice and to recognize as revenue.

All revenues from Alamo will be recognized in the West Texas region of the Company's Completions segment.

Well Construction and Intervention

The Company provides cementing services pursuant to contractual arrangements, such as term contracts, or on a spot market basis. Revenue is recognized upon the completion of each performance obligation, which for cementing services, represents the portion of the well cemented: surface casing, intermediate casing or production liner. The performance obligations are satisfied over time. Jobs for these services are typically short term in nature, with most jobs completed in a day. Once the well has been cemented, a field ticket is created that includes charges for the services performed and the consumables used during the course of service. The field ticket represents the amounts to which the Company has the right to invoice and to recognize as revenue.

The Company provides a range of coiled tubing services primarily used for fracturing plug drill-out during completion operations and for well workover and maintenance, primarily on a spot market basis. Jobs for these services are typically short-term in nature, lasting anywhere from a few hours to multiple days. Revenue is recognized upon completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the services performed and the consumables used during the course of service. The field ticket may also include charges for the mobilization and set-up of equipment, the personnel on the job, any additional equipment used on the job, and other miscellaneous consumables. The Company typically charges the customer for the services performed and resources provided on an hourly basis at agreed-upon spot market rates, at times, or pursuant to pricing agreements.

Historical Segment: Well Support Services Segment

On March 9, 2020, the Company completed the divestiture of its Well Support Services Segment. For additional information, see Note (14) Business Segments. Through its rig services line, the Company had provided workover and well servicing rigs that were primarily used for routine repair and maintenance of oil and gas wells, re-drilling operations and plug and abandonment operations.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

These services were provided on an hourly basis at prices that approximate spot market rates. A field ticket was generated and revenue is recognized upon the earliest of the completion of a job or at the end of each day. A rig services job can last anywhere from a few hours to multiple days depending on the type of work being performed. The field ticket includes the base hourly rate charge and, if applicable, charges for additional personnel or equipment not contemplated in the base hourly rate. The field ticket may also include charges for the mobilization and set-up of equipment.

Through its fluids management service line, the Company used to provide storage, transportation and disposal services for fluids used in the drilling, completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour, or per load basis, or on the basis of quantities sold or disposed. Revenue is recognized upon the completion of each job or load, or delivered product, based on a completed field ticket.

Through its other special well site service line, the Company used to provide fishing, contract labor and tool rental services for completion and workover of oil and gas wells. Rates for these services vary and can be on a per job, per hour or on the basis of rental days per month. Revenue is recognized based on a field ticket issued upon the completion of each job or on a monthly billing for rental services provided.

Disaggregation of Revenue

Revenue activities during the three and nine months ended September 30, 2021 and 2020 were as follows:


	Three Months Ended September 30, 2021						Nine Months Ended September 30, 2021
	(Thousands of Dollars)						(Thousands of Dollars)
	Completion Services		WC&I		Well Support Services		Total		Completion Services		WC&I		Well Support Services		Total
Geography
Northeast	$	64,140	$	4,859	$	—	$	68,999	$	177,448	$	16,978	$	—	$	194,426
Central	72,861		—		—		72,861		162,410		—		—		162,410
West Texas	168,176		20,902		—		189,078		407,643		49,511		—		457,154
West	50,511		1,336		—		51,847		60,794		3,335		—		64,129
International	10,379		—		—		10,379		35,592		—		—		35,592
	$	366,067	$	27,097	$	—	$	393,164	$	843,887	$	69,824	$	—	$	913,711


	Three Months Ended September 30, 2020						Nine Months Ended September 30, 2020
	(Thousands of Dollars)						(Thousands of Dollars)
	Completion Services		WC&I		Well Support Services		Total		Completion Services		WC&I		Well Support Services		Total
Geography
Northeast	$	58,099	$	3,704	$	—	$	61,803	$	217,752	$	16,728	$	—	$	234,480
Central	20,139		—		—		20,139		100,654		7,478		—		108,132
West Texas	55,416		5,094		—		60,510		388,413		48,830		8,373		445,616
West	9,278		861		—		10,139		108,004		10,698		49,556		168,258

International	11,084		—		—		11,084		31,041		—				31,041
	$	154,016	$	9,659	$	—	$	163,675	$	845,864	$	83,734	$	57,929	$	987,527

Property and equipment, inclusive of equipment under finance lease, are generally stated at cost.

Depreciation on property and equipment is calculated using the straight-line method over the estimated useful lives of the assets, which range from 13 months to 40 years. Management determines the estimate of the useful lives and salvage values of

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

property and equipment on expected utilization, technological change and effectiveness of its maintenance programs. Depreciation methods, useful lives and residual values are reviewed annually or as needed based on activities related to specific assets. When components of an item of property and equipment are identifiable and have different useful lives, they are accounted for separately as major components of property and equipment.

Gains and losses on disposal of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized net within operating costs and expenses in the Condensed Consolidated Statements of Operations and Comprehensive Loss.

Major classifications of property and equipment and their respective useful lives are as follows:


Land			Indefinite life
Building and leasehold improvements			13 months – 40 years
Machinery and equipment			13 months – 10 years
Office furniture, fixtures and equipment			3 years – 5 years

Leasehold improvements are assigned a useful life equal to the term of the related lease. Depreciation methods, useful lives and residual values are reviewed annually.

Leasehold improvements are assigned a useful life equal to the term of the related lease, or its expected period of use.

In the first quarter of 2021, the Company reassessed the estimated useful lives of select machinery and equipment, concluding that due to a decrease in service intensity for select machinery and equipment driven by operational parameters required to maximize natural gas substitution and longer major component lives attributable to equipment health monitoring and predictive maintenance from our proprietary digital NexHub platform and data science efforts, the useful lives of select machinery and equipment should be increased by 1-2 years depending on the specific asset class. In accordance with ASC 250, “Accounting Changes and Error Corrections,” the change in the estimated useful lives of the Company’s property and equipment was accounted for as a change in accounting estimate, on a prospective basis, effective January 1, 2021. This change resulted in a decrease in depreciation expense and decrease in net loss during the three and nine months ended September 30, 2021 of $7.5 million and 29.1 million, respectively, in the Consolidated Statement of Operations and Comprehensive Loss.

On May 9, 2021, one of the Company’s hydraulic frac fleets operating in the Permian Basin was involved in an accidental fire, which resulted in a complete loss of the equipment; no parties were injured as a result of this incident. In the second quarter of 2021, the Company recognized a $21.7 million receivable related to insurance proceeds in other current assets for replacement costs of the damaged equipment, which offset the $12.0 million loss recognized on the damaged equipment and costs to remove the equipment. The resulting gain of $9.7 million was recognized in the second quarter of 2021, in other income (expense), net in the Condensed Consolidated Statements of Operations and Comprehensive Loss.

During the three months ended September 30, 2021 the Company has received an additional $1.2 million in insurance proceeds, offset by additional costs of $0.5 million. The resulting additional gain of $0.7 million was recognized in the third quarter of 2021 in other income (expense), net in the Condensed Consolidated Statements of Operations and Comprehensive Loss.

Amortization on definite-lived intangible assets is calculated on the straight-line method over the estimated useful lives of the assets, which range from 2 to 15 years. The majority of the Company's definite lived intangible assets include customer contracts and technology.

Property and equipment and definite-lived intangible assets (“Long-lived Assets”) are evaluated on a quarterly basis to identify events or changes in circumstances, referred to as triggering events that indicate the carrying value of certain property and equipment may not be recoverable or upon the occurrence of a triggering event. An impairment loss is recorded in the period in which it is determined that the carrying amount of Long-lived Asset is not recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets with such cash flows to be realized over the estimated remaining useful life of the primary asset within the asset group. The Company determined the lowest level of identifiable cash flows that are independent of other asset groups to be primarily at the service line level. The Company's asset groups consist of fracturing services, wireline, cementing, and coiled tubing, except for an entity level asset group for Long-lived Assets that do not have identifiable independent

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

cash flows. Estimates of undiscounted future net cash flows of assets groups are projected based on estimates of projected revenue growth, unit count, utilization, pricing, gross profit rates, SG&A rates, working capital fluctuations and capital expenditures. Forecasted cash flows take into account known market conditions as of the assessment date, and management’s anticipated business outlook. A terminal period is used to reflect an estimate of stable, perpetual growth. If the estimated undiscounted future net cash flows for a given asset group is less than the carrying amount of the asset groups, an impairment loss is determined by comparing the estimated fair value with the carrying value of the related asset groups. The impairment loss is then allocated across the asset group's major classifications.

During the first quarter of 2020, management determined the reductions in commodity prices driven by the potential impact of the novel COVID-19 pandemic and global supply and demand dynamics coupled with the sustained decrease in the Company’s share price were deemed triggering events. As a result of the triggering event, recoverability testing was performed and it was determined that the estimated undiscounted future net cash flow for all asset groups was greater than the carrying amount of their related assets and no impairment loss was recorded.

The Company did not recognize any impairment charges related to the Company’s long-lived assets for the three and nine months ended September 30, 2021 or 2020.

(d) Leases

In accordance with ASU 2016-02, the Company considers any contract that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration to be a lease. The Company determines whether the contract into which it has entered is a lease at the lease commencement date. Rental arrangements with term lengths of one month or less are expensed as incurred, but not recognized as qualifying leases.

For lessees, leases can be classified as finance leases or operating leases, while for lessors, leases can be classified as sales-type leases, direct financing leases or operating leases. As lessee, all leases, with the exception of short-term leases, are capitalized on the balance sheet by recording a lease liability, which represents the Company's obligation to make lease payments arising from the lease and a right-of-use asset, which represents the Company's right to use the underlying asset being leased.

For leases in which the Company is the lessee, the Company uses a collateralized incremental borrowing rate to calculate the lease liability, as for most leases, the implicit rate in the lease is unknown. The collateralized incremental borrowing rate is based on a yield curve over various term lengths that approximates the borrowing rate the Company would receive if it collateralized its lease arrangements with all of its assets. For leases in which the Company is the lessor, the Company uses the rate implicit in the lease.

For finance leases, the Company amortizes the right-of-use asset on a straight-line basis over the earlier of the useful life of the right-of-use asset or the end of the lease term and records this amortization in depreciation and amortization expense on the Condensed Consolidated Statements of Operations and Comprehensive Loss. For finance leases where the Company has determined it is reasonably certain to exercise a purchase option to acquire the underlying asset, the lessee amortizes the ROU asset to the later of the end of the underlying asset’s useful life or lease term and records this amortization in depreciation and amortization expense on the Condensed Consolidated Statements of Operations and Comprehensive Loss. The Company adjusts the lease liability to reflect lease payments made during the period and interest incurred on the lease liability using the effective interest method. The incurred interest expense is recorded in interest expense on the Condensed Consolidated Statements of Operations and Comprehensive Loss. For operating leases, the Company recognizes one single lease cost, comprised of the lease payments and amortization of any associated initial direct costs, within rent expense on the Condensed Consolidated Statements of Operations and Comprehensive Loss. Variable lease costs not included in the determination of the lease liability at the commencement of a lease are recognized in the period when the specified target that triggers the variable lease payments becomes probable.

In accordance with ASC 842, the Company has made the following elections for its lease accounting:

•all short-term leases with term lengths of 12 months or less will not be capitalized; the underlying class of assets to which the Company has applied this expedient is primarily its apartment leases;

•for non-revenue contracts containing both lease and non-lease components, both components will be combined and accounted for as one lease component and accounted for under ASC 842; and

•for revenue contracts containing both lease and non-lease components, both components will be combined and accounted for as one component and accounted for under ASC 606.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(e) Derivative Instruments and Hedging Activities

The Company utilizes interest rate derivatives to manage interest rate risk associated with its floating-rate borrowings. The Company recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive loss until the hedged item affects earnings.

The Company only enters into derivative contracts that it intends to designate as hedges for the variability of cash flows to be received or paid related to a recognized asset or liability (i.e. cash flow hedge). For all hedging relationships, the Company formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively. The Company also formally assesses, both at the inception of the hedging relationship and on an ongoing basis, whether the derivatives that are used in hedging relationships are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging relationship, the gain or loss on the derivative is reported as a component of other comprehensive loss and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.

