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Non-accelerated filer

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Smaller reporting company

Emerging growth company

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 ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.



	March 31, 2019		December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	79,518	$	132,700
Accounts receivable - net of allowance for doubtful accounts of $199 and $100, respectively	357,472		202,956
Inventories	5,870		6,353
Prepaid expenses	5,597		6,610
Other current assets	1,198		638
Total current assets	449,655		349,257
PROPERTY AND EQUIPMENT - Net of accumulated depreciation	945,089		912,846
OPERATING LEASE RIGHT-OF-USE ASSETS	1,734		—
OTHER NONCURRENT ASSETS:
Goodwill	9,425		9,425
Intangible assets - net of amortization	—		13
Other noncurrent assets	3,102		2,981
Total other noncurrent assets	12,527		12,419
TOTAL ASSETS	$	1,409,005	$	1,274,522
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	274,016	$	214,460
Operating lease liabilities	416		—
Finance lease liabilities	3,042		—
Accrued and other current liabilities	24,492		138,089
Accrued interest payable	691		211
Total current liabilities	302,657		352,760
DEFERRED INCOME TAXES	75,366		54,283
LONG-TERM DEBT	160,000		70,000
NONCURRENT OPERATING LEASE LIABILITIES	1,441		—
OTHER LONG-TERM LIABILITIES	—		124
Total liabilities	539,464		477,167
COMMITMENTS AND CONTINGENCIES (Note 10)
SHAREHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 30,000,000 shares authorized, none issued, respectively	—		—
Common stock, $0.001 par value, 200,000,000 shares authorized,100,294,098 and 100,190,126 shares issued, respectively	100		100
Additional paid-in capital	820,071		817,690
Accumulated surplus (deficit)	49,370		(20,435		)
Total shareholders’ equity	869,541		797,355
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,409,005	$	1,274,522



	Three Months Ended March 31,
	2019			2018
REVENUE - Service revenue	$	546,179		$	385,219
COSTS AND EXPENSES
Cost of services (exclusive of depreciation and amortization)	381,523			298,122
General and administrative (inclusive of stock-based compensation)	18,524			11,944
Depreciation and amortization	33,117			18,936
Loss on disposal of assets	19,228			7,665
Total costs and expenses	452,392			336,667
OPERATING INCOME	93,787			48,552
OTHER EXPENSE:
Interest expense	(1,903		)	(1,261		)
Other expense	(187		)	(230		)
Total other expense	(2,090		)	(1,491		)
INCOME BEFORE INCOME TAXES	91,697			47,061
INCOME TAX EXPENSE	(21,892		)	(10,353		)
NET INCOME	$	69,805		$	36,708
NET INCOME PER COMMON SHARE:
Basic	$	0.70		$	0.44
Diluted	$	0.67		$	0.42
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	100,232			83,081
Diluted	104,123			86,848



	Three Months Ended March 31, 2019
	Common Stock
	Shares	Amount		Additional Paid-In Capital		Accumulated (Deficit) Surplus			Total
BALANCE - January 1, 2019	100,190	$	100	$	817,690	$	(20,435	)	$	797,355
Stock-based compensation cost	—	—		1,829		—			1,829
Issuance of equity awards, net	104	—		552		—			552
Net income	—	—		—		69,805			69,805
BALANCE - March 31, 2019	100,294	$	100	$	820,071	$	49,370		$	869,541



	Three Months Ended March 31, 2018
	Common Stock
	Shares	Amount		Additional Paid-In Capital		Accumulated Deficit			Total
BALANCE - January 1, 2018	83,040	$	83	$	607,466	$	(194,297	)	413,252
Stock-based compensation cost	—	—		758		—			758
Issuance of common stock for vested RSUs	372	—		—		—			—
Net income	—	—		—		$	36,708		36,708
BALANCE - March 31, 2018	83,412	$	83	$	608,224	$	(157,589	)	$	450,718



	Three Months Ended March 31,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	69,805		$	36,708
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	33,117			18,936
Deferred income tax expense	21,083			10,054
Amortization of deferred revenue rebate	—			462
Amortization of deferred debt issuance costs	134			89
Stock-based compensation	1,829			758
Loss on disposal of fixed assets	19,228			7,529
Changes in operating assets and liabilities:
Accounts receivable	(154,516		)	(53,461		)
Other current assets	(274		)	(338		)
Inventories	482			(1,327		)
Prepaid expenses	759			(742		)
Accounts payable	45,324			38,750
Accrued and other current liabilities	(1,366		)	(3,252		)
Accrued interest	480			468
Net cash provided by operating activities	36,085			54,634
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(178,912		)	(75,148		)
Proceeds from sale of assets	1,027			317
Net cash used in investing activities	(177,885		)	(74,831		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	90,000			46,735
Repayments of borrowings	—			(2,343		)
Repayments of insurance financing	(1,934		)	(1,371		)
Payment of debt issuance costs	—			(360		)
Proceeds from exercise of equity awards	552			—
Net cash provided by financing activities	88,618			42,661
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(53,182		)	22,464
CASH AND CASH EQUIVALENTS - Beginning of period	132,700			23,949
CASH AND CASH EQUIVALENTS - End of period	$	79,518		$	46,413

The accompanying condensed consolidated financial statements of ProPetro Holding Corp. and its subsidiary (the "Company," "we," "us" or "our") have been prepared in accordance with the requirements of the U.S. Securities and Exchange Commission ("SEC") for interim financial information and do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America ("GAAP") for annual financial statements. Those adjustments (which consisted of normal recurring accruals) that are, in the opinion of management, necessary for a fair presentation of the results of the interim periods have been made. Results of operations for such interim periods are not necessarily indicative of the results of operations for a full year due to changes in market conditions and other factors. The condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2018 included in our Form 10-K filed with the SEC ("Form 10-K").

