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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 has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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.



	September 30, 2017			December 31, 2016

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	51,008		$	133,596
Accounts receivable - net of allowance for doubtful accounts of $335 and $552, respectively	160,047			115,179
Inventories	9,148			4,713
Prepaid expenses	5,543			4,608
Other current assets	975			6,684
Total current assets	226,721			264,780
PROPERTY AND EQUIPMENT - Net of accumulated depreciation	399,268			263,862
OTHER NONCURRENT ASSETS:
Goodwill	9,425			9,425
Intangible assets - net of amortization	373			589
Deferred revenue rebate - net of amortization	1,077			2,462
Other noncurrent assets	1,727			304
Total other noncurrent assets	12,602			12,780
TOTAL ASSETS	$	638,591		$	541,422
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	181,660		$	129,093
Accrued liabilities	11,074			13,619
Current portion of long-term debt	7,441			16,920
Accrued interest payable	86			109
Total current liabilities	200,261			159,741
DEFERRED INCOME TAXES	1,315			1,148
LONG-TERM DEBT	34,476			159,407
OTHER LONG-TERM LIABILITIES	124			117
Total liabilities	236,176			320,413
COMMITMENTS AND CONTINGENCIES (Note 9)
SHAREHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 30,000,000 shares authorized, 0 and 16,999,990 shares issued, respectively	—			17
Preferred stock, additional paid-in capital	—			162,494
Common stock, $0.001 par value, 200,000,000 shares authorized, 83,039,854 and 52,627,652 shares issued, respectively	83			53
Additional paid-in capital	606,707			265,355
Accumulated deficit	(204,375		)	(206,910		)
Total shareholders’ equity	402,415			221,009
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	638,591		$	541,422



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
REVENUE - Service revenue	$	282,730		$	116,904		$	668,153		$	272,999
COSTS AND EXPENSES
Cost of services (exclusive of depreciation and amortization)	225,433			110,223			551,775			255,362
General and administrative (inclusive of stock-based compensation)	11,106			5,856			38,881			17,197
Depreciation and amortization	14,745			10,790			38,602			32,669
Loss on disposal of assets	8,742			5,923			28,971			12,859
Total costs and expenses	260,026			132,792			658,229			318,087
OPERATING INCOME (LOSS)	22,704			(15,888		)	9,924			(45,088		)
OTHER INCOME (EXPENSE):
Interest expense	(644		)	(4,550		)	(6,469		)	(15,942		)
Gain on extinguishment of debt	—			—			—			6,975
Other expense	(191		)	(106		)	(792		)	(419		)
Total other income (expense)	(835		)	(4,656		)	(7,261		)	(9,386		)
INCOME (LOSS) BEFORE INCOME TAXES	21,869			(20,544		)	2,663			(54,474		)
INCOME TAX (EXPENSE)/BENEFIT	96			6,946			(128		)	18,644
NET INCOME (LOSS)	$	21,965		$	(13,598	)	$	2,535		$	(35,830	)
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	0.26		$	(0.26	)	$	0.03		$	(0.84	)
Diluted	$	0.25		$	(0.26	)	$	0.03		$	(0.84	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	83,040			52,975			74,124			42,526
Diluted	86,264			52,975			77,118			42,526



	Preferred Stock								Common Stock
	Shares		Amount			Preferred Additional Paid-In Capital			Shares	Amount		Additional Paid-In Capital		Accumulated Deficit			Total
BALANCE - January 1, 2017	17,000		$	17		$	162,494		52,628	$	53	$	265,355	$	(206,910	)	$	221,009
Stock-based compensation cost	—		—			—			—	—		8,730		—			8,730
Initial Public Offering net of costs	—		—			—			13,250	13		170,128		—			170,141
Conversion of preferred stock to common at Initial Public Offering	(17,000	)	(17		)	(162,494		)	17,000	17		162,494		—			—
Exercise of stock options—net	—		—			—			162	—		—		—			—
Net income	—		—			—			—	—		—		2,535			2,535
BALANCE - September 30, 2017	—		$	—		$	—		83,040	$	83	$	606,707	$	(204,375	)	$	402,415