The Company discontinues hedge accounting prospectively, when it determines that the derivative is no longer highly effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the originally forecasted transaction is no longer probable of occurring or if management decides to remove the designation of the cash flow hedge. The net derivative instrument gain or loss related to a discontinued cash flow hedge shall continue to be reported in accumulated other comprehensive loss and reclassified into earnings in the same period or periods during which the originally hedged transaction affects earnings, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period. When it is probable that the originally forecasted transaction will not occur by the end of the originally specified time period, the Company recognizes immediately, in earnings, any gains and losses related to the hedging relationship that were recognized in accumulated other comprehensive loss. In all situations in which hedge accounting is discontinued and the derivative remains outstanding, the Company continues to carry the derivative at its fair value on the consolidated balance sheets and recognizes any subsequent changes in the derivative’s fair value in earnings.

In addition, we evaluate the terms of our operating agreements and other contracts, if any, to determine whether they contain embedded components that are required to be bifurcated and accounted for separately as derivative financial instruments. For additional detailed information regarding derivatives, see Note (8) Derivatives.

(f) Stock-based compensation

The Company recognizes compensation expense for restricted stock awards, restricted stock units to be settled in common stock (“RSUs”), performance-based RSU award (“PSUs”), and non-qualified stock options (“stock options”) based on the fair value of the awards at the date of grant. The fair value of restricted stock awards and RSUs is determined based on the number of shares or RSUs granted and the closing price of the Company’s common stock on the date of grant. The fair value of stock options is determined by applying the Black-Scholes model to the grant-date market value of the underlying common shares of the Company. The fair value of PSUs with market conditions is determined using a Monte Carlo simulation method. The Company has elected to recognize forfeiture credits for these awards as they are incurred, as this method best reflects actual stock-based compensation expense.

Compensation expense from time-based restricted stock awards, RSUs, PSUs, and stock options is amortized on a straight-line basis over the requisite service period, which is generally the vesting period.

Tax deductions on the stock-based compensation awards are not realized until the awards are vested or exercised. The Company recognizes deferred tax assets for stock-based compensation awards that will result in future deductions on its income tax returns, based on the amount of tax deduction for stock-based compensation recognized at the statutory tax rate in the jurisdiction in which the Company will receive a tax deduction. If the tax deduction for a stock-based award is greater than the cumulative GAAP compensation expense for that award upon realization of a tax deduction, an excess tax benefit will be recognized and recorded as a favorable impact on the effective tax rate. If the tax deduction for an award is less than the cumulative GAAP compensation expense for that award upon realization of the tax deduction, a tax shortfall will be recognized and recorded as an unfavorable impact on the effective tax rate. Any excess tax benefits or shortfalls will be recorded as discrete, adjustments in the period in which they occur. The

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

cash flows resulting from any excess tax benefit will be classified as financing cash flows in the Condensed Consolidated Statements of Cash Flows.

The Company provides its employees with the option to settle income tax obligations arising from the vesting of their restricted or deferred stock-based compensation awards by withholding shares equal to such income tax obligations. Shares acquired from employees in connection with the settlement of the employees’ income tax obligations are accounted for as treasury shares that are subsequently retired. Restricted stock awards, RSUs, and PSUs are not considered issued and outstanding for purposes of earnings per share calculations until vested.

For additional information, see Note (10) Stock-Based Compensation.

(3) Alamo Acquisition

On August 31, 2021 (the “Alamo Acquisition Date”), the Company completed the Alamo Acquisition in accordance with the terms of the Purchase Agreement, dated as of August 4, 2021 (the “Purchase Agreement”), by and among the Company, NexTier Completion Solutions Inc., Alamo Frac Holdings, LLC, Alamo and the “owner group” identified therein. The Company acquired 100% of Alamo.

The Alamo Acquisition was completed for cash consideration of $100.0 million, equity consideration of 26 million shares of the Company's common stock valued at $82.3 million, post-closing services valued at $30 million, an estimated $15.9 million of contingent consideration, $7.4 million of non contingent consideration, and a net working capital settlement to be finalized in the fourth quarter of 2021. The contingent consideration includes the Tier II Upgrade Payment and the Earnout Payments, which are contingent upon the achievement of certain performance targets, as described in the Purchase Agreement.

The Company accounted for the Alamo Acquisition using the acquisition method of accounting. The aggregate purchase price noted above was allocated to the assets acquired and liabilities assumed based upon their estimated fair values at the date of the acquisition. The measurements of some assets acquired and liabilities assumed, such as intangible assets and the earnout were based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired property and equipment were based on both available market data and a cost approach.

The following table summarizes the fair value of the consideration transferred in the Alamo Acquisition and the allocation of the purchase price to the fair values of the assets acquired and liabilities assumed at the Alamo Acquisition Date:

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements


Total Purchase Consideration	(Thousands of Dollars)
Cash consideration(1)	$	100,000
Equity consideration	82,323
Post close services	30,000
Contingent consideration	15,944
Non contingent consideration	7,370
Total purchase consideration	235,637

Cash	7,419
Trade and accounts receivable	50,619
Inventories	1,726
Prepaid and other current assets	19,654
Assets held for sale	3,282
Property and equipment	114,705
Intangible assets	27,113
Finance lease right-of-use assets	35,813
Other noncurrent assets	1,676
Total identifiable assets acquired	262,007
Accounts payable	39,101
Accrued expenses	38,000
Current maturities of long-term finance lease liabilities	10,125
Long-term finance lease liabilities	25,688
Non-current liabilities	971
Total liabilities assumed	113,885
Goodwill	87,515
Total purchase consideration	$	235,637

(1) Includes $32.3 million of payments for indebtedness on behalf of Alamo.

Goodwill is calculated as the excess of the consideration transferred over the fair value of the net assets acquired. All the goodwill recognized for the Alamo acquisition is recognized in the Completions segment and is tax deductible with an amortization period of 15 years. The goodwill in this acquisition was primarily attributable to Alamo's organized workforce and potential synergies.

Intangible assets related to the Alamo acquisition consisted of the following:


	(Thousands of Dollars)
	Weighted average remaining amortization period (Years)	Gross Carrying Amounts
Trademarks	1.5	$	2,409
Non-compete agreements	3	1,310
Customer relationships	7.33	23,394
Total		$	27,113

For the valuation of the customer relationship intangible asset within the Completions Services segment, management used the income based multi-period excess earning method, which utilized contributory asset charges. Under this method, the Company calculated earnings derived from the existing customer relationships and then deducted portions of the earnings that could be attributed to supporting assets that contribute to the generation of said earnings. Estimated cash flows were discounted at the cost of equity based on the assumption that the intangible asset would be financed with 100% equity. For the valuation of the trademarks intangible asset

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

within the Completions Services segment, management used the relief from royalty method to reflect the after tax royalty savings attributable to owning the intangible asset. Management used the return on asset method to determine an implied royalty rate since a royalty rate was not available in the Company's industry. For the valuation of the non-compete agreements intangible asset within the Completions Services segment, management used the incremental cash flow (''with/without") method.

The Company has recognized $19.0 million in indemnification assets related to an ongoing sales & use tax audit and other indemnified liabilities under the Purchase Agreement.

The following transactions were recognized separately from the acquisition of assets and assumptions of liabilities in the Alamo Acquisition. Merger costs consist of legal and professional fees. Integration costs consist of expenses incurred to integrate Alamo's operations with that of the Company, including retention bonuses and severance payments. The expenses for all these transactions were expensed as incurred and are presented in Merger and integration in the condensed consolidated statements of operations and comprehensive loss.


	(Thousands of Dollars)
Transaction Type	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Merger	$	4,552	$	4,662
Integration	200		268
Total merger and integration costs	$	4,752	$	4,930

The following combined pro forma information assumes the Alamo Acquisition occurred on January 1, 2020. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after September 30, 2021 or any operating efficiencies or inefficiencies that resulted from the Alamo Acquisition. The information is not necessarily indicative of results that would have been achieved had the Company controlled Alamo during the period presented. Pro forma adjustments related to the elimination of historical interest expense for debt paid off as part of the Alamo Acquisition were $2.7 million and $5.4 million for the nine months ended September 30, 2021 and 2020, respectively.


	(Thousands of Dollars)
	Unaudited
	Nine Months Ended September 30,
	2021		2020
Revenue	$	1,124,136	$	1,170,276
Net income (loss)	(116,291)		(266,435)

Net income (loss) per share (basic)	(0.48)		(1.11)
Net income (loss) per share (diluted)	(0.48)		(1.11)

The Company’s condensed consolidated statement of operations and comprehensive loss for the three months ended and nine months ended September 30, 2021 includes revenue of $34.8 million and net income of $3.0 million from the Alamo operations, from September 1, 2021 to September 30, 2021.

As of September 30, 2021, there have been no changes to the fair value of the contingent consideration compared to the Acquisition Date.

(4) Goodwill

Goodwill is allocated across three reporting units: Completion Services, Well Construction and Intervention Services and Well Support Services reporting units. At the reporting unit level, the Company tests goodwill for impairment on an annual basis as of October 31 of each year, or when events or changes in circumstances, referred to as triggering events, indicate the carrying value of goodwill may not be recoverable and that a potential impairment exists.

Judgment is used in assessing whether goodwill should be tested for impairment more frequently than annually. Factors such as unexpected adverse economic conditions, competition, market changes, and other external events may require more frequent assessments.

During the first quarter of 2020, a significant decline in the Company's share price, which resulted in the Company's market capitalization dropping below the book value of equity, as well as reductions in commodity prices driven by the potential impact of the

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

COVID-19 pandemic and global supply and demand dynamics were deemed triggering events that led to a test for goodwill impairment. The impairment testing methodologies for the first quarter 2020 are discussed below.

Income approach

The income approach impairment testing methodology is based on a discounted cash flow model, which utilizes present values of cash flows to estimate fair value. For the Completions and Well Construction and Intervention reporting units, the future cash flows were projected based on estimates of projected revenue growth, unit count, utilization, pricing, gross profit rates, SG&A rates, working capital fluctuations and capital expenditures. Forecasted cash flows took into account known market conditions as of March 31, 2020, and management’s anticipated business outlook. A terminal period was used to reflect an estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 2.5%. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital (“WACC”) of 19.9% for the Completions reporting unit and 22.4% for the Well Construction and Intervention reporting unit. These assumptions were derived from both observable and unobservable inputs and combined reflect management’s judgments and assumptions.

Market approach

The market approach impairment testing methodology is based upon the guideline public company method and the guideline transaction method. The application of the guideline public company method was based upon selected public companies operating within the same industry as the Company. Based on this set of comparable competitor data, operational multiples were derived for the reporting units weighted based on management’s assessment of reliability. The selected market multiples for the guideline public company method were forward-looking enterprise value to revenue and enterprise value to EBITDA multiples, with multiples ranging from 0.5x to 0.6x for revenues and from 3.3x to 6.2x for EBITDA. The application of the guideline transaction method was based upon valuation multiples derived from actual control transactions for comparable companies. Based on this, valuation multiples are derived from historical data of selected transactions, then evaluated and adjusted, if necessary, based on the strengths and weaknesses of the subject reporting unit relative to each acquired guideline company. The selected market multiples for the guideline transaction method were enterprise value to revenue and enterprise value to book value of invested capital, with multiples ranging from 0.7x to 2.1x for revenues and from 0.6x to 1.3x for book value of invested capital.

The fair value determined under the market approach is sensitive to these market multiples, and a decline in any of the multiples could reduce the estimated fair value of the reporting unit below its carrying value. Earnings estimates were derived from unobservable inputs that require significant estimates, judgments and assumptions as described in the income approach.

Reconciliation of value and goodwill impairment conclusion

The estimated fair value determined under the income approach was consistent with the estimated fair value determined under the market approach. The concluded fair value for both reporting units consisted of a weighted average, with a 40.0% weighted under the income approach and 60.0% weight under the market approach. Market data in support of the implied control premium were used in this reconciliation to corroborate the estimated reporting unit fair values with the Company's overall market-indicated value. The results of the Step 1 impairment testing for goodwill resulted in the Company recognizing an impairment expense of $32.6 million during the first quarter of 2020, consisting of $32.2 million related to the Completions Services reporting unit and $0.4 million representing the entire balance of goodwill for the Well Construction and Intervention reporting unit.

The Company assessed and determined there were not any triggering events in the first three quarters of 2021.