The Company’s services are sold based upon contracts with customers. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. The following is a description of the principal activities, separated by reportable segment and all other, from which the Company generates its revenue.

Hydraulic fracturing is a well-stimulation technique intended to optimize hydrocarbon flow paths during the completion phase of shale wellbores. The process involves the injection of water, sand and chemicals under high pressure into shale formations. Our hydraulic fracturing contracts have one performance obligation, contracted total stages, satisfied over time. We recognize revenue over time using a progress output method, unit-of-work performed method, which is based on the agreed fixed transaction price and actual stages completed. We believe that recognizing revenue based on actual stages completed faithfully depicts how our hydraulic fracturing services are transferred to our customers over time.

Acidizing, which is part of our hydraulic fracturing operating segment, involves a well-stimulation technique where acid is injected under pressure into formations to form or expand fissures. Our acidizing contracts have one performance obligation, satisfied at a point-in-time upon completion of the contracted service when control is transferred to the customer. Jobs for these services are typically short term in nature, with most jobs completed in less than a day. We recognize acidizing revenue at a point-in-time, upon completion of the performance obligation.

Our cementing services use pressure pumping equipment to deliver a slurry of liquid cement that is pumped down a well between the casing and the borehole. Our cementing contracts have one performance obligation, satisfied at a point-in-time upon completion of the contracted service when control is transferred to the customer. Jobs for these services are typically short term in nature, with most jobs completed in less than a day. We recognize cementing revenue at a point-in-time, upon completion of the performance obligation.

All Other— All other consists of our coil tubing, drilling and flowback, which are all downhole well stimulation and completion/remedial services. The performance obligation for each of the services has a fixed transaction price which is satisfied at a point-in-time upon completion of the service when control is transferred to the customer. Accordingly, we recognize revenue at a point-in-time, upon completion of the service and transfer of control to the customer.

Accounts receivables are stated at the amount billed and billable to customers. At March 31, 2019 and December 31, 2018, accrued revenue (unbilled receivable) included as part of our accounts receivable was $33.8 million and $18.0 million, respectively. At March 31, 2019, the transaction price allocated to the remaining performance obligation for our partially completed hydraulic fracturing operations was $79.8 million, which is expected to be completed and recognized in one month following the current period balance sheet date, in our pressure pumping reportable segment.

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") No. 2016-02, Leases. This new leases standard introduces a lessee model that brings most leases on the balance sheet. This new standard increases transparency and comparability by recognizing a lessee’s rights and obligations resulting from leases by recording them on the balance sheet as Right of Use ("ROU") Assets and Lease Liabilities. Leases will be classified as either finance or operating, which will impact the pattern of expense recognition on the income statement. This ASU also requires additional qualitative and quantitative disclosures to better enable users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. Effective January 1, 2019, we adopted the new leases standard using the modified retrospective transition method and electing to account for comparative periods under legacy GAAP. We also elected other practical expedients provided by the new leases standard, the short-term lease recognition practical expedient in which leases with an initial term of 12 months or less will not be recognized on the balance sheet and the practical expedient to not separate lease and non-lease components for our real estate class of leased assets. See Note 9 for additional disclosures relating to our adoption of ASU 2016-02.

In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment, which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test. As a result, under this ASU, an entity would recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value. Although, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This ASU is effective for impairment tests in fiscal years beginning after December 15, 2019, on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We believe that the adoption of this guidance will not materially affect our consolidated financial statements.

In determining fair value, the Company uses various valuation approaches and establishes a hierarchy for inputs used in measuring fair value that maximizes the use of relevant observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used, when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions about the assumptions other market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the observability of inputs as follows:

Level 1 — Valuations based on quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Valuation adjustments and block discounts are not applied to Level 1 instruments. Since valuations are based on quoted prices that are readily and regularly available in an active market, valuation of these instruments does not entail a significant degree of judgment.

A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

We generally apply fair value techniques to our reporting units on a nonrecurring basis associated with valuing potential impairment loss related to goodwill. Our estimate of the reporting unit fair value is based on a combination of income and market approaches, Level 1 and 3, respectively, in the fair value hierarchy. The income approach involves the use of a discounted cash flow method, with the cash flow projections discounted at an appropriate discount rate. The market approach involves the use of comparable public companies market multiples in estimating the fair value. Significant assumptions include projected revenue growth, capital expenditures, utilization, gross margins, discount rates, terminal growth rates, and weight allocation between income and market approaches. If the reporting unit's carrying amount exceeds its fair value, we consider goodwill impaired, and the impairment loss is calculated and recorded in the period. There were no additions to, or disposal of, goodwill during the three months ended March 31, 2019 and 2018. At December 31, 2018, we determined our goodwill carrying value not to be impaired as per our annual impairment test.

On March 22, 2017, we entered into a revolving credit facility with a $150.0 million borrowing capacity ("ABL Credit Facility"). Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with no LIBOR floor. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company. The ABL Credit Facility has a borrowing base of 85% of eligible accounts receivable less customary reserves. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. In addition, the ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio of 1.0x when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $12.0 million. The ABL has a commitment fee of 0.38%, which reduces to 0.25% if utilization is greater than 50.0% of the borrowing base.

On February 22, 2018, we entered into an amendment with our lenders to increase the capacity of the ABL Credit Facility. The amendment increased total capacity under the facility from $150.0 million to $200.0 million, and modified the Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10.0% of the lesser of the facility size and the Borrowing Base and (ii) $15.0 million.