	Nine Months Ended September 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	2,535		$	(35,830	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	38,602			32,669
Gain on extinguishment	—			(6,975		)
Deferred income tax expense (benefit)	166			(18,644		)
Amortization of deferred revenue rebate	1,385			1,385
Amortization of deferred debt issuance costs	3,322			1,806
Stock-based compensation	8,730			1,130
Loss on disposal of assets	28,971			12,859
Gain on interest rate swap	(226		)	(54		)
Changes in operating assets and liabilities:
Accounts receivable	(44,868		)	3,255
Other current assets	3,271			(4		)
Inventories	(4,435		)	1,579
Prepaid expenses	(910		)	2,845
Accounts payable	41,564			(2,294		)
Accrued liabilities	589			620
Accrued interest	(23		)	1
Net cash provided by (used in) operating activities	78,673			(5,652		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(193,820		)	(18,631		)
Proceeds from sale of assets	4,237			475
Net cash used in investing activities	(189,583		)	(18,156		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	27,112			—
Repayments of borrowings	(164,638		)	(42,166		)
Repayments of insurance financing	(2,900		)	(2,833		)
Debt extinguishment cost	—			(525		)
Payment of debt issuance costs	(1,653		)	(115		)
Equity capitalization	—			40,425
Proceeds from IPO	185,500			—
Payment of IPO costs	(15,099		)	—
Net cash provided by (used in) financing activities	28,322			(5,214		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(82,588		)	(29,022		)
CASH AND CASH EQUIVALENTS - Beginning of period	133,596			34,310
CASH AND CASH EQUIVALENTS - End of period	$	51,008		$	5,288

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, 2016 included in the final prospectus of the Company filed with the SEC pursuant to rule 424(b) under the Securities Act of 1933 on March 20, 2017 ("Prospectus").

On March 22, 2017, we consummated our initial public offering ("IPO"), in which 25,000,000 shares of our common stock, par value $0.001 per share, were sold at a public offering price of $14.00 per share, with 13,250,000 shares issued and sold by the Company and 11,750,000 shares sold by existing stockholders. We received net proceeds of approximately $170.1 million after deducting $10.9 million of underwriting discounts and commissions, and $4.5 million of other offering expenses. Upon closing of the IPO, we used the proceeds (i) to repay $71.8 million in outstanding borrowings under our Term Loan (as defined in Note 4), (ii) to fund the purchase of additional hydraulic fracturing fleets and ancillary equipment, and (iii) for general corporate purposes.

In connection with the IPO, the Company executed a stock split, such that each holder of common stock of the Company received 1.45 shares of common stock for every one share of previous common stock. Accordingly, any information related to, or dependent upon, the share or option counts in our comparative 2016 condensed consolidated financial statements (Unaudited) and Note 6, Net Income (Loss) per Share, Note 7, Stock-Based Compensation, and Note 10, Equity Capitalization, have been updated to reflect the effect of the stock split.

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU No. 2014-09 requires entities to recognize revenue to depict transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 requires entities to disclose both qualitative and quantitative information that enables users of the consolidated financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including disclosure of significant judgments affecting the recognition of revenue. ASU No. 2014-09 was originally effective for annual periods beginning after December 15, 2016, using either the retrospective or cumulative effect transition method. On August 12, 2015, the FASB issued ASU No. 2015-14, which defers the effective date of the revenue standard, ASU No. 2014-09, by one year for all entities and permits early adoption on a limited basis. We have completed our preliminary evaluation of ASU No. 2014-09, and the adoption of this guidance will not materially affect our revenue recognition. However, there will be additional disclosures on our consolidated financial statements relating to the adoption of this standard.

In July 2015, the FASB issued ASU No. 2015-11, Simplifying the Measurement of Inventory, which requires entities to measure most inventory "at the lower of cost and net realizable value," thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU No. 2015-11 does not apply to inventories that are measured by using either the last-in, first-out method or the retail inventory method. The amendments in ASU No. 2015-11 are effective for fiscal years beginning after December 15, 2016. The ASU became effective for us in 2017 and the adoption of this guidance did not materially affect our consolidated financial statements.

The new standard is effective for annual reporting periods beginning after December 15, 2018, including periods within that reporting period, using a modified retrospective approach. Early adoption is permitted. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU No. 2016-09, Compensation- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which modifies several aspects of the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new standard is effective for fiscal years and interim periods beginning after December 15, 2016, with early adoption permitted. The ASU became effective for us in 2017 and the adoption of this guidance did not materially affect our consolidated financial statements.

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; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This pronouncement 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.