During the second quarter of 2021, the Company completed an acquisition for total cash consideration of $2.5 million. The transaction resulted in additional goodwill of $0.7 million recorded under the Completion Services reporting unit.

During the third quarter of 2021, the Company acquired Alamo for total transaction valuation of $235.6 million. The transaction resulted in additional goodwill of $87.5 million recorded under the Completion Services reporting unit.


	(Thousands of Dollars)
Goodwill as of December 31, 2020	$	104,198
Completions Acquisition	733
Alamo Acquisition	87,515
Goodwill as of September 30, 2021	$	192,446

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(5) Inventories, net

Inventories, net, consisted of the following as of September 30, 2021 and December 31, 2020:


	(Thousands of Dollars)
	September 30, 2021		December 31, 2020
Sand, including freight	$	10,911	$	5,096
Chemicals and consumables	4,437		2,993
Materials and supplies	22,760		21,979

Total inventory, net	$	38,108	$	30,068

Inventories are reported net of obsolescence reserves of $5.4 million and $4.4 million as of September 30, 2021 and December 31, 2020, respectively. The Company recognized $0.6 million and $0.1 million of obsolescence expense during the three months ended September 30, 2021 and 2020, respectively. The Company recognized $1.0 million and $3.8 million of obsolescence expense during the nine months ended September 30, 2021 and 2020. Additionally, during the three and nine months ended September 30, 2020, the Company recognized a $2.7 million write-down in inventory carrying value down to its net realizable value.

(6) Long-Term Debt

Long-term debt at September 30, 2021 and December 31, 2020 consisted of the following:


	(Thousands of Dollars)
	September 30, 2021		December 31, 2020
2018 Term Loan Facility	$	338,625	$	341,250
2021 Equipment Loan	39,428		—
Less: Unamortized debt discount and debt issuance costs	(5,031)		(5,710)
Total debt, net of unamortized debt discount and debt issuance costs	373,022		335,540
Less: Current portion	(11,186)		(2,252)
Long-term debt, net of unamortized debt discount and debt issuance costs	$	361,836	$	333,288

Below is a summary of the Company’s credit facilities outstanding as of September 30, 2021:


				(Thousands of Dollars)
	2021 Equipment Loan			2019 ABL Facility		2018 Term Loan Facility
Original facility size	$	46,500		$	450,000	$	350,000
Outstanding balance	$	39,428		$	—	$	338,625
Letters of credit issued	$	—		$	23,200	$	—
Available borrowing base commitment	n/a			$	154,131	n/a
Interest Rate(1)	5.25		%	LIBOR or base rate plus applicable margin		LIBOR or base rate plus applicable margin
Maturity Date	June 1, 2025			October 31, 2024		May 25, 2025

(1) London Interbank Offer Rate (“LIBOR”) is subject to a 1.00% floor

Maturities of the 2018 Term Loan Facility and the 2021 Equipment Loan for the next five years are presented below:

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements


(Thousands of Dollars)
Year-end December 31,
2021	$	2,351
2022	13,634
2023	14,187
2024	14,768
2025	333,113
	$	378,053

ABL Revolving Credit Facility

On October 31, 2019, the Company entered into the Second Amended and Restated Asset-Based Revolving Credit Agreement (“2019 ABL Facility”), modifying the Company’s pre-existing asset-based revolving credit facility (“2017 ABL Facility”). Deferred charges associated with the 2019 ABL Facility were capitalized and totaled $1.2 million. In connection with the modification of the 2017 ABL Facility, the Company wrote off $0.5 million of deferred financing costs. The remaining deferred financing costs related to the 2017 ABL Facility will be amortized over the life of the 2019 ABL Facility. Unamortized deferred charges associated with the 2019 and 2017 ABL Facilities were $2.5 million and $3.1 million as of September 30, 2021 and December 31, 2020, respectively, and are recorded in other noncurrent assets on the consolidated balance sheets. During the first quarter of 2020, the Company provided notice to the lenders to borrow a total of $175 million under the 2019 ABL Facility. The interest rates for the $150.0 million LIBOR borrowing and $25.0 million Base Rate borrowing were 2.125% and 3.75%, respectively. During the second quarter of 2020, the Company repaid the $150.0 million LIBOR borrowing and the $25.0 million Base Rate borrowing and did not incur any penalties.

Equipment Loan

On August 20, 2021, the Company entered into the Master Loan and Security Agreement (the “Master Agreement”) with Caterpillar Financial Services Corporation. The Master Agreement provides for secured equipment financing term loans in an aggregate amount of up to $46.5 million (the “Equipment Loans”). The Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note. On September 3, 2021 entered into a term note for $39.4 million (the “Note”) for an equipment financing loan. The Note will bear interest at a rate of 5.25% per annum and has a maturity date of June 1, 2025. The Company will amortize $0.2 million in debt issuance costs and debt discount over the life of the loan.

(7) Significant Risks and Uncertainties

Subsequent to the sale of the Well Support Services segment, the Company operates in two reportable segments: Completion Services and Well Construction and Intervention with significant concentration in the Completion Services segment. During the three months ended September 30, 2021 and 2020, sales to Completion Services customers represented 93% and 94% of the Company's consolidated revenue, respectively. During the nine months ended September 30, 2021 and 2020, sales to Completion Services customers represented 92% and 86% of the Company's consolidated revenue.

The Company depends on its customers' willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas onshore in the U.S. This activity is driven by many factors, including current and expected crude oil and natural gas prices. The U.S. energy industry experienced a significant downturn in the second half of 2014 through early 2016, driven primarily by global oversupply and a decline in commodity prices. From early 2016 through late 2018, the U.S. generally experienced some recovery in commodity prices and drilling and completion activity. Over this time frame, the U.S. active rig count increased from a trough of 404 rigs in May 2016 to a peak of 1,083 rigs in December 2018, driving significant demand for the Company's completion services.

In late 2019 and early 2020, and in response to the oversupply of hydraulic fracturing equipment, an increasing number of horsepower retirements were announced, removing a significant base of equipment from the market. Despite some of these announcements, the oversupply of hydraulic fracturing equipment persisted, resulting in a continuation of highly competitive market conditions into 2020.

In late first quarter of 2020, the industry faced sudden and unprecedented circumstances, including major shocks to both supply and demand. COVID-19 has resulted in significant demand destruction for oil products, driven by a significant slowdown in economic activity throughout the U.S. and abroad.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

This resulted in a rapid and significant decline in crude oil prices and an increasingly utilized storage network, limiting distribution outlets and optionality for production and further exacerbating price declines. U.S. exploration and production companies responded with drastic reductions in budgets and outright completion stoppages. As a result, from the first quarter of 2020 to the third quarter of 2020, the average U.S. active rig count decreased by approximately 68% to 254 rigs.

Commodity prices have recovered from the 2020 downturn, and oil and natural gas prices are both trading above pre-COVID-19 levels. The rig count averaged 496 in the third quarter of 2021, 95% higher than the third quarter of 2020. The rig count was 521 at the end of the third quarter of 2021.

Significant customers are those that individually account for 10% or more of the Company's consolidated revenue or total accounts receivable. For the three months ended September 30, 2021, revenue from one customer individually represented more than 10% of the Company's consolidated revenue. This customer represented 15% or $60.8 million of our consolidated revenue in the Completions Services segment. For the three months ended September 30, 2020, revenue from four customers individually represented more than 10% of the Company's consolidated revenue. These customers represented 19% or $30.6 million, 14% or $22.7 million, 13% or $22.2 million and 13% or $21.9 million, respectively, of our consolidated revenue in the Completions Services segment.

For the nine months ended September 30, 2021, revenue from one customer individually represented more than 10% of the Company's consolidated revenue. This customer represented 12% or $113.6 million of our consolidated revenue in the Completions Services segment. For the nine months ended September 30, 2020, revenue from two customers individually represented more than 10% of the Company's consolidated revenue. These customers represented 16% or $161.9 million and 15% and $142.7 million, respectively, of our consolidated revenue in the Completions Services segment.

For the three months ended September 30, 2021, purchases from the Company's top supplier represented approximately 5% of the Company's overall purchases, while for the nine months ended September 30, 2021, the Company's top supplier represented approximately 6% of the Company's overall purchases. For the three months ended September 30, 2020, purchases from the Company's top supplier represented approximately 7% of the Company's overall purchases. For the nine months ended September 30, 2020, purchases from the Company's top supplier represented approximately 5% of the Company's overall purchases.

(8) Derivatives

The Company uses interest-rate-related derivative instruments to manage its variability of cash flows associated with changes in interest rates on its variable-rate debt.

On March 9, 2020, the Company sold its Well Support Services segment to Basic Energy Services, Inc. (“Basic”) for $93.7 million of total proceeds, including $59.4 million in cash, before transaction costs, escrowed amounts, and subject to customary working capital adjustments, for a net of $53.3 million received at close, and $34.4 million of par value Senior Secured Notes, with 10.75% coupon rate, (“WSS Notes”) previously issued by Basic. On July 29, 2020, the Company agreed to use the escrowed amount in the final settlement of the working capital reconciliation. Under the terms of the agreement, the WSS Notes were accompanied by a make-whole guarantee at par value, which guaranteed the payment of $34.4 million to NexTier after the WSS Notes were held to the one-year anniversary of March 9, 2021. The cash equivalent make-whole was issued under a fund guarantee by Ascribe III Investments LLC ("Ascribe"), a private equity investment firm with approximately $1.0 billion in assets under management. In the event of a Basic restructuring or a credit rating downgrade in conjunction with a change in control prior to the one-year anniversary, the make-whole guarantee accelerates the WSS Notes to par value of $34.4 million. NexTier was entitled to semi-annual interest payments on the WSS Notes based on the 10.75% annual coupon throughout the holding period. The Company identified the make-whole guarantee as an embedded derivative and bifurcated the valuation of the WSS Note and the make-whole guarantee. The Company elected the fair value option for the WSS Notes at the inception of the transaction. The fair value on the date of the transaction for the make-whole derivative and WSS Notes was $12.2 million and $22.2 million, respectively, and resulted in a gain on divestiture of $8.7 million. The fair value of the WSS Notes and the make-whole guarantee are measured at the end of each reporting period. Gains and losses recognized in relation to these instruments are recognized in net income. The fair value of the WSS Notes and make-whole guarantee were recorded in Other Current Assets. See Note (14) Business Segments for further discussion.

On March 31, 2021, the Company received a $34.4 million cash payment from Ascribe in full settlement of the WSS Notes and the make-whole guarantee. At the time of the cash payment, the WSS Notes and make-whole guarantee had a fair value of $33.6 million, resulting in a realized gain on settlement of $0.8 million. This gain is recorded within other income (expense) on the Consolidated Statements of Operations and Comprehensive Loss.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

On May 25, 2018, the Company, and certain subsidiaries of the Company as guarantors, entered into a term loan facility (the "2018 Term Loan Facility") with each lender from time to time party thereto and Barclays Bank PLC, as administrative agent and collateral agent. The 2018 Term Loan Facility has an initial aggregate principal amount of $350.0 million and proceeds were used to repay the Company's pre-existing 2017 term loan facility. The 2018 Term Loan Facility has a variable interest rate based on the London Interbank Offer Rate ("LIBOR"), subject to a 1.0% floor. In June 2018, the Company executed a new off-market interest rate swap effective through March 31, 2025 to hedge 50% of its expected LIBOR exposure matching the swap to the 1-month LIBOR, 1% floor, of the 2018 Term Loan Facility, and terminated the pre-existing interest rate swaps. After completing all appropriate accounting treatment, including the $3.5 million of deferred gains in accumulated other comprehensive loss for the pre-existing interest rate, the new interest rate swap was designated in a new cash flow hedge relationship.

The following tables present the fair value of the Company's derivative instruments on a gross and net basis as of the periods shown below:


	(Thousands of Dollars)
	Derivatives designated as hedging instruments		Derivatives not designated as hedging instruments		Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet(1)		Net Amounts Presented in the Balance Sheet(2)
As of September 30, 2021:

Other current liability	$	(2,865)	$	—	$	(2,865)	$	—	$	(2,865)
Other noncurrent liability	(5,314)		—		(5,314)		—		(5,314)
As of December 31, 2020:


Other current asset	$	—	$	27,243	$	27,243	$	—	$	27,243
Other current liability	(2,861)		—		(2,861)		—		(2,861)
Other noncurrent liability	(8,260)		—		(8,260)		—		(8,260)

(1) Agreements are in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

(2) There are no amounts subject to an enforceable master netting arrangement that are not netted in these amounts. There are no amounts of related financial collateral received or pledged.