On December 19, 2018, we entered into a second amendment with our lenders to further increase the capacity of the ABL Credit Facility. The second amendment increased total capacity under the facility from $200.0 million to $300.0 million and extended the maturity date of the ABL Credit Facility from March 22, 2022 until December 19, 2023. The second amendment to the ABL Credit Facility further modified the Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $22.5 million.

In accordance with Accounting Standards Codification ("ASC") 280—Segment Reporting, the Company has one reportable segment (pressure pumping) comprised of the hydraulic fracturing and cementing operating segments. All other operating segments and corporate administrative expenses are included in the ‘‘all other’’ category in the table below. Inter-segment revenues are not material and are not shown separately in the table below.

The Company manages and assesses the performance of the reportable segment by its adjusted EBITDA (earnings before other income (expense), interest, taxes, depreciation & amortization, stock-based compensation expense, impairment expense, (gain)/loss on disposal of assets and other unusual or nonrecurring expenses or income). A reconciliation from segment level financial information to the consolidated statement of operations is provided in the table below.



	Three Months Ended March 31, 2019
($ in thousands)	Pressure Pumping		All Other			Total
Service revenue	$	532,064	$	14,115		$	546,179
Adjusted EBITDA	$	151,040	$	(765	)	$	150,275
Depreciation and amortization	$	31,783	$	1,334		$	33,117
Goodwill	$	9,425	$	—		$	9,425
Capital expenditures	$	82,035	$	4,112		$	86,147
Total assets	$	1,351,786	$	57,219		$	1,409,005

	Three Months Ended March 31, 2018
($ in thousands)	Pressure Pumping		All Other			Total
Service revenue	$	375,045	$	10,174		$	385,219
Adjusted EBITDA	$	79,063	$	(2,319	)	$	76,744
Depreciation and amortization	$	17,763	$	1,173		$	18,936
Goodwill	$	9,425	$	—		$	9,425
Capital expenditures	$	77,435	$	2,519		$	79,954
Total assets at December 31, 2018	$	1,230,830	$	43,692		$	1,274,522

Reconciliation of net income (loss) to adjusted EBITDA:



	Three Months Ended March 31, 2019
($ in thousands)	Pressure Pumping		All Other			Total
Net income (loss)	$	98,094	$	(28,289	)	$	69,805
Depreciation and amortization	31,783		1,334			33,117
Interest expense	—		1,903			1,903
Income tax expense	—		21,892			21,892
Loss on disposal of assets	19,006		222			19,228
Stock-based compensation	—		1,829			1,829
Other expense	—		187			187
Deferred IPO bonus and retention expense	2,157		157			2,314
Adjusted EBITDA	$	151,040	$	(765	)	$	150,275

	Three Months Ended March 31, 2018
($ in thousands)	Pressure Pumping		All Other			Total
Net income (loss)	$	52,934	$	(16,226	)	$	36,708
Depreciation and amortization	17,763		1,173			18,936
Interest expense	—		1,261			1,261
Income tax expense	—		10,353			10,353
Loss (gain) on disposal of assets	7,828		(163		)	7,665
Stock-based compensation	—		758			758
Other expense	—		230			230
Other general and administrative expense⁽¹⁾	—		1			1
Deferred IPO bonus expense	538		294			832
Adjusted EBITDA	$	79,063	$	(2,319	)	$	76,744

Basic net income per common share is computed by dividing the net income relevant to the common stockholders by the weighted average number of shares outstanding during the period. Diluted net income per common share uses the same net income divided by the sum of the weighted average number of shares of common stock outstanding during the period, plus dilutive effects of options, performance and restricted stock units outstanding during the period calculated using the treasury method and the potential dilutive effects of preferred stocks (if any) calculated using the if-converted method.



	Three Months Ended March 31,
(In thousands, except for per share data)	2019		2018
Numerator (both basic and diluted)
Net income relevant to common stockholders	$	69,805	$	36,708
Denominator
Denominator for basic income per share	100,232		83,081
Dilutive effect of stock options	3,160		3,191
Dilutive effect of performance stock units	555		96
Dilutive effect of non-vested restricted stock	176		480
Denominator for diluted income per share	104,123		86,848
Basic income per common share	$	0.70	$	0.44
Diluted income per common share	$	0.67	$	0.42

There were no new grants during the three months ended March 31, 2019 and 2018. As of March 31, 2019, the aggregate intrinsic value for our outstanding stock options was $77.5 million, and the aggregate intrinsic value for our exercisable stock options was $74.3 million. The aggregate intrinsic value for the exercised stock options during the three months ended March 31, 2019 was $1.4 million. The remaining contractual term for the outstanding and exercisable stock options as of March 31, 2019, was 5.6 years and 5.5 years, respectively. For the three months ended March 31, 2019 and 2018, we recognized $0.2 million and $0.2 million in stock compensation expense related to these stock option awards.

During the three months ended March 31, 2019, we granted a total of 318,332 restricted stock units ("RSUs") to employees, directors and executives pursuant to our Incentive Award Plan ("IAP"). Each RSU represents the right to receive one share of common stock. The fair value of the RSUs is based on the closing share price of our common stock on the date of grant. During the three months ended March 31, 2019 and 2018, the recorded stock compensation expense for all RSUs was $0.9 million and $0.4 million, respectively. As of March 31, 2019 the total unrecognized compensation expense for all RSUs was approximately $11.3 million, and is expected to be recognized over a weighted average period of approximately 2.5 years.