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, and a derivative financial instrument. The estimated fair value of our financial instruments — cash and cash equivalents, accounts receivable and accounts payable at September 30, 2017 and December 31, 2016 approximates their carrying value as reflected in our condensed consolidated balance sheets due to their short-term nature. We use a derivative financial instrument, an interest rate swap, to manage interest rate risk. Our policies do not permit the use of derivative financial instruments for speculative purposes. We did not designate the interest rate swap as a hedge for accounting purposes. We record all derivatives as of the end of our reporting period in our condensed consolidated balance sheet at fair value, which is based on quoted market prices, a Level 1 input. We may be exposed to credit losses in the event of nonperformance by counterparties to the interest rate swap. The counterparty of the interest rate swap is a credible, large institution, and we do not believe there is significant or material credit risk upon settlement of the contract. The fair value of the interest rate swap liability at September 30, 2017 and December



			Estimated fair value measurements
	Balance		Quoted prices in active market (Level 1)		Significant other observable inputs (Level 2)		Significant other unobservable inputs (Level 3)		Total gains (losses)
($ in thousands)
September 30, 2017:
Property and equipment, net	$	—	$	—	$	—	$	—	$	—
Goodwill	$	—	$	—	$	—	$	—	$	—
December 31, 2016:
Property and equipment, net	$	8,700	$	—	$	8,700	$	—	$	(6,305	)
Goodwill	$	9,425	$	—	$	—	$	9,425	$	(1,177	)

No impairment of property and equipment was recorded during the nine months ended September 30, 2017 and 2016. During the fourth quarter of 2016, the depressed cash flows and continued decline in utilization of our Permian drilling assets were indicative of potential impairment, resulting in the Company comparing the carrying value of the Permian drilling assets with its estimated fair value. We determined that the carrying value of the Permian drilling assets was greater than its estimated fair value, and as such, an impairment expense was recorded in the fourth quarter of 2016. The non-cash asset impairment charges recorded in the fourth quarter of 2016 for Permian drilling was $6.3 million, which had a then net carrying value of $15.0 million prior to the impairment write-down.

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. There were no additions to, or disposal of, goodwill during the nine months ended September 30, 2017 and 2016. At December 31, 2016, we estimated the fair value of the surface drilling reporting unit to be $3.8 million and its carrying value was $4.2 million. As a result of the potential impairment due to the carrying value exceeding the estimated fair value, we then further determined the implied fair value of the $1.2 million goodwill for the surface drilling reporting unit to be $0. Accordingly, we recorded an impairment loss of $1.2 million during the fourth quarter of 2016.

On September 30, 2013, we entered into a term loan in the amount of $220 million ("Term Loan") with a $40 million revolving credit line ("Revolving Credit Facility"). Borrowings under the Term Loan and Revolving Credit Facility accrued interest at LIBOR plus 6.25%, subject to a 1% LIBOR floor, and were secured by a first priority lien and security interest in all assets of the Company. Proceeds from the Term Loan were used to pay off 100% of our debt outstanding, including accrued interest, at September 30, 2013, with excess proceeds from the Term Loan and the Revolving Credit Facility used to fund growth and working capital needs. The Term Loan and Revolving Credit Facility were scheduled to mature on September 30, 2019 and September 30, 2018, respectively, with quarterly and monthly payments of principal and interest, respectively.

Under the Term Loan and Revolving Credit Facility we were 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 reporting, insurance, collateral maintenance, change of control, transactions with affiliates, distributions, and limitations on additional indebtedness. In addition, the Term Loan and Revolving Credit Facility included a maximum leverage ratio of 3.5x EBITDA (earnings before interest, taxes, depreciation, and amortization) to total debt, which became effective March 31, 2014.

In 2015, given the then near-term economic uncertainty and volatility of commodity prices, we determined that we were likely to be out of compliance with the leverage ratio covenant under the Term Loan and Revolving Credit Facility at the March 31, 2016 test date. Accordingly, the Company and its equity sponsor, Energy Capital Partners ("ECP"), commenced negotiations with the lenders to amend the covenants and leverage ratio in the Term Loan and Revolving Credit Facility. The resulting amendment and waiver agreement was executed on June 8, 2016. Under the terms of the amendment, ECP infused $40 million of additional equity into the Company, $10 million of which was reserved for working capital, with up to $30 million available to repurchase debt. A minority shareholder also infused $0.425 million alongside ECP to prevent dilution. The amendment and waiver also suspended the leverage ratio test until June 30, 2017, and provided us with 30 days to deliver any past-due financial statements.