The following table presents gains and losses for the Company's interest rate derivatives designated as cash flow hedges (in thousands of dollars):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		Location
Amount of gain (loss) recognized in total other comprehensive loss on derivative	$	(46)	$	(453)	$	785	$	(6,068)	OCI
Amount of loss reclassified from accumulated other comprehensive loss into earnings	(694)		(673)		(2,043)		(1,662)		Interest Expense

The gain (loss) recognized in other comprehensive loss for the derivative instrument is presented within hedging activities in the Condensed Consolidated Statements of Operations and Comprehensive Loss.

There were no gains or losses recognized in earnings as a result of excluding amounts from the assessment of hedge effectiveness. Based on recorded values as of September 30, 2021, $2.9 million of net losses will be reclassified from accumulated other comprehensive loss into earnings within the next 12 months.

See Note (9) Fair Value Measurements and Financial Information for discussion on fair value measurements related to the Company's derivative instruments.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(9) Fair Value Measurements and Financial Information

The Company discloses the required fair values of financial instruments in its assets and liabilities under the hierarchy guidelines, in accordance with GAAP. As of September 30, 2021, the Company's financial instruments consisted of cash and cash equivalents, accounts receivable, equity security investments, accounts payable, accrued expenses, derivative instruments, long-term debt and lease obligations. As of September 30, 2021 and December 31, 2020, the carrying values of the Company's financial instruments, included in its condensed consolidated balance sheets, approximated or equaled their fair values.

Recurring Fair Value Measurement

As of September 30, 2021 the Company has four financial instruments measured at fair value on a recurring basis which are its interest rate derivative, see Note (8) Derivatives above, its equity security investment, the Earnout Payments and Tier II Upgrade Payments related to the Alamo acquisition and as described in the Purchase Agreement. The equity security investment is composed primarily of common equity shares in a publicly traded company, acquired at a fair value of $5.3 million. During the three and nine months ended September 30, 2021, the Company recognized an unrealized loss of $0.5 million and an unrealized loss of $3.2 million, respectively, on its equity security investment, which is recorded within other income (expense) on the Condensed Consolidated Statements of Operations and Comprehensive Loss.

As of December 31, 2020, the Company had four financial instrument measured on a recurring basis which was its interest rate derivative, make-whole derivative, WSS Notes, see Note (8) Derivatives above, and equity security investment. The interest rate derivative, make-whole derivative, WSS Notes, and the equity security investment are presented within other current assets in the condensed consolidated balance sheets.

The fair market value of the financial instruments reflected on the condensed consolidated balance sheets as of September 30, 2021 and December 31, 2020 were determined using industry-standard models that consider various assumptions, including current market and contractual rates for the underlying instrument, time value, implied volatilities, nonperformance risk as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

The following tables present the placement in the fair value hierarchy of assets and liabilities that were measured at fair value on a recurring basis at September 30, 2021 and December 31, 2020 (in thousands of dollars):


			Fair value measurements at reporting date using
	September 30, 2021		Level 1		Level 2		Level 3
Assets:
Equity security investment	$	4,702	$	4,702	$	—	$	—
Liabilities:

Earnout Payments	$	(9,424)	$	—	$	—	$	(9,424)
Tier II Upgrade Payment	$	(6,520)	$	—	$	(6,520)	$	—
Interest rate derivative	$	(8,179)	$	—	$	(8,179)	$	—


			Fair value measurements at reporting date using
	December 31, 2020		Level 1		Level 2		Level 3
Assets:
Make-whole derivative	$	27,243	$	—	$	27,243	$	—
WSS Note	6,322		—		6,322		—
Equity security investment	11,263		11,263		—		—
Liabilities:
Interest rate derivative	$	(11,121)	$	—	$	(11,121)	$	—

Non-Recurring Fair Value Measurement

At March 31, 2020 and September 30, 2020, the Company determined the reductions in commodity prices driven by the impact of the novel COVID-19 virus and global supply and demand dynamics represented triggering events that may indicate that the

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

carrying value of the Company's indefinite-lived assets and long-lived assets may not be recoverable. After further evaluation, the Company recognized impairment expense of $32.6 million and no impairment expense in the first and third quarter of 2020, respectively. See Note (4) Goodwill. The Company assessed and determined there were no triggering events during the other two quarters in 2020.

During each quarter of 2021, the Company has assessed and determined there were no triggering events.

Credit Risk

The Company's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents, derivative contracts and trade receivables.

The Company's cash balances on deposit with financial institutions totaled $135.5 million and $276.0 million as of September 30, 2021 and December 31, 2020, respectively, which exceeded Federal Deposit Insurance Corporation insured limits. The Company regularly monitors these institutions' financial condition.

The credit risk from the derivative contracts derives from the potential failure of the counterparty to perform under the terms of the derivative contracts. The Company minimizes counterparty credit risk in derivative instruments by entering into transactions with high-quality counterparties, whose Standard & Poor's credit rating is higher than BBB. The derivative instruments entered into by the Company do not contain credit-risk-related contingent features.

The majority of the Company's trade receivables have payment terms of 30 to 60 days. Significant customers are those that individually account for 10% or more of the Company's consolidated revenue or total accounts receivable. As of September 30, 2021, trade receivables from one customer individually represented 13% of the Company's total trade receivables. As of December 31, 2020, trade receivables from the Company's top customer individually represented 17% of the Company's total trade receivables.

The Company mitigates the associated credit risk by performing credit evaluations and monitoring the payment patterns of its customers. The Company has a process in place to collect all receivables within 30 to 60 days of aging. As of September 30, 2021, the Company had $4.9 million in allowance for credit losses. As of December 31, 2020, the Company had $2.7 million in allowance for credit losses, including the increase of $1.5 million from the adoption of ASU 2016-13.

The Company recognized $0.9 million and $2.1 million of bad debts, net of recoveries during the three and nine months ended September 30, 2021, respectively. During the third quarter of 2020, the Company recovered $5.3 million of accounts receivable, which resulted in a net credit in bad debt expense of $4.6 million during the three months ended September 30, 2020 and $0.3 million of bad debt expense during the nine months ended September 30, 2020.

(10) Stock-Based Compensation

Effective as of October 31, 2019, the Company (i) amended and restated the Keane Group, Inc. Equity and Incentive Award Plan under the name NexTier Oilfield Solutions Inc. Equity and Incentive Award Plan (“Equity and Incentive Award Plan”), and (ii) assumed and amended and restated the C&J Energy Services, Inc. 2017 Management Incentive Plan under the name NexTier Oilfield Solutions Inc. (Former C&J Energy) Management Incentive Plan ( “Management Incentive Plan”, and collectively with the Equity and Incentive Award Plan, the “Equity Award Plans”). As part of the C&J Merger, the Company assumed the award agreements outstanding under the Management Incentive Plan on the terms set forth in the Merger agreement.

As of September 30, 2021, the Company has four types of stock-based compensation outstanding under its Equity Award Plans: (i) restricted stock awards issued to independent directors and certain executives and employees, (ii) restricted stock units issued to executive officers and key management employees, (iii) non-qualified stock options issued to executive officers and (iv) performance-based stock units issued to executive officers and key management employees.

The following table summarizes stock-based compensation costs for the three and nine months ended September 30, 2021 and 2020 (in thousands of dollars):

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements


	Three Months Ended September 30,			Nine Months Ended September 30,
		2021		2020		2021		2020
Restricted stock awards		$	300	$	406	$	1,065	$	1,192
Restricted stock time-based unit awards		4,100		3,271		10,318		15,985
Non-qualified stock options		—		100		76		804
Restricted stock performance-based unit awards		2,950		971		5,983		3,170
Equity-based compensation cost		7,350		4,748		17,442		21,151
Tax Benefit		(1,151)		(1,138)		(3,573)		(5,076)
Equity-based compensation cost, net of tax		$	6,199	$	3,610	$	13,869	$	16,075

Performance-based RSU awards

During the first and second quarter of 2021, the Company issued 550,899 and 1,473,736 of performance based RSUs to executive officers under its Equity Award Plans, which were fair valued at $3.2 million and $13.7 million using a Monte Carlo simulation method. Each vesting is subject to a payout percentage based on the Company's annualized total stockholder return ranking relative to its total stockholder return peer group achieved during the performance period. The number of shares that may be earned at the end of the vesting period ranges from 0% to 200% of the target award amount, if the performance criteria is met. These performance-based RSUs will be settled in the Company's common stock and are classified as equity awards. The compensation expense associated with these performance-based RSUs will be amortized into earnings on a straight-line basis. As of September 30, 2021, total unamortized compensation cost related to unvested performance-based RSUs was $14.6 million, which the Company expects to recognize over the weighted-average period of 2.25 years.

(11) Earnings per Share

Basic income or (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted income or (loss) per share includes additional common shares that would have been outstanding if potential common shares with a dilutive effect, such as stock awards from the Equity Awards Plans, had been issued. Anti-dilutive securities represent potentially dilutive securities which are excluded from the computation of diluted income or (loss) per share as their impact would be anti-dilutive.

A reconciliation of the numerators and denominators used for the basic and diluted net income (loss) per share computations is as follows (in thousands of dollars):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Numerator:
Net loss	$	(43,994)	$	(102,433)	$	(130,277)	$	(286,677)

Denominator:
Basic weighted-average common shares outstanding(1)	224,481		214,251		218,499		213,620
Dilutive effect of restricted stock awards granted to Board of Directors	—		195		214		139
Dilutive effect of time-based restricted stock awards granted under the Equity Plan	1,166		14		957		16
Dilutive effect of performance-based restricted stock awards granted under the Equity Plan	511		1,221		321		981

Diluted weighted-average common shares outstanding(1)	226,158		215,681		219,991		214,756

(1) As a result of the net loss incurred by the Company for the three and nine months ended September 30, 2021 and 2020, the calculation of diluted net loss per share gives no consideration to the potentially anti-dilutive securities shown in the above reconciliation, and as such is the same as basic net loss per share.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(12) Commitments and Contingencies

As of September 30, 2021 and December 31, 2020, the Company had $0.5 million and $4.9 million of deposits on equipment, including deposits acquired through the C&J Merger, respectively. Outstanding purchase commitments on equipment were $60.3 million and $23.4 million, as of September 30, 2021 and December 31, 2020, respectively.

Aggregate minimum commitments under long-term raw material supply contracts for the next five years as of September 30, 2021 are listed below:


	(Thousands of Dollars)
2021	$	4,204
2022	19,145
2023	5,280
2024	1,190
2025	—
	$	29,819

Litigation

From time to time, the Company is subject to legal and administrative proceedings, settlements, investigations, claims and actions, as is typical of the industry. These claims include, but are not limited to, contract claims, environmental claims, employment related claims, claims alleging injury or claims related to operational issues. The Company's assessment of the likely outcome of litigation matters is based on its judgment of a number of factors, including experience with similar matters, past history, precedents, relevant financial information and other evidence and facts specific to the matter. In accordance with GAAP, the Company accrues for contingencies where the occurrence of a material loss is probable and can be reasonably estimated, based on the Company's best estimate of the expected liability. The Company may increase or decrease its legal accruals in the future, on a matter-by-matter basis, to account for developments in such matters. Notwithstanding the uncertainty as to the final outcome and based upon the information currently available to it, the Company does not currently believe these matters in aggregate will have a material adverse effect on its financial position or results of operations.

Environmental

The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. The Company cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Company continues to monitor the status of these laws and regulations. Currently, the Company has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of the Company's business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or through indemnification.