Effective March 18, 2019, our Board of Directors authorized and granted 199,413 performance stock units ("PSUs") to certain key employees under the IAP. The actual number of shares that may be issued under the PSUs ranges from zero up to a maximum of twice the target number of performance stock unit awards granted to the participant, based on our total shareholder return relative to a designated peer group from January 1, 2019 through December 31, 2021. Compensation expense is recorded

ratably over the corresponding requisite service period. The fair value of PSUs is determined using a Monte Carlo probability model. Grant recipients do not have any shareholder rights until performance relative to the peer group has been determined following the completion of the performance period and shares have been issued. During the three months ended March 31, 2019 and 2018, the recorded stock compensation expense for the PSUs was $0.7 million and $0.2 million, respectively.



Period Granted	Target Shares Outstanding at January 1, 2019	Target Shares Granted	Target Shares Vested	Target Shares Forfeited	Target Shares Outstanding at March 31, 2019	Weighted Average Grant Date Fair Value per Share
2017	169,635	—	—	—	169,635	$	10.73
2018	178,975	—	—	—	178,975	$	27.51
2019	—	199,413	—	—	199,413	$	34.82
Total	348,610	199,413	—	—	548,023	$	24.98

The total stock compensation expense for the three months ended March 31, 2019 and 2018 for all stock awards was $1.8 million and $0.8 million, respectively. The total unrecognized compensation expense as of March 31, 2019 is approximately $23.1 million, and is expected to be recognized over a weighted average period of approximately 2.4 years.

For the three months ended March 31, 2019 and 2018, the Company paid approximately $0.1 million and $0.03 million, respectively, for the use of transportation services from a related party. The Company also rents equipment in Elk City, Oklahoma from a related party, and for the three months ended March 31, 2019 and 2018, the Company paid $0.05 million and $0.05 million, respectively.

On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc. ("Pioneer") and Pioneer Pressure Pumping Services, LLC. The acquisition cost of the assets was comprised of approximately $110.0 million of cash and 16.6 million shares of our common stock. In addition, we entered into a real estate lease for a crew camp facility with Pioneer, as disclosed in Note 9. In connection with the consummation of the transaction, we became a service provider to Pioneer, providing pressure pumping and related services for a term of up to ten years. Revenue from services provided to Pioneer accounted for approximately 29.3% and 4.8% of our total revenue during the three months ended March 31, 2019 and 2018, respectively. As of March 31, 2019, the balance due from Pioneer for services we provided during the period amounted to $93.7 million and the amount due to Pioneer was $0.2 million. As of December 31, 2018, the balance due from Pioneer for services we provided during the period amounted to $15.7 million and the amount due to Pioneer was $109.8 million.

On January 1, 2019, we implemented ASC 842, using the modified transition approach and elected not to restate prior years ("Comparatives Under ASC 840 Option"). Accordingly, the effects of adopting ASC 842 were adjusted in the beginning of 2019 while prior periods are accounted for under the legacy GAAP, ASC 840. There was no cumulative effect adjustment on beginning retained earnings. We also elected other practical expedients provided by the new leases standard, the short-term lease recognition practical expedient in which leases with a term of twelve months or less will not be recognized on the balance sheet and the practical expedient to not separate lease and non-lease components for real estate class of assets. Our discount rate was based on our estimated incremental borrowing rate on a collateralized basis with similar terms and economic considerations as our lease payments at the lease commencement. Below is a description of our operating and finance leases.

In March 2013, we entered into a ten year real estate lease contract (the "Real Estate Lease") with a commencement date of April 1, 2013, as part of the expansion of our equipment yard. The assets and liabilities under this contract are equally allocated between our cementing and coiled tubing segments. In addition to the contractual lease period, the contract includes an optional renewal of up to ten years, and in management's judgment the exercise of the renewal option is not reasonably assured. The contract does not include a residual value guarantee, covenants or financial restrictions. Further, the Real Estate Lease does not contain variability in payments resulting from either an index change or rate change. Effective January 1, 2019, the remaining lease term in our present value estimate of the minimum future lease payments was four years.

In January 2019, we entered into a four year real estate lease contract with Pioneer Natural Resources USA, Inc. (the "Crew Camp Lease") with a commencement date of January 1, 2019 for purposes of providing housing to company personnel. The contract does not include a residual value guarantee, covenants or financial restrictions. Further, the Crew Camp Lease does not contain variability in payments resulting from either an index change or rate change. The lease term used in our estimate of the present value of the minimum future lease payments for the purpose of determining our right-of-use asset and lease obligation was four years. The right-of-use asset and lease liability outstanding under the Crew Camp Lease as of March 31, 2019 is $0.5 million and $0.5 million, respectively. The total operating lease cost recorded during three months ended March 31, 2019, in connection with the Crew Camp lease was $0.04 million.

Consistent with the requirements of the new lease standard, ASC 842, we have determined the Real Estate Lease and Crew Camp Lease to be operating leases. Our assumptions resulted from the existence of the right to control the use of the assets throughout the lease term. We did not account for the land separately from the building of the real estate lease because we concluded that the accounting effect will be insignificant. As of March 31, 2019, the weighted average discount rate and remaining lease term was 6.1% and 3.9 years, respectively.

As of March 31, 2019, our total operating lease right-of-use asset cost was $1.8 million, and accumulated amortization was $0.1 million. For the three months ended March 31, 2019, we recorded operating lease cost of $0.1 million in our statement of operations. During the three months ended March 31, 2018, our operating lease expense, under legacy GAAP, ASC 840, was $0.4 million.

As part of our expansion of maintenance facilities for our pressure pumping equipment, we entered into a ten year land lease contract (the "Ground Lease") with an exclusive option to purchase the land exercisable beginning one year from the commencement date of October 1, 2018 through the end of the contractual lease term. The Ground Lease does not include any residual value guarantee, covenants or financial restrictions. Further, the Ground Lease does not contain variability in payments resulting from either an index change or rate change. The remaining lease term used in our estimate of the present value of the minimum future lease payments for the purpose of determining our right-of-use asset and lease obligation was 0.6 years, assuming we will exercise our option to purchase the land immediately after the option becomes exercisable.