Gain on Extinguishment of Debt — in connection with the amendment to the Term Loan and Revolving Credit Facility, we initiated an auction process with the lenders to repurchase a portion of debt for a price of 80 cents, a 20% discount to par value. The auction settled on June 16, 2016 as the Company repurchased a total amount of $37.5 million of debt for $30 million plus $0.5 million in debt extinguishment auction costs, leading to a gain on extinguishment of debt of $7.0 million.

On January 13, 2017, we repaid $75 million of the outstanding balance under the Term Loan and repaid the remaining balance of $13.5 million under the Revolving Credit Facility using a portion of the proceeds from the private placement offering. On March 22, 2017, we retired the $71.8 million remaining balance of the Term Loan, along with accrued interest, using a portion of the proceeds from our IPO. Each of the Term Loan and Revolving Credit Facility were terminated in accordance with their terms upon the repayment of outstanding borrowings.

On March 22, 2017, we entered into a new revolving credit facility with a $150 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 tenor of 5 years and 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 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.

Total debt consisted of the following at September 30, 2017 and December 31, 2016, respectively:



($ in thousands)	2017		2016
ABL Credit Facility	$	25,000	$	—
6.25% "Term loan" due September 2019	—		146,750
Revolving Credit Facility	—		13,500
Equipment financing	16,917		19,193
Total debt	41,917		179,443
Less deferred loan costs, net of amortization	—		3,116
Subtotal	41,917		176,327
Less current portion of long-term debt	7,441		16,920
Total long-term debt, net of deferred loan costs	$	34,476	$	159,407

In accordance with Accounting Standards Codification (ASC) 280—Segment Reporting, the Company has one reportable segment (pressure pumping) comprised of the hydraulic fracturing, cementing, and acidizing 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.



	Three months ended September 30, 2017							Nine months ended September 30, 2017
($ in thousands)	Pressure Pumping		All Other			Total		Pressure Pumping		All Other			Total

Service revenue	$	271,924	$	10,806		$	282,730	$	639,355	$	28,798		$	668,153
Adjusted EBITDA	$	50,013	$	(2,245	)	$	47,768	$	98,296	$	(3,641	)	$	94,655
Depreciation and amortization	$	13,637	$	1,108		$	14,745	$	35,228	$	3,374		$	38,602
Goodwill	$	9,425	$	—		$	9,425	$	9,425	$	—		$	9,425
Capital expenditures	$	61,752	$	765		$	62,517	$	203,097	$	3,231		$	206,328
Total assets	$	604,769	$	33,822		$	638,591	$	604,769	$	33,822		$	638,591

	Three months ended September 30, 2016							Nine months ended September 30, 2016
	Pressure Pumping		All Other			Total		Pressure Pumping		All Other			Total
Service revenue	$	109,697	$	7,207		$	116,904	$	251,410	$	21,589		$	272,999
Adjusted EBITDA	$	2,951	$	(1,616	)	$	1,335	$	6,500	$	(4,930	)	$	1,570
Depreciation and amortization	$	9,274	$	1,516		$	10,790	$	27,905	$	4,764		$	32,669
Goodwill	$	9,425	$	1,177		$	10,602	$	9,425	$	1,177		$	10,602
Capital expenditures	$	11,641	$	202		$	11,843	$	21,582	$	312		$	21,894
Total assets at December 31, 2016	$	501,906	$	39,516		$	541,422	$	501,906	$	39,516		$	541,422



	Three months ended September 30, 2017									Nine months ended September 30, 2017
($ in thousands)	Pressure Pumping			All Other			Total			Pressure Pumping			All Other			Total
Net income (loss)	$	28,372		$	(6,407	)	$	21,965		$	30,087		$	(27,552	)	$	2,535
Depreciation and amortization	13,637			1,108			14,745			35,228			3,374			38,602
Interest expense	—			644			644			—			6,469			6,469
Income tax (benefit) expense	—			(96		)	(96		)	—			128			128
Loss on disposal of assets	7,552			1,190			8,742			27,943			1,028			28,971
Stock-based compensation	—			751			751			—			8,730			8,730
Other expense	—			191			191			—			792			792
Other general and administrative expense ⁽¹⁾	—			149			149			—			722			722
Deferred IPO bonus expense	452			225			677			5,038			2,668			7,706
Adjusted EBITDA	$	50,013		$	(2,245	)	$	47,768		$	98,296		$	(3,641	)	$	94,655