Regulatory Audits

Prior to the consummation of the C&J Merger, the Company and C&J had been notified by certain state taxing authorities that these taxing authorities would be conducting routine sales and use tax audits of certain wholly owned operating subsidiaries of the Company for tax periods ranging from January 2011 through December 2019. As of December 31, 2020, the Company had recorded estimates of potential assessments for each audit totaling in the aggregate approximately $33.0 million. For one audit, in particular, the Company disagreed with many aspects of the state’s assessment and began to contest the state’s position through administrative procedures. During the first quarter of 2021, the Company obtained additional information that resulted in a reduction of the Company's accrual related to this tax audit by $13.3 million. During the second quarter of 2021, the Company further reduced the accrual related to this tax audit by $8.8 million, after taking into account additional information obtained, including refund claims relating to such periods. The Company received a final settlement offer from Texas Attorney General Office on September 8, 2021 for $3.7 million, which resulted in an additional reduction to the accrual by $2.8 million. These reductions were recorded in selling, general and administrative expenses in the Condensed Consolidated Statements of Operations and Comprehensive Loss.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

Alamo is subject to regulatory audits by state taxing jurisdictions it operates in. There was an ongoing tax audit when the Alamo Acquisition was completed. The Company evaluated the potential assessment and exposures for all taxing jurisdictions and recorded an estimate of $17.7 million. The estimate is included in the purchase price allocation disclosed under Note (3) Alamo Acquisition.

(13) Related Party Transactions

Cerberus Operations and Advisory Company, Cerberus Capital Management, L.P., and Cerberus Technology Solutions LLC, affiliates of the Company's principal equity holder, provide certain consulting services to the Company. The Company paid $0.1 million and $0.3 million during the three months ended September 30, 2021 and 2020, respectively, for these services. The Company paid $0.3 million and $2.1 million during the nine months ended September 30, 2021 and 2020, respectively.

As part of the Purchase Agreement, the Company agreed to provide certain post-closing services to Alamo Frac Holdings, LLC valued at $30.0 million in the aggregate. During the three and nine months ended September 30, 2021, the Company provided services to Alamo Frac Holdings, LLC of $3.2 million as part of the Purchase Agreement. The Company has a remaining customer contract liability related to these services of $26.8 million as of September 30, 2021.

(14) Business Segments

In accordance with Accounting Standard Codification (“ASC”) No. 280, Segment Reporting (“ASC 280”), the Company routinely evaluates whether its separate segments have changed. This determination is made based on the following factors: (1) the Company’s chief operating decision maker (“CODM”) is currently managing each operating segment as a separate business and evaluating the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each operating segment is available.

In 2019, due to the transformative nature of the C&J Merger, the CODM changed the way in which the Company is managed, including the level at which to make performance evaluation and resource allocation decisions. Discrete financial information was created to provide the segment information necessary for the CODM to manage the Company under the revised operating segment structure. On March 9, 2020, the Company announced it had completed the divestiture of its Well Support Services segment. As a result of the changes to operating segments, the Company revised its reportable segments subsequent to the completion of the C&J Merger and Well Support Services segment divestiture. For the period from after the C&J merger and prior to the WSS divestiture, the Company’s revised reportable segments were: (i) Completion Services, (ii) Well Construction and Intervention (“WC&I”) and (iii) Well Support Services. Subsequent to the WSS divestiture, the Company's reportable segments were (i) Completion Services, and (ii) Well Construction and Intervention (“WC&I”) Services. This segment structure reflects the financial information and reports used by the Company’s management, specifically including its CODM, to make decisions regarding the Company’s business, including performance evaluation and resource allocation decisions. As a result of the revised reportable segment structure subsequent to the C&J merger, the Company has restated the corresponding items of segment information for all periods presented.

The following is a description of each reportable segment:

Completion Services

The Company’s Completion Services segment consists of the following businesses and service lines: (1) fracturing services; (2) wireline and pumpdown services; and (3) completion support services, which includes the Company's research and technology department.

All of Alamo's financial results are included in the Completions Services segment.

Well Construction and Intervention Services

The Company’s WC&I Services segment consists of the following businesses and service lines: (1) cementing services and (2) coiled tubing services.

Historical Segment: Well Support Services

The Company’s Well Support Services segment consisted of the following businesses and service lines: (1) rig services; (2) fluids management services; and (3) other specialty well site services. On March 9, 2020, the Company completed the divestiture of its Well Support Services segment for $93.7 million of total proceeds, including $59.4 million in cash, before transaction costs, escrowed

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

amounts, and subject to customary working capital adjustments, for a net of $53.3 million received at close, and $34.4 million of par value Senior Secured Notes, with 10.75% coupon rate, ("WSS Notes") previously issued by Basic. This resulted in a gain on divestiture of $8.7 million. The gain is recorded within (Gain) Loss on Disposal of Assets on the Condensed Consolidated Statements of Operations and Comprehensive Loss. Income per share for the three months ended March 31, 2020 attributable to the divested Well Support Services segment was less than $0.01. On July 29, 2020, the Company received the escrowed cash amount in final settlement for working capital reconciliation.

On March 31, 2021 the Company received a $34.4 million cash payment from Ascribe in full settlement of the WSS Notes and the make-whole guarantee. At the time of the cash payment, the WSS Notes and make-whole guarantee had a fair value of $33.6 million, resulting in a realized gain on settlement of $0.8 million recorded in other income (expense) on the Consolidated Statements of Operations and Comprehensive Loss.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

The following tables present financial information with respect to the Company’s segments. Corporate and Other represents costs not directly associated with a segment, such as interest expense, income taxes and corporate overhead. Corporate assets include cash, deferred financing costs, derivatives and entity-level machinery equipment.


	(Thousands of Dollars)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operations by business segment





Adjusted gross profit:
Completion Services(1)	$	46,184	$	15,145	$	81,959	$	144,676
WC&I(1)	2,905		(785)		7,337		8,811
Well Support Services(1)	—		—		—		12,338
Total adjusted gross profit	$	49,089	$	14,360	$	89,296	$	165,825

(1) Adjusted gross profit (loss) at the segment level is not considered to be a non-GAAP financial measure as it is the Company's segment measure of profitability and is required to be disclosed under GAAP pursuant to ASC 280. Adjusted gross profit (loss) is defined as revenue less cost of services, further adjusted to eliminate items in cost of services that management does not consider in assessing ongoing performance.


	(Thousands of Dollars)
	Three Months Ended September 30, 2021								Nine Months Ended September 30, 2021
	Completion Services		WC&I		Well Support Services		Total		Completion Services		WC&I		Well Support Services		Total
Revenue	$	366,067	$	27,097	$	—	$	393,164	$	843,887	$	69,824	$	—	$	913,711
Cost of Services	320,297		24,340		—		344,637		768,562		63,112		—		831,674
Gross profit excluding depreciation and amortization	45,770		2,757		—		48,527		75,325		6,712		—		82,037
Management adjustments associated with cost of services(1)	414		148		—		562		6,634		625		—		7,259
Adjusted gross profit	$	46,184	$	2,905	$	—	$	49,089	$	81,959	$	7,337	$	—	$	89,296

(1) Adjustments relate to market-driven severance, leased facility closures, and restructuring costs incurred as a result of significant declines in crude oil prices resulting from demand destruction from the COVID-19 pandemic and global oversupply.

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements


	(Thousands of Dollars)
	Three Months Ended September 30, 2020								Nine Months Ended September 30, 2020
	Completion Services		WC&I		Well Support Services		Total		Completion Services		WC&I		Well Support Services		Total
Revenue	$	154,016	$	9,659	$	—	$	163,675	$	845,864	$	83,734	$	57,929	$	987,527
Cost of Services	139,477		10,589		—		150,066		716,008		79,464		45,591		841,063
Gross profit excluding depreciation and amortization	14,539		(930)		—		13,609		129,856		4,270		12,338		146,464
Management adjustments associated with cost of services(2)	606		145		—		751		14,820		4,541		—		19,361
Adjusted gross profit	$	15,145	$	(785)	$	—	$	14,360	$	144,676	$	8,811	$	12,338	$	165,825

(2) Adjustments relate to market-driven severance and restructuring costs incurred as a result of significant declines in crude oil prices resulting from demand destruction from the COVID-19 pandemic and global oversupply.


	(Thousands of Dollars)
	September 30, 2021		December 31, 2020
Total assets by segment:
Completion Services	$	1,112,324	$	689,814
WC&I	68,087		62,959
Well Support Services	—		—
Corporate and Other	237,564		405,115
Total assets	$	1,417,975	$	1,157,888
Goodwill by segment:
Completion Services	$	192,446	$	104,198
WC&I	—		—
Well Support Services	—		—
Corporate and Other	—		—
Total goodwill	$	192,446	$	104,198

NEXTIER OILFIELD SOLUTIONS INC. AND SUBSIDIARIES

Notes to the Unaudited Condensed Consolidated Financial Statements

(15) New Accounting Pronouncements

(a) Recently Adopted Accounting Standards

In December 2019, the Financial Accounting Standards Board issued ASU No 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”). ASU 2019-12 removes certain exceptions to the general principles in Topic 740 in Generally Accepted Accounting Principles. ASU 2019-12 is effective for public entities for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted this standard on January 1, 2021, and there was no impact on the financial statements.

(b) Recently Issued Accounting Standards

In October 2021, the FASB issued ASU 2021-08 “Business Combinations (Topic 805) Accounting for Contract Assets and Contact Liabilities from Contracts with Customers”. ASU 2021-08 requires acquiring entities to apply Topic 606 to recognize and measure contract assets and contract liabilities in a business combination. This standard is effective beginning on December 15, 2022. The Company does not expect ASU 2021-08 to have any impact on its consolidated financial statements.

In January 2021, the FASB issued ASU 2021-01 “Reference Rate Reform (Topic 848)”. ASU 2021-01 expands on the US GAAP guidance on contract modifications and hedge accounting related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. This standard is effective beginning on March 12, 2020, and the Company may elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact of this standard on its consolidated financial statements and related disclosures.

In October 2020, the FASB issued ASU 2020-10 “Codification Improvements”. ASU 2020-10 improves the clarity and consistency of various provisions in the Codification. The Company does not expect ASU 2020-10 to have any impact on the its consolidated financial statements.

In August 2020, the FASB issued ASU 2020-06 “Debt—Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity's Own Equity (Subtopic 815-40)” (“ASU 2020-06”). ASU 2020-06 simplifies the guidance on the issuer's accounting for convertible debt instruments and convertible preferred stock. The Company does not expect ASU 2020-06 to have any impact on the Company's consolidated financial statements.

In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848)”, which is intended to provide temporary optional expedients and exceptions to the US GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. This standard is effective beginning on March 12, 2020, and the Company may elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact of this standard on its consolidated financial statements and related disclosures.

In January 2020, the FASB issued ASU 2020-01, “Investments—Equity Securities (Topic 321), Investments—Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815)”, which clarifies the interaction between the accounting for investments in equity securities, investment in equity method and certain derivatives instruments. This standard is expected to reduce diversity in practice and increase comparability of the accounting for these interactions. This standard is effective for fiscal years beginning after December 15, 2021 and the adoption is not expected to have any impact on the Company's consolidated financial statements.

(16) Subsequent Events

During the third quarter of 2021, negotiations on a contract extension with National Energy Services Reunited Corp. ("NESR") regarding an unconventional fracturing fleet ended with both parties mutually agreeing not to extend the contract for equipment and consulting services. The Company has begun an orderly wind-down for this operation in early fourth quarter of 2021, while continuing to support NESR during the transition period. Additionally, during the fourth quarter of 2021, the Company and NESR signed an agreement for the sale and payment of equipment and accompanying parts inventory. The Company will continue to operate in the Middle East with NESR through a consulting service agreement on another fracturing fleet and will continue to pursue additional partnering opportunities in the Middle East North Africa region as mutually beneficial to the Company and NESR.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related condensed footnotes included within Part I, "Item 1. Condensed Consolidated Financial Statements (Unaudited)" in this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2020.

ORGANIZATIONAL OVERVIEW

NexTier Oilfield Solutions Inc. is an industry-leading U.S. land oilfield focused service company, with a diverse set of well completion and production services across a variety of active and demanding basins. We have a history of growth through acquisition, including the October 31, 2019 C&J Merger. After this business combination, we were organized into three reportable segments:

•Completion Services, which consists of the following businesses and services lines: (1) hydraulic fracturing; (2) wireline and pumpdown services; and (3) completion support services, which includes our innovation centers and activities.

•Well Construction and Intervention Services, which consists of the following businesses and service lines: (1) cementing services and (2) coiled tubing services.

•Well Support Services, which consists of the following businesses and service lines: (1) rig services; (2) fluids management; and (3) other special well site services.