Consistent with the requirements of the new lease standard, ASC 842, we have determined the Ground Lease to be a finance lease. Our assumptions resulted from the existence of the right to control the use of the land for a period of time and the option to purchase the land, which we are reasonable certain of exercising after one year from the commencement date. As of March 31, 2019, the weighted average discount rate and remaining lease term was 4.3% and 0.6 years, respectively .

As of March 31, 2019, our net finance lease right-of-use asset included as part of property and equipment in our consolidated balance sheet consists of a cost of $3.1 million and accumulated amortization of $0. For the three months ended March 31, 2019, no amortization was recorded on the land under the finance lease and the interest on our finance lease for the three months ended March 31, 2019 was $0.03 million. No amortization was recorded in the period for our finance lease right-of-use asset because it is comprised of land only.

The total cash paid for amounts included in the measurement of our operating and finance lease liabilities during the three months ended March 31, 2019 was $0.1 million and $0.1 million, respectively. The non-cash lease obligation we recorded effective January 1, 2019, upon adopting the new lease standard, was $2.0 million and $3.1 million for operating and finance leases, respectively. There were no non-cash changes to our lease liabilities during the three months ended March 31, 2019.

We elected the practical expedient, consistent with ASC 842, to exclude leases with an initial term of twelve months or less ("short-term leases") from our balance sheet and continue to record short-term leases as a period expense. For the three months ended March 31, 2019, our short-term lease expense was $0.3 million. At March 31, 2019, the total remaining lease commitments for all of our short-term lease was $0.03 million.

This Quarterly Report on Form 10-Q contains forward-looking statements that are intended to be covered by the safe harbor provided by the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact contained in this Quarterly Report on Form 10-Q are forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are predictive in nature, refer to future events or conditions, and generally not historical facts. Words such as "may," "could," "plan," "project," "budget," "predict," "pursue," "target," "seek," "objective," "believe," "expect," "anticipate," "intend," "estimate," "will," "should" and similar expressions are intended to identify forward-looking statements. These statements include, but are not limited to statements about our business strategy, industry, future profitability and future capital expenditures. Such statements are subject to risks and uncertainties, many of which are difficult to predict and generally beyond our control, that could cause actual results to differ materially from those implied or projected by the forward-looking statements. Factors that could cause our actual results to differ materially from those contemplated by such forward-looking statements include:

Readers are cautioned not to place undue reliance on our forward-looking statements. We do not undertake to update or revise any forward-looking statements, except as required by applicable securities laws. Investors are also advised to carefully review and consider the various risks and other disclosures discussed in our SEC reports, including the risk factors described in our Form 10-K.

We are a growth-oriented, Midland, Texas-based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated long-standing customer relationships with some of the region's most active and well-capitalized E&P companies. The Permian Basin is widely regarded as the most prolific oil-producing area in the United States, and we believe we are currently one of the largest providers of hydraulic fracturing services in the region by hydraulic horsepower ("HHP").

On December 31, 2018, we consummated the purchase of eight hydraulic fracturing fleets with a total of 510,000 HHP, four coiled tubing units and a maintenance yard from Pioneer Natural Resources USA, Inc. and Pioneer Natural Resources Pumping Services, LLC (the "Pioneer Pressure Pumping Acquisition"). Through the acquisition, we expanded our existing presence in the Permian Basin and increased our pressure pumping capacity by 56%, to an aggregate capacity of 1,415,000 HHP at March 31, 2019. During the three months ended March 31, 2019, our average active fleet count was approximately 27 fleets. In addition, we have made deposits of $18.4 million, or approximately 30% of the fleets' costs, to acquire two DuraStim hydraulic fracturing fleets which are expected to be delivered and put into service in the fourth quarter of 2019. Our fleet has been designed to handle the highest intensity and most complex hydraulic fracturing jobs in the region.

Through our pressure pumping segment (which also includes our cementing operations), we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our modern hydraulic fracturing fleet has been designed to handle Permian Basin specific operating conditions and the region's increasingly high-intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. The majority of our fleet has been delivered in recent years, and we fully maintained our equipment through the recent industry downturn to ensure optimal performance and reliability.

In addition to our core pressure pumping segment operations, we also offer a suite of complementary well completion and production services, including coiled tubing, flowback and drilling. We believe these complementary services create operational efficiencies for our customers and allow us to capture a greater portion of their capital spending across the lifecycle of a well. Additionally, we believe that these complementary services should benefit from a continued industry recovery and that we are well positioned to continue expanding these offerings in response to our customers' service needs and spending levels.

The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control. Declines and sustained weakness in crude oil prices began in the fourth quarter of 2014 and continued into February 2016, when the closing crude oil price for West Texas Intermediate ("WTI") reached a low of approximately $26.19 per barrel. This decline in WTI oil prices caused our customers to reduce drilling and completion activity and curtail spending. These declines adversely affected the demand for our equipment and services and negatively impacted the prices we were able to charge our customers.

believe the Permian Basin, our primary area of operation, is the leading basin with the lowest break-even production cost in the United States, and accordingly, the number of active drilling rigs in the basin increased from a low of 137 rigs in May 2016 to 454 rigs in March 2019, according to Baker Hughes. In addition to increased activity levels in the Permian Basin, several evolving industry trends, including increasingly longer horizontal wellbore laterals, a greater number of fractured stages per lateral and increasing amounts of proppant employed per well, have significantly increased demand for our hydraulic fracturing and other completion services.