	Three months ended September 30, 2016									Nine months ended September 30, 2016
($ in thousands)	Pressure Pumping			All Other			Total			Pressure Pumping			All Other			Total
Net loss	$	(12,265	)	$	(1,333	)	$	(13,598	)	$	(34,815	)	$	(1,015	)	$	(35,830	)
Depreciation and amortization	9,274			1,516			10,790			27,905			4,764			32,669
Interest expense	—			4,550			4,550			—			15,942			15,942
Income tax benefit	—			(6,946		)	(6,946		)	—			(18,644		)	(18,644		)
(Gain)/loss on disposal of assets	5,942			(19		)	5,923			13,410			(551		)	12,859
Stock-based compensation	—			510			510			—			1,130			1,130
Gain on extinguishment of debt	—			—			—			—			(6,975		)	(6,975		)
Other expense	—			106			106			—			419			419
Adjusted EBITDA	$	2,951		$	(1,616	)	$	1,335		$	6,500		$	(4,930	)	$	1,570

Net income (loss) per share is determined by dividing the net income (loss) relevant to the common stockholders by the weighted average number of shares outstanding during the period. Diluted net income (loss) per common share uses the same net income (loss) divided by the number of shares that would be outstanding assuming dilutive options and stock are converted. The table below shows the calculations for the three and nine months ended September 30, 2017 and 2016.



	Three Months Ended September 30,					Nine Months Ended September 30,
(In thousands, except for per share data)	2017		2016			2017		2016
Numerator (both basic and diluted)
Net income (loss) relevant to common stockholders	$	21,965	$	(13,598	)	$	2,535	$	(35,830	)
Denominator
Denominator for basic income (loss) per share	83,040		52,975			74,124		42,526
Dilutive effect of stock options	2,808		—			2,822		—
Dilutive effect of performance stock units	37		—			—		—
Dilutive effect of non-vested restricted stock	379		—			172		—
Denominator for diluted income (loss) per share	86,264		52,975			77,118		42,526
Basic income (loss) per common share	$	0.26	$	(0.26	)	$	0.03	$	(0.84	)
Diluted income (loss) per common share	$	0.25	$	(0.26	)	$	0.03	$	(0.84	)

Effective March 4, 2013, we adopted the ProPetro Stock Option Plan pursuant to which our Board of Directors may grant stock options or other stock-based awards to key employees, consultants, and directors. The Plan, as amended, is authorized to grant up to 4,645,884 shares of common stock to be issued upon exercise of the options. The Company’s share price used to estimate the fair value of the option at the grant date was based on a combination of income and market approaches, which are highly complex and sensitive. The income approach involves the use of a discounted cash flow method, with 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 of the Company’s stock. The expected term used to calculate the fair value of all options considers the vesting date and the grant’s expiration date. The expected volatility was estimated by considering comparable public companies, and the risk free rate is based on the U.S treasury yield curve as of the grant date. The dividend assumption is based on historical experience. After becoming a public company, the market price was used to determine the market value of our common stock. Prior to 2015, we had granted a total of 3,499,228 options with an exercise price of $3.96 per option, and all options expire 10 years from the date of grant.

On June 14, 2013, we granted 2,799,408 stock option awards to certain key employees and directors that shall vest and become exercisable based upon the achievement of a service requirement. The options vest in 25% increments for each year of continuous service and an option becomes fully vested upon the optionee’s completion of the fourth year of service. The contractual term for the options awarded is 10 years. For the nine months ended September 30, 2017 and 2016, we recognized $0.7 million and $0.9 million, respectively, in compensation expense related to these stock options. The fair value of each option award granted is estimated on the date of grant using the Black-Scholes option-pricing model. The fair value of the options was estimated at the date of grant using the following assumptions:

On December 1, 2013, we granted 699,820 stock option awards to certain key employees which were scheduled to vest in four substantially equal annual installments, subject to service and performance requirements and acceleration upon a change in control. As of September 30, 2016, the performance requirement was not considered to be probable of achievement for any of the outstanding option awards and 114,456 options were forfeited during the year ended December 31, 2016. Accordingly, we have not recognized any compensation expense related to these stock options as of September 30, 2016. Effective March 16, 2017, we terminated the options in connection with the IPO and approved a cash bonus totaling $5.1 million to the holders of the options.