M&A Activity

Our Well Support Services segment was divested in a transaction that closed on March 9, 2020. It focused on post-completion activities at the well site, including rig services, such as workover and plug and abandonment, fluids management services, and other specialty well site services. Subsequent to the Well Support Services divestiture, the Company's reportable segments were (i) Completion Services, and (ii) Well Construction and Intervention (“WC&I”) Services.

On August 31, 2021 the Company completed its acquisition (the “Alamo Acquisition”) of Alamo Pressure Pumping, LLC and its wholly owned subsidiaries (“Alamo”). The Alamo Acquisition was completed for cash consideration of $100.0 million, equity consideration of 26 million shares of the Company's common stock valued at $82.3 million, post-closing services valued at $30 million, an estimated $15.9 million of contingent consideration, and $7.4 million of non contingent consideration. The contingent consideration includes the Tier II Upgrade Payment and the Earnout Payments, which are contingent upon the achievement of certain performance targets, as described in the Purchase Agreement. Alamo's base of operations is in Midland, Texas, and it's pressure pumping business operates almost exclusively in the Permian Basin.

This history impacts the comparability of our operational results from year to year. Additional information on these transactions can be found in Note (14) Business Segments and Note (3) Alamo Acquisition.

OPERATIONAL OVERVIEW

Market Trends and Influences

We provide our services in several of the most active basins in the United States, including the Permian, the Marcellus Shale/Utica, the Eagle Ford, Mid-Continental, and the Bakken/Rockies.

Total North America rig count during the third quarter of 2021 averaged 496 rigs, reflecting an increase of approximately 10% as compared to the second quarter 2021 average of 450 rigs, but is still approximately 37% below the first quarter 2020 average of 785 rigs. North America rig count exited the third quarter of 2021 at 521 rigs. The increase as compared to the second quarter 2021 average was driven by an improvement in economic activity, supportive commodity prices, and modest continued improvements in completions supply/demand dynamics. Crude prices entered and exited the third quarter of 2021 at similar levels, but the exit rate at $75.03 was 21% higher than the intraquarter low of $62.14. Natural gas prices were up 61% from $3.65 on June 30, 2021 to $5.87 on September 30, 2021.

Activity within our business segments is significantly influenced by spending on upstream exploration, development and production programs by our customers. Also driving our activity is the status of the global economy, which is a major factor on oil and natural gas demand. Some of the more significant determinants of current and future spending levels of our customers are oil and natural gas prices, global oil supply and demand, the world economy, the availability of credit, government regulation and global stability, which together drive worldwide drilling activity.

In the third quarter of 2021, we continued to see disciplined increases in oil supply from the Organization of Petroleum Exporting Countries plus (OPEC+) and U.S. shale operators. U.S. onshore completion activity growth continued to trend higher in the third quarter, and we deployed two additional frac fleets during the quarter. With this increased revenue came some related startup inefficiencies, which impacted our results, particularly early in the quarter. Commodity prices have continued to improve, but the discipline of U.S. shale operators has tempered the levels of activity that we would have seen historically at these oil and natural gas prices. We expect fourth quarter activity will continue along a similar trend of disciplined improvements in activity, subject to typical seasonality. Continued improvement in customer activity and utilization remains dependent on macro conditions, including commodity prices, changing political climate, response to the COVID-19 pandemic (including any resurgences in the

U.S. and abroad), seasonality and potential lasting changes that a prolonged or resurging pandemic may have on supply and demand worldwide.

In addition, we have continued to see some modest improvement in pricing, especially with our duel fuel equipment. But, overall economic conditions in the market, including contract structure, inflation and abundant competition, continue to burden profitability of the fleet. We had adjusted our cost structure over the past year, but the current pricing is still below the levels at which we would expect to deploy significant additional horsepower.

Furthermore, as operators are looking for opportunities to improve well performance and lower costs through innovative techniques, we are seeing a rise in operator initiatives such as simulfrac techniques (we generally refer to these types of initiatives as increasing “frac intensity”). Simulfrac is a process of fracking two or more wells at the same time instead of a single well, for the purpose of increasing operational efficiencies and contributing to well cost savings. These techniques require multi-well pads and advanced complex completion designs, resulting in, among other things, adaption costs, an increase in the amount of equipment related to a particular job, an increase in commodities (such as proppant, logistics, and chemicals), and enhanced maintenance practices and procedures. The increasing complexity and resources required by evolving frac intensity, such as double simulfrac, results in the need to fine-tune our approach in the related commercial agreements, especially around sharing the value created and the commercial risks of these enhanced operations. We're continuing to work with our customers to utilize experiences on these operations to hone our commercial agreements going forward.

We are constantly assessing our approach to ensure that our team and our equipment meets the evolving demands. Customers are increasingly looking for ways to lower their carbon footprint by lower emissions associated with their drilling and completion activity. We have invested to upgrade a significant portion of our fleet to be able to operate using natural gas as a primary fuel source. These dual fuel fleets can be powered using both diesel and natural gas as a fuel source. In addition to lowering emissions, at current diesel and natural gas prices, using natural gas can lower the cost to operate a dual fuel fleet relative to a conventional diesel fleet.

As indicated previously, macro-economic factors are resulting in inflation of materials and other costs, such as employee compensation, contract services, commodity prices and communications expenses. While inflation increases our operating costs, the impact of commodity inflation on the Company to date has been significantly mitigated by the Company's ability to adjust pricing to pass the impact of inflation through to its customers. Additionally, we, our suppliers and contractors are facing a highly competitive domestic labor market. These labor market dynamics create wage inflation, increase recruiting costs due to elevated employee attrition and, with respect to driver shortages, may negatively impact or increase the cost of our logistics service for our customers. The rate and scope of these various aspects of inflation may continue to impact our costs, which may not be readily recoverable in the prices of our services. At this time, we expect this trend to continue through 2021 and likely into 2022. As such, its full financial impact on our business is impractical to quantify at this time.

Global market supply chain and logistics constraints have also impacted our suppliers. We have begun to see a more pronounced delay in lead times for certain components used in equipment, parts and supplies. Additionally, some shipments from overseas suppliers are experiencing transportation delays due to a lack of available containers and a backlog at incoming ports of entry. These delays in shipments could impact our availability to secure parts and inventory, although the ultimate impact is impractical to quantify at this time.

Utilization Tendencies

Historically, our utilization levels have been highly correlated to U.S. onshore spending by our customers, which is heavily driven by the price of oil and natural gas. Generally, as capital spending by our customers increases, drilling, completion and production activity also increases, resulting in increased demand for our services, and therefore more days or hours worked (as the case may be). Conversely, when drilling, completion and production activity levels decline due to lower spending by our customers, we generally provide fewer services, which results in fewer days or hours worked (as the case may be).

Given the volatile and cyclical nature of activity drivers in the U.S. onshore oilfield services industry, coupled with the varying prices we are able to charge for our services and the cost of providing those services, among other factors, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle. Additionally, during periods of decreased spending by our customers and/or high competition, we may be required to discount our rates or provide other pricing concessions to remain competitive and support deployed equipment utilization, which negatively impacts our revenue and operating margins. During periods of pricing weakness for our services, we may not be able to reduce our costs accordingly, and our ability to achieve any cost reductions from our suppliers typically lags behind the decline in pricing for our services, which could further adversely affect our results. Furthermore, when demand for our services increases following a period of low demand, our ability to capitalize on such increased demand may be delayed while we reengage and redeploy equipment and crews that have been idled during a downturn. The mix of customers that we are working for, as well as limited periods of exposure to the spot market, also impacts our deployed equipment utilization. Some smaller operators may not have sufficient programs to support continuous operations or dedicated fleets. To the extent we have a significant percentage of our operations servicing such smaller operators, we may experience lower utilization.

Strategic Direction

We believe that there is competitive value in providing integrated solutions that align the incentives of operators and service providers. We are pursuing opportunities to leverage our investment in our digital program and diesel substitution technologies (such as duel fuel capabilities), to provide a service strategy targeted at achieving emissions reductions, both for us and our customers. Our recent acquisition of Alamo added 9 hydraulic fracturing fleets, approximately 92% of which is Tier IV dual fuel capable. NexTier has been developing and building its digital program for some time, and our digital platform has been applied to the NexTier operating fleets, with the opportunity to add the digital platform to the Alamo fleets. We are also working toward a natural gas treatment and delivery solution, including natural gas sourcing, compression, transport, decompression, and treatment services, that will power NexTier’s fleet with field gas or compressed natural gas. This service solution seeks to address wellsites where there is not a reliable nearby gas supply, and thus, the full benefit and value of dual fuel or other lower emissions technologies may not otherwise be fully realized. Our integrated natural gas treatment and delivery solution became operational in the second half of 2021. This integrated strategy is designed to provide our customers with a streamlined approach to driving more sustainable, cost effective operations at the wellsite.

We believe our integrated approach and proven capabilities enable us to deliver cost-effective solutions for increasingly complex and technically demanding well completion requirements, which include longer lateral segments, higher pressure rates and proppant intensity and multiple fracturing stages in challenging high-pressure formations. In addition, our technical team and our innovation centers, provide us with the ability to supplement our service offerings with engineered solutions specifically tailored to address customers’ completion requirements and unique challenges. For example, utilizing a lateral science technique resulting in simulfrac stage pairing can reduce the operator’s cost per barrel by taking existing drilling data, analyzing the downhole rock properties, and matching the four or six wells across a simulfrac pad to create an optimized pair for every simulfrac stage. We believe utilization of this technique will ultimately improve injectivity of the frac treatments, improve the long-term production of the treated wells, and lower the equipment costs for each operation. Simulfrac stage pairing can help connect our simulfrac operational experience to real reservoir properties, thereby providing opportunity to deploy a more cost-effective solution that delivers higher production to the operator.

We believe that the safety, quality and efficiency of our service execution and our alignment with customers who recognize the value that we provide are central to our efforts to support utilization and grow our business.

Operating Effectively Through the COVID-19 Pandemic

We have continued our measures focused on the safety of our partners, employees, and the communities in which we operate, while at the same time seeking to mitigate the impact on our financial position and operations. In August the Company experienced higher levels of employee absenteeism as a result of the surge in COVID-19 cases associated with the Delta variant. While this trend improved as we exited the third quarter, it is possible that these negative effects will reoccur until infection rates decline. We continue to encourage our workforce to practice safe behaviors in the workplace and while away from work to help prevent community spread of COVID-19. In addition, a new federal mandate was implemented in November 2021 requiring companies with 100 or more employees to ensure that workers are either fully vaccinated or test negative for COVID-19 at least once per week. The extent of the impact of this and any other regulatory actions at the federal, state or local level is unclear and could have an adverse impact on the availability and cost related to labor.

Contingency plans remain in place in the event of significant impacts from COVID-19 infection resurgences, but there are no guarantees that such plans will be sufficient. Additional information regarding the actions we've taken since the onset of the COVID-19 pandemic and the increased risks to our business related to the COVID-19 pandemic can be found in our Annual Report on Form 10-K for the year ended December 31, 2020.

RESULTS OF OPERATIONS IN 2021 COMPARED TO 2020

The following is a comparison of our results of operations for the three months ended September 30, 2021 compared to the three months ended September 30, 2020.

Three Months Ended September 30, 2021 Compared with Three Months Ended September 30, 2020


	Three Months Ended September 30,
(Thousands of Dollars)					As a % of Revenue				Variance
Description	2021		2020		2021		2020		$		%
Completion Services	$	366,067	$	154,016	93	%	94	%	$	212,051	138	%
WC&I	27,097		9,659		7	%	6	%	17,438		181	%

Revenue	393,164		163,675		100	%	100	%	229,489		140	%
Completion Services	320,297		139,477		81	%	85	%	180,820		130	%
WC&I	24,340		10,589		6	%	6	%	13,751		130	%

Costs of services	344,637		150,066		88	%	92	%	194,571		130	%
Depreciation and amortization	44,861		73,570		11	%	45	%	(28,709)		(39	%)
Selling, general and administrative expenses	37,453		25,521		10	%	16	%	11,932		47	%
Merger and integration	4,752		7,288		1	%	4	%	(2,536)		(35	%)
(Gain) loss on disposal of assets	(1,133)		(3,027)		0	%	(2	%)	1,894		(63	%)
Impairment	—		2,681		0	%	2	%	(2,681)		(100	%)
Operating income (loss)	(37,406)		(92,424)		(10	%)	(56	%)	55,018		(60	%)
Other income (expense), net	585		(3,978)		0	%	(2	%)	4,563		(115	%)
Interest expense	(6,701)		(5,524)		(2	%)	(3	%)	(1,177)		21	%
Total other income (expense)	(6,116)		(9,502)		(2	%)	(6	%)	3,386		(36	%)
Income tax expense	(472)		(507)		0	%	0	%	35		(7	%)
Net income (loss)	$	(43,994)	$	(102,433)	(11	%)	(63	%)	$	58,439	(57	%)

Revenue: Total revenue is comprised of revenue from our Completion Services and Well Construction and Intervention Services segments. Revenue during the three months ended September 30, 2021 increased by $229.5 million, or 140%, to $393.2 million from $163.7 million during the three months ended September 30, 2020. This change in revenue by reportable segment is discussed below.