With the shift towards more intensive horizontal drilling in the Permian Basin, operators and service providers are placing significant focus on drilling and completion efficiencies, such as multi-well pads and zipper fracturing. Multi-well pads allow for the drilling of multiple wellbores from a single topside location, reducing average drilling time. Similarly, zipper fracturing allows for the alternating completion of hydraulic fracturing stages in adjacent wells, increasing the number of stages that can be performed in a given time period. These advancements have resulted in a reduction in the number of days typically required to drill and complete a well and increased the total number of wells that can be drilled per rig, which, in turn, drives incremental demand for hydraulic fracturing services. In addition, there has been a recent shift to regional sand in the Permian Basin, which we believe will increase availability, shorten the supply chain from the mine to the well and improve operational efficiency by reducing downtime.

Rising producer activity levels, increasing basin service intensity and continued drilling and completion efficiencies have combined to drive utilization and pricing. We have differentiated our services to E&P companies by increasing operational efficiencies and helping our customers lower their well costs. Our performance at the well site has resulted in strong demand for our services in a very competitive market. Moreover, we believe the other complementary services we provide are well-positioned to similarly benefit from a continued industry recovery.

Our competitors include many large and small oilfield services companies, including RPC, Inc., Halliburton, C&J Energy Services, Patterson-UTI Energy Inc., Keane Group, Inc., Liberty Oilfield Services, Superior Energy Services, Schlumberger, FTS International and a number of private companies. Although we believe price is a key factor in E&P companies' criteria in choosing a service provider, we believe that other important factors include operational efficiency, technical expertise, service and equipment quality, and health and safety standards. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our deep local roots, operational expertise, the capability of our modern fleet to handle the most complex Permian Basin well completions, and commitment to safety and reliability.

Our substantial market presence in the Permian Basin positions us well to capitalize on increasing drilling and completion activity in the region. Historically, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have primarily operated. However, with increasing levels of Delaware Basin activity, we have recently expanded our presence in the Delaware Basin in response to demand from our customers. Given our entrenched relationships with a variety of Delaware Basin operators, we believe that we are uniquely positioned to capture large addressable growth opportunity as the basin develops. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.

We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our net income (loss), before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock based compensation, and (iii) other unusual or nonrecurring expenses, such as impairment charges and costs related to our initial public offering. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.

Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income)/expenses and items outside the control of our management team (such as income tax rates). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income/(loss), operating income/(loss), cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ("non-GAAP"), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring expenses (income) and items outside the control of the Company. Net income is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA or Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.



	Three Months Ended March 31, 2019
($ in thousands)	Pressure Pumping		All Other			Total
Net income (loss)	$	98,094	$	(28,289	)	$	69,805
Depreciation and amortization	31,783		1,334			33,117
Interest expense	—		1,903			1,903
Income tax expense	—		21,892			21,892
Loss on disposal of assets	19,006		222			19,228
Stock-based compensation	—		1,829			1,829
Other expense	—		187			187
Deferred IPO bonus and retention expense	2,157		157			2,314
Adjusted EBITDA	$	151,040	$	(765	)	$	150,275

	Three Months Ended March 31, 2018
($ in thousands)	Pressure Pumping		All Other			Total
Net income (loss)	$	52,934	$	(16,226	)	$	36,708
Depreciation and amortization	17,763		1,173			18,936
Interest expense	—		1,261			1,261
Income tax expense	—		10,353			10,353
Loss (gain) on disposal of assets	7,828		(163		)	7,665
Stock-based compensation	—		758			758
Other expense	—		230			230
Other general and administrative expense⁽¹⁾	—		1			1
Deferred IPO bonus expense	538		294			832
Adjusted EBITDA	$	79,063	$	(2,319	)	$	76,744

We conduct our business through five operating segments: hydraulic fracturing (inclusive of acidizing), cementing, coil tubing, flowback, and drilling. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment—pressure pumping. All other operating segments and corporate administrative expenses are included in the ‘‘all other’’ category.



(in thousands, except for percentages)	Three Months Ended March 31,						Change
	2019			2018			Variance			%
Revenue	$	546,179		$	385,219		$	160,960		41.8	%
Cost of services ⁽¹⁾	381,523			298,122			83,401			28.0	%
General and administrative expense ⁽²⁾	18,524			11,944			6,580			55.1	%
Depreciation and amortization	33,117			18,936			14,181			74.9	%
Loss on disposal of assets	19,228			7,665			11,563			150.9	%
Interest expense	1,903			1,261			642			50.9	%
Other expense	187			230			(43		)	(18.7	)%
Income tax expense	21,892			10,353			11,539			111.5	%
Net income	$	69,805		$	36,708		$	33,097		90.2	%

Adjusted EBITDA ⁽³⁾	$	150,275		$	76,744		$	73,531		95.8	%
Adjusted EBITDA Margin ⁽³⁾	27.5		%	19.9		%	7.6		%	38.2	%

Pressure pumping segment results of operations:
Revenue	$	532,064		$	375,045		$	157,019		41.9	%
Cost of services	$	371,105		$	290,470		$	80,635		27.8	%
Adjusted EBITDA	$	151,040		$	79,063		$	71,977		91.0	%
Adjusted EBITDA Margin ⁽⁴⁾	28.4		%	21.1		%	7.3		%	34.6	%

(1) Exclusive of depreciation and amortization.

(2) Inclusive of stock-based compensation.

(3) For definitions of the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA to our most directly comparable financial measures calculated in accordance with GAAP, please read "How We Evaluate Our Operations".