On July 19, 2016, we granted 1,274,549 stock option awards to certain key employees and directors which are scheduled to vest in five substantially equal semi-annual installments commencing in December 2016, subject to a continuing services requirement. The contractual term for the options awarded is 10 years. For the nine months ended September 30, 2017, we recognized the remaining $1.8 million in stock compensation expense related to these stock options, as the Company fully accelerated vesting of the options in connection with the IPO, and for the nine months ended September 30, 2016, we recognized $0.2 million in stock compensation expense related to these stock options.

In March 2017, our shareholders approved the ProPetro 2017 Incentive Award Plan ("IAP") pursuant to which our Board of Directors may grant stock options, restricted stock units ("RSUs"), performance stock units ("PSUs"), or other stock-based awards to key employees, consultants, directors and employees. The IAP authorizes up to 5,800,000 shares of common stock to be issued under awards granted pursuant to the plan. On March 16, 2017, we granted 793,738 stock option awards to certain key employees and directors pursuant to the IAP which are scheduled to vest in four substantially equal annual installments, subject to a continuing service requirement. The contractual term for the options awarded is 10 years. For the nine months



	Number of Shares		Weighted Average Exercise Price		Weighted Average Grant-Date Fair Value
Outstanding at January 1, 2016	3,485,791		$	3.96	$	1.77
Granted	1,274,549		$	2.25	$	1.77
Exercised	—		$	—	$	—
Forfeited	(114,456	)	$	3.96	$	1.77
Expired	—		$	—	$	—
Canceled	—		$	—	$	—
Outstanding at December 31, 2016	4,645,884		$	3.49	$	1.77
Exercisable at December 31, 2016	2,354,466		$	3.77	$	1.77

Outstanding at January 1, 2017	4,645,884		$	3.49	$	1.77
Granted	793,738		$	14.00	$	3.35
Exercised	(226,194	)	$	3.96	$	1.77
Forfeited	(5,148	)	$	14.00	$	3.35
Expired	—		$	—	$	—
Canceled	(571,927	)	$	3.96	$	1.77
Outstanding at September 30, 2017	4,636,353		$	5.20	$	2.04
Exercisable at September 30, 2017	3,847,763		$	3.39	$	1.77

On September 30, 2013, our Board of Directors authorized and granted 372,335 restricted stock units (RSUs) to a key executive. Each RSU represents the right to receive one share of common stock of the Company at par value $0.001 per share. Under the terms of the award, the shares of common stock subject to the RSUs were to be paid to the grantee upon change in control, regardless of whether the grantee was affiliated with the Company on the settlement date. The fair value of the RSUs is measured as the price of the Company’s shares on the grant date, which was estimated to be $3.89. The share price used to estimate the fair value of the RSU at the grant date was based on a combination of income and market approaches, which are highly complex and sensitive. 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 of the Company’s stock. Effective March 22, 2017, the Board of Directors canceled these RSUs and issued 372,335 new RSUs to the grantee. These issued RSUs are effectively identical to the RSUs granted in 2013, provided, however, that the RSUs will now be payable in full on March 22, 2018. The fair value of the RSUs

On June 5, 2017, our Board of Directors granted 319,250 RSUs to employees, directors and executives pursuant to the 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 nine months ended September 30, 2017 and 2016, the recorded stock compensation expense for all RSUs was $5.8 million and $0, respectively.

Effective June 5, 2017, our Board of Directors authorized and granted performance stock unit awards to certain key employees under the IAP. The actual number of shares that may be issued under the performance stock unit awards 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 the date of our IPO through December 31, 2019. Compensation expense is recorded ratably over the corresponding requisite service period. The fair value of performance stock unit awards 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 nine months ended September 30, 2017 and 2016 the recorded stock compensation expense for the performance stock units was $0.2 million and $0, respectively.

The Company leases its corporate offices from a related party pursuant to a five-year lease agreement with a five-year extension option requiring a base rent of $0.07 million per year. The Company also leases five properties adjacent to the corporate office from related parties with annual base rents of $0.03 million, $0.03 million, $0.09 million, $0.09 million, and $0.18 million.

For the nine months ended September 30, 2017 and 2016, the Company paid approximately $0.21 million and $0.12 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. For the the nine months ended September 30, 2017 and 2016, the Company paid $0.14 million and $0.14 million, respectively.