Completion Services: Revenue for Completion Services during the three months ended September 30, 2021 increased by $212.1 million, or 138%, to $366.1 million from $154.0 million during the three months ended September 30, 2020. The segment revenue increase is primarily attributable to more than doubling the number of fully utilized hydraulic fracturing fleets, increases in wireline and pump down services, and the acquisition of Alamo on August 31, 2021. Higher global commodity prices led to increased customer activity and modest price improvements in all operating basins as market conditions showed signs of improvement from low commodity prices and the COVID-19 pandemic. Fracturing Services increased to 24 fully utilized fleets, including 3 fully utilized Alamo fleets, during the three months ended September 30, 2021 from 11 fully utilized fleets during the three months ended September 30, 2020.

Well Construction and Intervention Services: Well Construction and Intervention Services segment revenue increased $17.4 million, or 181%, to $27.1 million during the three months ended September 30, 2021 from $9.7 million during the three months ended September 30, 2020. The increase in revenue is primarily due to higher activity, improved pricing, and increased utilization in our cementing and coil tubing services.

Cost of Services: Cost of services during the three months ended September 30, 2021 increased by $194.6 million, or 130%, to $344.6 million from $150.1 million during the three months ended September 30, 2020. The increase is primarily due to significantly increased activity and utilization, as explained in Revenue above, in addition to input costs inflation.

Equipment Utilization: Depreciation and amortization expense decreased $28.7 million, or 39%, to $44.9 million during the three months ended September 30, 2021 from $73.6 million, during the three months ended September 30, 2020. The decrease in depreciation and amortization is due to more equipment nearing the end of its useful lives in addition to the change in estimated useful life of equipment in the first quarter of 2021, which consisted mostly of increases to the expected life of our fracturing equipment. Gain on disposal of assets decreased $1.9 million, or 63%, to a gain of $1.1 million during the three months ended September 30, 2021 from $3.0 million during the three months ended September 30, 2020.

Selling, general and administrative expense: Selling, general and administrative (“SG&A”) expense, which represents costs associated with managing and supporting our operations, increased by $11.9 million, or 47%, to $37.5 million during the three months ended September 30, 2021 from $25.5 million during the three months ended September 30, 2020, primarily due to the contingent liability related to the Basic Energy Services bankruptcy filing, in addition to the increase in an accrual related to litigation costs.

Merger and integration expense: Merger and integration expense decreased by $2.5 million, or 35%, to $4.8 million during the three months ended September 30, 2021 from $7.3 million during the three months ended September 30, 2020. The merger and integration costs related to the C&J Merger were a lot more significant, even quarters after the transaction occurred, compared to the Alamo Acquisition merger and integration costs.

Effective tax rate: Our effective tax rate on continuing operations for the three months ended September 30, 2021 was (1.1)% for $0.5 million of recorded income tax expense. The difference between the effective tax rate and the U.S. federal statutory rate is due to foreign withholding taxes and change in valuation allowance. After considering all available positive and negative evidence, we determined that it is unlikely that we will utilize our net deferred tax assets in the foreseeable future and continued to maintain a full valuation allowance.

RESULTS OF OPERATIONS IN 2021 COMPARED TO 2020

The following is a comparison of our results of operations for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.

Nine Months Ended September 30, 2021 Compared with Nine Months Ended September 30, 2020


	Nine Months Ended September 30,
(Thousands of Dollars)					As a % of Revenue				Variance
Description	2021		2020		2021		2020		$		%
Completion Services	843,887		$	845,864	92	%	86	%	$	(1,977)	0	%
WC&I	69,824		83,734		8	%	8	%	(13,910)		(17	%)
Well Support Services	—		57,929		0	%	6	%	(57,929)		(100	%)
Revenue	913,711		987,527		100	%	100	%	(73,816)		(7	%)
Completion Services	768,562		716,008		84	%	73	%	52,554		7	%
WC&I	63,112		79,464		7	%	8	%	(16,352)		(21	%)
Well Support Services	—		45,591		0	%	5	%	(45,591)		(100	%)
Costs of services	831,674		841,063		91	%	85	%	(9,389)		(1	%)
Depreciation and amortization	131,400		234,651		14	%	24	%	(103,251)		(44	%)
Selling, general and administrative expenses	74,256		120,429		8	%	12	%	(46,173)		(38	%)
Merger and integration	4,930		33,498		1	%	3	%	(28,568)		(85	%)
(Gain) loss on disposal of assets	(7,742)		(11,942)		(1	%)	(1	%)	4,200		(35	%)
Impairment	—		37,008		0	%	4	%	(37,008)		(100	%)
Operating income (loss)	(120,807)		(267,180)		(13	%)	(27	%)	146,373		(55	%)
Other income (expense), net	9,113		(1,303)		1	%	0	%	10,416		(799	%)
Interest expense	(16,633)		(16,943)		(2	%)	(2	%)	310		(2	%)
Total other income (expense)	(7,520)		(18,246)		(1	%)	(2	%)	10,726		(59	%)
Income tax expense	(1,950)		(1,251)		0	%	0	%	(699)		56	%
Net income (loss)	$	(130,277)	$	(286,677)	(14	%)	(29	%)	$	156,400	(55	%)

Revenue: Total revenue is comprised of revenue from our Completion Services, Well Construction and Intervention Services, and Well Support Services segments. Revenue during the nine months ended September 30, 2021 decreased by $73.8 million, or 7%, to $913.7 million from $987.5 million during the nine months ended September 30, 2020. This change in revenue by reportable segment is discussed below.

Completion Services: Revenue for Completion Services during the nine months ended September 30, 2021 decreased by $2.0 million, or 0%, to $843.9 million from $845.9 million during the nine months ended September 30, 2020. The segment revenue decrease is primarily attributable to a 22% decrease in wireline and pump down services from less activity and lower pricing, partially offset by an increase of 5% in fracturing services driven by increased logistics services and the acquisition of Alamo. Fracturing Services increased to 18 fully utilized fleets, including Alamo, during the nine months ended September 30, 2021 from 16 fully utilized fleets during the nine months ended September 30, 2020.

Well Construction and Intervention Services: Well Construction and Intervention Services segment revenue decreased $13.9 million, or 17%, to $69.8 million during the nine months ended September 30, 2021 from $83.7 million during the nine months ended September 30, 2020. The decrease in revenue is mostly attributable to less activity, lower utilization, and price reductions in both our cementing and coil tubing services resulting from lower customer demand as a result of the COVID-19 pandemic and weakened market conditions.

Cost of Services: Cost of services during the nine months ended September 30, 2021 decreased by $9.4 million, or 1%, to $831.7 million from $841.1 million during the nine months ended September 30, 2020. The reduction is primarily due to significantly less activity and lower utilization, as explained in Revenue above, combined with higher sand and freight

costs as a result of increased logistics services in our Completions Segment, and increased repair and maintenance expenses related to startup costs of fleet re-deployments, in addition to input costs inflation.

Equipment Utilization: Depreciation and amortization expense decreased $103.3 million, or 44%, to $131.4 million during the nine months ended September 30, 2021 from $234.7 million, during the nine months ended September 30, 2020. The decrease in depreciation and amortization is due to more equipment nearing the end of its useful lives in addition to the change in estimated useful life of equipment in the first quarter of 2021, which consisted mostly of increases to the expected life of our fracturing equipment. Gain on disposal of assets decreased $4.2 million, or 35%, to $7.7 million during the nine months ended September 30, 2021 from a gain of $11.9 million during the nine months ended September 30, 2020.

Selling, general and administrative expense: Selling, general and administrative (“SG&A”) expense, which represents costs associated with managing and supporting our operations, decreased by $46.2 million, or 38%, to $74.3 million during the nine months ended September 30, 2021 from $120.4 million during the nine months ended September 30, 2020, primarily due to the $24.9 million accrual reduction for our regulatory audit estimate and our business transformation results to structurally drive out costs and increase efficiencies in our support function processes.

Merger and integration expense: Merger and integration expense decreased by $28.6 million, or 85%, to $4.9 million during the nine months ended September 30, 2021 from $33.5 million during the nine months ended September 30, 2020 primarily due to the C&J merger and integration related expenses in the earlier part of 2020, which were larger in comparison to the Alamo Acquisition merger and integration related expenses.

Effective tax rate: Our effective tax rate on continuing operations for the nine months ended September 30, 2021 was (1.5)% for $(2.0) million of recorded income tax expense. The difference between the effective tax rate and the U.S. federal statutory rate is due to foreign withholding taxes, change in valuation allowance and discrete tax effect related to indefinite-lived assets. After considering all available positive and negative evidence, we determined that it is unlikely that we will utilize our net deferred tax assets in the foreseeable future and continued to maintain a full valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity represents a company's ability to adjust its future cash flows to meet its needs and opportunities, both expected and unexpected.


	(Thousands of Dollars)
	September 30, 2021		December 31, 2020
Cash and cash equivalents	$	135,525	$	275,990
Debt, net of unamortized deferred financing costs and unamortized debt discount	373,022		335,540


	(Thousands of Dollars)
	Nine Months Ended September 30,
	2021		2020
Net cash provided by (used in) operating activities	$	(19,320)	$	82,676
Net cash used in investing activities	(155,118)		(25,309)
Net cash provided by (used in) financing activities	33,540		(7,766)

Significant sources and uses of cash during the nine months ended September 30, 2021

Uses of cash:

•Operating activities:

–Net cash used in operating activities during the nine months ended September 30, 2021 was $19.3 million which was down $102.0 million from the nine months ended September 30, 2020. The change is primarily due to a decrease in activity and pricing for our wireline and pump down services, an increase in commodity prices, additional maintenance expenses related to startup costs required for fleet re-deployments, and inflation. For further discussion, see Part I, "Item 2. Management Discussion and Analysis of Financial Condition and Results of Operations" .

•Investing activities:

–Net cash used in investing activities during the nine months ended September 30, 2021 of $155.1 million, consisting primarily of capital expenditures, $101.8 million related to acquisition of business and payment of consideration liability, net of $34.4 million in cash received from the WSS notes and $24.5 million in proceeds from disposal of assets.

•Financing activities:

–Proceeds from the Equipment Loan for the nine months ended September 30, 2021 totaled $39.4 million.

–Cash used to repay our debt facilities, excluding leases and interest, during the nine months ended September 30, 2021 was $2.6 million.

–Cash used to repay our finance leases during the nine months ended September 30, 2021 was $1.1 million.

–Shares repurchased and retired related to payroll tax withholdings on our share-based compensation for the nine months ended September 30, 2021 totaled $1.9 million.

Significant sources and uses of cash during the nine months ended September 30, 2020

Sources of cash:

•Operating activities:

–Net cash generated by operating activities during the nine months ended September 30, 2020 of $82.7 million was the result of our thoroughness in receiving collections from our customers and controlling costs.

Uses of cash:

•Investing activities:

–Net cash used in investing activities for the nine months ended September 30, 2020 of $25.3 million, consisting primarily of capital expenditures, net of cash received as part of the sale of the Wells Support Services business segment.

•Financing activities:

–Cash used to repay our debt facilities, excluding leases and interest, during the nine months ended September 30, 2020 was $2.6 million.

–In the first quarter of 2020, the Company drew down $175 million on the 2019 ABL Facility (defined below). This borrowing was to provide the Company better flexibility while managing its cash position during the ongoing COVID-19 pandemic. The borrowing on the 2019 ABL Facility was repaid in full during the second quarter of 2020.

–Cash used to repay our finance leases during the nine months ended September 30, 2020 was $3.1 million.