(4) The non-GAAP financial measure of Adjusted EBITDA margin for the pressure pumping segment is calculated by taking Adjusted EBITDA for the pressure pumping segment as a percentage of our revenue for the pressure pumping segment.

Revenues. Revenues increased 41.8%, or $161.0 million, to $546.2 million for the three months ended March 31, 2019, as compared to $385.2 million for the three months ended March 31, 2018. The increase was primarily attributable to the increase in fleet size from 17.4 to 27 active fleets, demand for our services and customer activity, resulting in an increase in our customer base, during the three months ended March 31, 2019. Our pressure pumping segment revenues increased 41.9%, or $157.0 million, for the three months ended March 31, 2019, as compared to the three months ended March 31, 2018. Revenues from services other than pressure pumping increased 38.7%, or $3.9 million, to $14.1 million for the three months ended March 31, 2019 as compared $10.2 million for the three months ended March 31, 2018. The increase in revenues from services other than pressure pumping was primarily attributable to the increase in customer demand for our coil tubing services in the three months ended March 31, 2019.

Cost of Services. Cost of services increased 28.0%, or $83.4 million, to $381.5 million for the three months ended March 31, 2019, as compared to $298.1 million during the three months ended March 31, 2018. Cost of services in our pressure pumping segment increased $80.6 million for the three months ended March 31, 2019, as compared to the three months ended March 31, 2018. These increases were primarily attributable to our increased fleet size and higher activity levels, resulting in an increase in employee headcount. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 69.7% for the three months ended March 31, 2019, as compared to 77.4% for the three months ended March 31, 2018. The decrease in cost of services as a percentage of revenue for our pressure pumping segment resulted from a favorable change in our cost structure driven by our internal cost control measures and a decrease in the cost of certain consumables, which resulted in significantly higher realized Adjusted EBITDA margins during the three months ended March 31, 2019.

General and Administrative Expenses. General and administrative expenses increased 55.1%, or $6.6 million, to $18.5 million for the three months ended March 31, 2019, as compared to $11.9 million for the three months ended March 31, 2018. The net increase was primarily attributable to the increases in stock compensation expense of $1.1 million, retention bonus expense of $1.8 million associated with personnel who joined us as part of the Pioneer Pressure Pumping Acquisition, insurance expense of $1.7 million, payroll expense of $1.0 million, and net increase of $1.0 million in other remaining general and administrative expenses.

Depreciation and Amortization. Depreciation and amortization increased 74.9%, or $14.2 million, to $33.1 million for the three months ended March 31, 2019, as compared to $18.9 million for the three months ended March 31, 2018. The increase was primarily attributable to the increase in our fixed asset base as of March 31, 2019, resulting primarily from an increase in our pressure pumping fleet capacity by 73.6% to 1,415,000 HHP in 2019.

Loss on Disposal of Assets. Loss on the disposal of assets increased 150.9%, or $11.6 million, to $19.2 million for the three months ended March 31, 2019, as compared to $7.7 million for the three months ended March 31, 2018. The increase is attributable to the increase in fleet size, greater service intensity of jobs completed, and higher activity levels on certain of our equipment.

Interest Expense. Interest expense increased 50.9%, or $0.6 million, to $1.9 million for the three months ended March 31, 2019, as compared to $1.3 million for the three months ended March 31, 2018. The increase in interest expense was primarily attributable to an increase in our average debt balance during the three months ended March 31, 2019 compared to the three months ended March 31, 2018.

Income Tax Expense. Total income tax expense was $21.9 million resulting in an effective tax rate of 23.9% for the three months ended March 31, 2019 as compared to an income tax benefit of $10.4 million and an effective tax rate of 22.0% for the three months ended March 31, 2018. The increase in income tax expense during the three months ended March 31, 2019 is primarily attributable to the increase in book income during the three months ended March 31, 2019 compared to the March 31, 2018.

On March 22, 2017, we entered into a new revolving credit facility with a $150.0 million borrowing capacity ("ABL Credit Facility"). Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with no LIBOR floor. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company. The ABL Credit Facility has a borrowing base of 85% of eligible accounts receivable less customary reserves. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. In addition, the ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio of 1.0x when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $12.0 million. The ABL has a commitment fee of 0.375%, which reduces to 0.25% if utilization is greater than 50% of the borrowing base.

On February 22, 2018, we entered into an amendment with our lenders to increase the capacity of the ABL Credit Facility. The amendment increased total capacity under the facility from $150.0 million to $200.0 million, and modified the Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $15.0 million.

On December 19, 2018, we entered into a second amendment with our lenders to further increase the capacity of the ABL Credit Facility. The second amendment increased total capacity under the facility from $200.0 million to $300.0 million and extended the maturity date of the ABL Credit Facility from March 22, 2022 until December 19, 2023. The second amendment further modified the Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $22.5 million.

As of March 31, 2019, our cash and cash equivalents were $79.5 million, as compared to $132.7 million at December 31, 2018. Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our primary uses of cash will be to fund our operations, support growth opportunities and satisfy debt payments.

There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business or meet our future obligations.

Net cash provided by operating activities was $36.1 million for the three months ended March 31, 2019, compared to net cash provided by operating activities of $54.6 million for the three months ended March 31, 2018. The net decrease of $18.5 million was primarily due to the timing of our receivables and payments. However, we recorded a significant increase in our operating profits as our Adjusted EBITDA increased to $150.3 million during the three months ended March 31, 2019 from $76.7 million during the three months ended March 31, 2018. The increase in our operating profitability was primarily a result of the increase in our fleet size and expanding customers' activity levels.