On March 22, 2017, we consummated our IPO in which 25,000,000 shares of our common stock, par value $0.001 per share, were sold at a public offering price of $14.00 per share, with 13,250,000 shares issued and sold by the Company and 11,750,000 shares sold by existing stockholders. We received net proceeds of approximately $170.1 million after deducting $10.9 million of underwriting discounts and commissions, and $4.5 million of other offering expenses. At closing, we used the proceeds (i) to repay $71.8 million in outstanding borrowings under the term loan, (ii) to fund the purchase of additional hydraulic fracturing fleets and ancillary equipment, and (iii) for general corporate purposes. In connection with the IPO, all 16,999,990 shares of our outstanding Series A Preferred Stock converted to common stock on a 1:1 basis.

This document contains forward-looking statements that are intended to be covered by the safe harbor provided by the Private Securities Litigation Reform Act of 1995. 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," "may," "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:

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, or HHP, with a current aggregate deployed capacity of 690,000 HHP. Our fleet, which consists of 16 hydraulic fracturing fleets, has been designed to handle the highest intensity, most complex hydraulic fracturing jobs and has been 100% utilized since September 2016. During the third quarter ended September 30, 2017, we put three new hydraulic fracturing fleets into service. Subsequent to the end of this quarter, we also deployed one additional new hydraulic fracturing fleet in the fourth quarter of 2017, bringing our current total to 16, and aggregate capacity to 690,000 HHP. In addition, we have committed to acquire one new additional hydraulic fracturing fleet which is expected to be delivered before the end of the first quarter of 2018. This fleet will provide us with an incremental 45,000 HHP, bringing our aggregate capacity to 735,000 HHP by the end of the first quarter of 2018.

Through our pressure pumping segment (which also includes cementing and acidizing 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 have fully maintained our equipment throughout the recent industry downturn to ensure optimal performance and reliability. Additionally, all of the hydraulic horsepower delivered over the last four years has been sourced from a single manufacturer, leading to a homogeneous fleet with streamlined maintenance programs and training for our personnel.

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, Permian drilling and surface air 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 increasing 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 reached a low of $26.19 per barrel. This decline in 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.

Most recently, the recovery of crude oil prices to a high in excess of $50 per barrel since December 2016 through September 2017, has driven a considerable increase in drilling and completion activity, and associated demand for our services. The Permian Basin, our primary area of operation, is leading the recovery with the number of active drilling rigs increasing

from a low of 137 rigs in the basin as of May 2016 to 385 rigs in the basin as of September 2017, 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 frac stages per lateral and increasing amounts of proppant employed per well, have significantly increased demand for our hydraulic fracturing and other completion services.

As the Permian Basin shifts further towards more intensive horizontal drilling, operators and service providers are expected to continue to place significant focus on drilling and completion efficiencies, such as multi-well pads and zipper fracs. 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.

Rising producer activity levels, increasing basin service intensity and continued drilling and completion efficiencies have combined to drive the 100% utilization of our fleet and build a sizable backlog of addressable demand for our services. During the recent downturn, we saw our competitors defer necessary maintenance capital spending and cannibalize existing units for spare parts and idle HHP. This has resulted in tightening hydraulic fracturing supply and demand fundamentals and could drive pricing improvement for our hydraulic fracturing services. 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., Superior Energy Services, Schlumberger and a number of private companies. Competitive factors impacting sales of our services are price, reputation and technical expertise, service and equipment quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies' criteria in choosing a service provider. 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. More recently however, with increasing levels of Delaware Basin activity, we have recently expanded our presence in the Delaware Basin in response to increasing levels of demand pull 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) (gain) on extinguishment of debt, (iii) stock based compensation, and (iv) 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, research analysts and others, 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 expenses (such as IPO bonus) 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, operating income, 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. We believe that the presentation of these non-GAAP financial measures 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 and items outside the control of the Company. Net income is the GAAP measure most directly comparable to Adjusted EBITDA. Our non-GAAP financial measures 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 September 30, 2017									Nine months ended September 30, 2017
($ in thousands)	Pressure Pumping			All Other			Total			Pressure Pumping			All Other			Total
Net income (loss)	$	28,372		$	(6,407	)	$	21,965		$	30,087		$	(27,552	)	$	2,535
Depreciation and amortization	13,637			1,108			14,745			35,228			3,374			38,602
Interest expense	—			644			644			—			6,469			6,469
Income tax (benefit) expense	—			(96		)	(96		)	—			128			128
Loss on disposal of assets	7,552			1,190			8,742			27,943			1,028			28,971
Stock-based compensation	—			751			751			—			8,730			8,730
Other expense	—			191			191			—			792			792
Other general and administrative expense ⁽¹⁾	—			149			149			—			722			722
Deferred IPO bonus expense	452			225			677			5,038			2,668			7,706
Adjusted EBITDA	$	50,013		$	(2,245	)	$	47,768		$	98,296		$	(3,641	)	$	94,655