–Shares repurchased and retired related to payroll tax withholdings on our share-based compensation for the nine months ended September 30, 2020 totaled $2.0 million.

Future sources and use of cash

The Company currently expects fourth quarter capital expenditures of approximately $50 million, comprised of maintenance capital expenditures across all product and service lines, as well as strategic investments in additional dual fuel conversions, and the continued deployment of capital for our new Power Solutions business. The Company remains committed to disciplined growth through the coming cycle. While the Company believes it is too early to provide a 2022 capital expenditures guidance, we expect a significant year-over-year capital expenditures decline, even with the inclusion of a full year of Alamo, as additional fleet upgrades will be more limited relative to 2021.

Debt service for the year ended December 31, 2021 is projected to be $25.5 million, of which $4.8 million is related to finance leases, excluding buyout payments. We anticipate our debt service will be funded by cash flows from operations. Our leverage ratio, as calculated pursuant to the terms of our debt agreement, is 5.80x for the twelve rolling months ended September 30, 2021.

In addition, depending upon Alamo's performance during the performance period, we may be using cash to perform our obligations under the Earnout Agreement related to the Alamo Acquisition. We anticipate that any payments due under the Earnout Agreement will be funded by cash flows from operations.

Other factors affecting liquidity

Financial position in current market. As of September 30, 2021, we had $135.5 million of cash and a total of $154.1 million available under our revolving credit facility. As of September 30, 2021, we were compliant with all financial and non-financial covenants in our bank agreements. Furthermore, our debt maturities extend over a long period of time. Despite the current uncertainty in global markets resulting from the COVID-19 pandemic, we currently believe that our cash on hand, cash flow generated from operations and availability under our revolving credit facility will provide sufficient liquidity for at least the next 12 months, including for capital expenditures, debt service, working capital investments, and contingent liabilities.

Guarantee agreements. In the normal course of business, we have agreements with financial institutions as part of our 2019 ABL Facility under which $23.2 million of letters of credit were outstanding as of September 30, 2021.

Customer receivables. In line with industry practice, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. The majority of our trade receivables have payment terms of 30 to 60 days. In weak economic environments, we may experience increased delays and failures to pay our invoices due to, among other reasons, a reduction in our customers' cash flow from operations and their access to the credit markets. The economic impact of the COVID-19 pandemic and the resulting actions taken to control the further spread of the virus may exacerbate these delays or failures to pay in the future. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have an adverse effect on our liquidity, consolidated results of operations and consolidated financial condition.

Purchase Commitments. In the normal course of business, we enter into various contractual obligations that impact or could impact our liquidity. The Company has a number of purchase commitments that primarily relate to our agreements with vendors for sand purchases, other commodities/services and deposits on equipment. The purchase commitments to these vendors include obligations to purchase a minimum amount of product/services; provided that, if the minimum purchase requirement is not met, the shortfall at the end of the applicable period is settled in cash or, in some cases, carried forward to the next period. We also have a variety of operating lease obligations related to our real estate, rail cars, and light duty vehicles. See Part II, "Item 1A. Risk Factors." for additional information on the risks related to these purchase commitments.

Long-Term Debt Arrangements

2019 ABL Facility

We, and certain of our other subsidiaries as additional borrowers and guarantors, are parties to a Second Amended and Restated Asset-Based Revolving Credit Agreement (the “2019 ABL Facility”) that matures on October 31, 2024. This facility provides for, among other things, a $450.0 million revolving credit facility (with a $100.0 million subfacility for letters of credit), subject to a borrowing base in accordance with the terms agreed between us and the lenders. As of September 30, 2021, we had no outstanding principal amounts under the 2019 ABL Facility.

The 2019 ABL Facility is subject to customary fees, guarantees of subsidiaries, events of default, restrictions and covenants, including certain restricted payments and a consolidated fixed charge coverage ratio test. As of September 30, 2021, the Company was in compliance with all covenants.

2018 Term Loan Facility

We are party to a term loan facility and certain of our subsidiaries are guarantors (the "2018 Term Loan Facility") that matures on May 25, 2025. As of September 30, 2021, there was $338.6 million principal amount of term loans outstanding (the "2018 Term Loans") at an interest rate of LIBOR plus an applicable margin, which is currently at 4.00%. The 2018 Term Loan Facility is subject to customary fees, guarantees of subsidiaries, events of default, restrictions and covenants, including certain restricted payments. As of September 30, 2021, the Company was in compliance with all covenants.

Equipment Loan

On August 20, 2021, the Company entered into the Master Loan and Security Agreement (the “Master Agreement”) with Caterpillar Financial Services Corporation. The Master Agreement provides the backdrop for the Company to enter into secured equipment financing term loans from time to time in an aggregate amount of up to $46.5 million (the “Equipment Loans”). The Equipment Loans may be drawn in multiple tranches, with each loan evidenced by a separate promissory note. On September 3, 2021, we entered into a term note for $39.4 million (the “Note”) for an equipment financing loan. The Note will bear interest at a rate of 5.25% per annum and will mature no later than June 1, 2025. The Master Agreement and the Note contain customary affirmative and negative covenants, including limitations on further encumbrance of the collateral subject to the applicable loans under the Master Agreement. As of September 30, 2021, the Company was in compliance with all covenants.

Off-Balance Sheet Arrangements

We do not have any material off-balance sheet financing arrangements, transactions or special purpose entities.

Significant Accounting Policies and Estimates

The preparation of our unaudited condensed consolidated financial statements and related notes to the unaudited condensed consolidated financial statements included within Part I, "Item 1. Condensed Consolidated Financial Statements (Unaudited)" requires us to make estimates that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures of contingent assets and liabilities. We base these estimates on historical results and various other assumptions believed to be reasonable, all of which form the basis for making estimates concerning the carrying values of assets and liabilities that are not readily available from other sources. Actual results may differ from these estimates.

A critical accounting estimate is one that requires a high level of subjective judgment by management and has a material impact to our financial condition or results of operations. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related notes included within Part I, "Item 1. Condensed Consolidated Financial Statements (Unaudited)" of this Quarterly Report on Form 10-Q, as well as our consolidated and combined financial statements and related notes included in Part II, "Item 8. Financial Statements and Supplementary Data" and Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K Report on Form 10-K for the year ended December 31, 2020.

New Accounting Pronouncements

For discussion on the potential impact of new accounting pronouncements issued but not yet adopted, see Note (15) New Accounting Pronouncements of Part I, "Item 1. Condensed Consolidated Financial Statements (Unaudited)."

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Interest Rate Risk. As of March 31, 2021, we had variable-rate debt outstanding, the exposure to which we manage with our interest-rate-related derivative instrument. We held no derivative instruments that increased our exposure to market risks for foreign currency rates, commodity prices or other market price risks. We are exposed to changes in interest rates on our floating rate borrowings under our 2019 ABL Facility and 2018 Term Loan. As of September 30, 2021, we had $338.6 million aggregate principal amount outstanding under the 2018 Term Loan. The impact of a 1.0% increase in interest rates under the terms of the 2018 Term Loan would have a $0.9 million and $2.6 million impact on interest expense for the three and nine months ended September 30, 2021, respectively.

Commodity Price Risk. Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as proppant, chemicals and guar. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials (particularly guar and proppant) in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Depending on market conditions, we have generally been able to pass along price increases to our customers; however, we may be unable to do so in the future. We generally do not engage in commodity price hedging activities. However, we have purchase commitments with certain vendors to supply a majority of the proppant used in our operations. Some of these agreements are take-or-pay agreements with minimum purchase obligations. As a result of future decreases in the market price of proppants, we could be required to purchase goods and pay prices in excess of market prices at the time of purchase. For further quantitative disclosure about our market risk related to our variable-rate debt, interest-rate-related derivative instrument and purchase commitments, see Part I, "Item 2. Management Discussion and Analysis of Financial Condition and Results of Operations".

Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. As a result of the COVID-19 pandemic, we have seen an increase in collection time related to trade receivables. We have established various procedures to manage our credit exposure, including credit evaluations and maintaining an allowance for doubtful accounts. For certain additional information regarding credit risk related to derivative instruments we hold, see Note (8) Derivatives of Part I, "Item 1. Condensed Consolidated Financial Statements (Unaudited)."

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including the Chief Executive Officer and Principal Financial Officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures were effective as of such date. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's (the "SEC") rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Principal Financial Officer, to allow timely decisions regarding required disclosure.

As disclosed in Note (3) Alamo Acquisition in the Notes to Consolidated Financial Statements, we acquired Alamo on August 31, 2021, and its total revenues constituted approximately 9% of total revenues as shown on our consolidated financial statements for the three months ended September 30, 2021. Alamo’s total assets constituted approximately 27% of total assets as shown on our consolidated financial statements as of September 30, 2021. We excluded Alamo’s disclosure controls and procedures that are subsumed by its internal control over financial reporting from the scope of management's assessment of the effectiveness of our disclosure controls and procedures. This exclusion is in accordance with the guidance issued by the Staff of the Securities and Exchange Commission that an assessment of recent business combinations may be omitted from management's assessment of internal control over financial reporting for one year following the acquisition. As part of the Company’s ongoing integration activities, the Company’s financial reporting controls and procedures are in the process of being implemented at Alamo. The two companies will maintain separate accounting systems through December 31, 2021. The condensed consolidated financial statements presented in this Quarterly Report on Form 10-Q were prepared using information obtained from these separate accounting systems.

Changes in Internal Control Over Financial Reporting

Except as described above, there were no changes to our internal control over financial reporting that occurred during the quarter ended September 30, 2021 that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

As is typical of the industry, the Company is, from time to time and in the ordinary course of business, involved in routine litigation or subject to disputes or claims related to its business activities. It is the Company's opinion that although the amount of liability with respect to certain of these known legal proceedings and claims cannot be ascertained at this time, any resulting liability will not have a material adverse effect individually or in the aggregate on the Company's financial condition, cash flows or results of operations; however, there can be no assurance as to the ultimate outcome of these matters.

Item 1A. Risk Factors

The statements in this section describe the known material risks to our business and should be considered carefully. There have been no material changes from the risk factors previously disclosed in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

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

(a) Unregistered Sales of Equity Securities

None.

(b) Use of Proceeds

None.


Issuer Purchases of Equity Securities
Settlement Period	(a) Total Number of Shares Purchased(1)	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(1)
July 1, 2021 through July 31, 2021	44,130	$3.98	—	$—
August 1, 2021 through August 31, 2021	88,780	$3.56	—	$—
September 1, 2021 through September 30, 2021	7,715	$3.77	—	$—
Total	140,625	$3.70	—	$—

(1) Consists of shares that were withheld by us to satisfy tax withholding obligations of employees that arose upon the vesting of restricted shares. The value of such shares is based on the closing price of our common shares on the vesting date.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The documents listed in the Exhibit Index of this Quarterly Report on Form 10-Q are incorporated by reference or are filed with this Quarterly Report on Form 10-Q, in each case as indicated therein (numbered in accordance with Item 601 of Regulation S-K).



Exhibit Number						Exhibit Description
10.1						Purchase Agreement, dated as of August 4, 2021 (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed August 4, 2021).
10.2						Form of Earnout Agreement (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed August 4, 2021).
10.3						Form of Registration Rights Agreement (incorporated by reference to Exhibit 10 .2 to the Registrant's Current Report on Form 8-K filed August 4, 2021).
10.4						Master Loan and Security Agreement, dated August 20, 2021 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on September 7, 2021).
10.5*†						Employment Agreement, dated August 4, 2021 by and between Alamo Pressure Pumping, LLC and Michael Joseph McKie.
31.1*						Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 .
31.2*						Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**						Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*						XBRL Instance Document - The Instance Document does not appear in the Interactive Data Files because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*						XBRL Taxonomy Extension Schema Document.
101.CAL*						XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB*						XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*						XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF*						XBRL Taxonomy Extension Definition Linkbase Document.
104						Cover Page Interactive Data File (embedded within the Inline XBRL document).

* Filed herewith.

** Furnished herewith.

† Indicates a management contract or compensatory plan or arrangement.

SIGNATURES

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 on November 9, 2021.


			NexTier Oilfield Solutions Inc. (Registrant)

			By:			/s/ Phung Ngo-Burns
						Phung Ngo-Burns
						Principal Accounting Officer and Duly Authorized Officer