Net cash used in investing activities increased to $177.9 million for the three months ended March 31, 2019, from $74.8 million for the three months ended March 31, 2018. The increase was primarily attributable to the cash payment of approximately $110.0 million for 510,000 HHP (or 8 fleets), 4 coiled tubing units and maintenance yard acquired in the Pioneer Pressure Pumping Acquisition. In addition, in the three months ended March 31, 2019, we made deposits of $18.4 million for two new-build DuraStim hydraulic fracturing fleets which is expected to be delivered before the end of 2019 and $1.5 million for other ancillary equipment.

Net cash provided by financing activities was $88.6 million for the three months ended March 31, 2019, and $42.7 million for the three months ended March 31, 2018. The net increase in cash provided by financing activities during the three months ended March 31, 2019 was primarily driven by the increase in borrowings under our ABL Credit Facility, compared to three months ended March 31, 2018. Our net cash provided from financing activities during the three months ended March 31, 2019, was primarily driven by additional borrowings under our ABL Credit Facility of $90.0 million, and offset by our use of cash for repayment of insurance financing of $1.9 million. Our net cash provided from financing activities during the three months ended March 31, 2018, was primarily driven by our borrowings of $46.7 million, and offset by our use of cash for repayment of borrowings of $2.3 million, insurance financing of $1.4 million and debt issuance cost of $0.4 million.

There have been no material changes during the three months ended March 31, 2019 to the methodology applied by our management for critical accounting policies previously disclosed in our Form 10-K. Please refer to Part II, Item 7, "Management Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Form 10-K for a discussion of our critical accounting policies and estimates.

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for West Texas Intermediate ("WTI") oil and natural gas and expectations about future prices. For many years, WTI oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. WTI oil prices declined significantly close to the end of the second half of 2014. The closing price of WTI oil, which was as high as $105.68 per barrel during the third quarter of 2014, averaged $48.69 during 2015 and reached a twelve-year low of $26.19 in February 2016. However, beginning in the third quarter of 2016, WTI oil prices started recovering, and reaching an average of $58.15 per barrel in March 2019. As a result of the recent recovery in WTI oil prices, our industry has experienced a significant increase in both drilling and pressure pumping activity levels. Looking forward, we expect WTI oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Higher WTI oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices.

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2019.

From time to time, we may be subject to various legal proceedings and claims incidental to or arising in the ordinary course of our business. We are not currently party to any legal proceedings that we believe would have a material adverse effect on our financial position or results of operations, and we are not aware of any material legal proceedings contemplated by governmental authorities.



Delaware		26-3685382
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.001 per share	PUMP	New York Stock Exchange



		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	1
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2019 and 2018	2
	Condensed Consolidated Statement of Shareholders' Equity for the three months ended March 31, 2019 and 2018	3
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018	4
	Notes to Condensed Consolidated Financial Statements	5
	Cautionary Note Regarding Forward-Looking Statements	17
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	Results of Operations	21
	Liquidity and Capital Resources	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	25
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.	Defaults Upon Senior Securities	26
Item 4.	Mine Safety Disclosures	26
Item 5.	Other Information	26
Item 6.	Exhibits	27
	Signatures	28



	Number of Shares		Weighted Average Exercise Price
Outstanding at January 1, 2019	4,557,186		$	5.14
Granted	—		$	—
Exercised	(103,972	)	$	5.31
Forfeited	(3,045	)	$	14.00
Expired	—		$	—
Canceled	—		$	—
Outstanding at March 31, 2019	4,450,169		$	5.13
Exercisable at March 31, 2019	4,075,377		$	4.32



($ in thousands)
2019	$	892
2020	721
2021	721
2022	721
2023 and thereafter	2,258
Total	$	5,313



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



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



	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2019	473,505		$	16.52
Granted	318,332		$	21.54
Vested	—		$	—
Forfeited	(1,538	)	$	13.25
Expired	—		$	—
Canceled	—		$	—
Outstanding at March 31, 2019	790,299		$	18.55



	Leases
($ in thousands)	Operating			Finance
2019	$	389		$	3,117
2020	526			—
2021	537			—
2022	549			—
2023	98			—
Total Undiscounted future lease payments	2,099			3,117
Less: amount representing interest	(242		)	(75		)
Present value of future lease payments (lease obligation)	$	1,857		$	3,042


•	the level of production and resulting market prices for crude oil, natural gas and other hydrocarbons;


•	changes in the long-term supply of, and demand for, oil and natural gas;


•	actions taken by our customers, suppliers, competitors and third-party operators;


•	large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;


•	the price and availability of debt and equity financing (including changes in interest rates);


•	our ability to complete growth projects on time and on budget;


•	technological changes;


•	operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	the effects of existing and future laws and governmental regulations (or the interpretation thereof);


•	our ability to successfully execute on our plans and objectives.



3.1		Certificate of Incorporation of ProPetro Holding Corp., as amended March 16, 2017 (incorporated by reference to Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
3.2		Bylaws of ProPetro Holding Corp. (incorporated by reference to Exhibit 3.3 to the Company’s Registration Statement on Form S-1, dated March 10, 2017 (Registration No. 333-215940)).
31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350 as adopted by Section 906 of the Sarbanes-Oxley Act of 2002.
* 101.INS		XBRL Instance 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



+	Indicates management contracts or compensatory plans or arrangements.



SIGNATURES

Date:	May 8, 2019	By:	/s/ Dale Redman
			Dale Redman
			Chief Executive Officer and Director
			(Principal Executive Officer)

		By:	/s/ Jeffrey Smith
			Jeffrey Smith
			Chief Financial Officer
			(Principal Financial Officer)

		By:	/s/ Ian Denholm
			Ian Denholm
			Chief Accounting Officer
			(Principal Accounting Officer)