	Three months ended September 30, 2016									Nine months ended September 30, 2016
($ in thousands)	Pressure Pumping			All Other			Total			Pressure Pumping			All Other			Total
Net loss	$	(12,265	)	$	(1,333	)	$	(13,598	)	$	(34,815	)	$	(1,015	)	$	(35,830	)
Depreciation and amortization	9,274			1,516			10,790			27,905			4,764			32,669
Interest expense	—			4,550			4,550			—			15,942			15,942
Income tax benefit	—			(6,946		)	(6,946		)	—			(18,644		)	(18,644		)
(Gain)/loss on disposal of assets	5,942			(19		)	5,923			13,410			(551		)	12,859
Stock-based compensation	—			510			510			—			1,130			1,130
Gain on extinguishment of debt	—			—			—			—			(6,975		)	(6,975		)
Other expense	—			106			106			—			419			419
Adjusted EBITDA	$	2,951		$	(1,616	)	$	1,335		$	6,500		$	(4,930	)	$	1,570

We conduct our business through seven operating segments: hydraulic fracturing, cementing, acidizing, coil tubing, flowback, surface drilling, and Permian drilling. For reporting purposes, the hydraulic fracturing, cementing and acidizing 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. We expect revenues and costs of services related to our Permian drilling operating segment to comprise a lower percentage of total revenues and total costs of service in future results of operations when compared to historic results due to our increased focus on pressure pumping and other complementary service offerings. We anticipate the financial significance of this service line relative to the financial results from pressure pumping and other service offerings to continue to decline.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenue	$	282,730		$	116,904		$	668,153		$	272,999
Cost of services ⁽¹⁾	225,433			110,223			551,775			255,362
General and administrative expense ⁽²⁾	11,106			5,856			38,881			17,197
Depreciation and amortization	14,745			10,790			38,602			32,669
Loss on disposal of assets	8,742			5,923			28,971			12,859
Interest expense	644			4,550			6,469			15,942
Gain on extinguishment of debt	—			—			—			(6,975		)
Other expense	191			106			792			419
Income tax expense/(benefit)	(96		)	(6,946		)	128			(18,644		)

Net income (loss)	$	21,965		$	(13,598	)	$	2,535		$	(35,830	)

Adjusted EBITDA ⁽³⁾	$	47,768		$	1,335		$	94,655		$	1,570
Adjusted EBITDA Margin ⁽³⁾	16.90		%	1.14		%	14.17		%	0.58		%

Pressure pumping segment results of operations:
Revenue	$	271,924		$	109,697		$	639,355		$	251,410
Cost of services	$	217,171		$	103,465		$	529,818		$	235,587
Adjusted EBITDA	$	50,013		$	2,951		$	98,296		$	6,500
Adjusted EBITDA Margin ⁽⁴⁾	18.39		%	2.69		%	15.37		%	2.59		%

(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 141.8%, or $165.8 million, to $282.7 million for the three months ended September 30, 2017, as compared to $116.9 million for the three months ended September 30, 2016. The increase was primarily attributable to the increase in customer activity, fleet size and demand for our services, which has led to an increase in pricing for our hydraulic fracturing and other services. Our pressure pumping segment revenues increased 147.9%, or $162.2 million, for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. Revenues from services other than pressure pumping increased 49.9%, or $3.6 million, for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase in revenues from services other than pressure pumping was primarily attributable to the increase in revenues and customer demand for our flowback, coil tubing and surface drilling services, offset by the decrease in revenue from the idling of our Permian drilling rigs in the three months ended September 30, 2017.

Cost of Services. Cost of services increased 104.5%, or $115.2 million, to $225.4 million for the three months ended September 30, 2017, from $110.2 million during the three months ended September 30, 2016. Cost of services in our pressure pumping segment increased $113.7 million for the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. The increases were primarily attributable to higher activity levels, fleet size, coupled with an increase in personnel headcount following the increased activity levels. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 79.9% for the three months ended September 30, 2017, as compared to 94.3% for the three months ended September 30, 2016. The decrease in cost of services as a percentage of revenue for the pressure pumping segment resulted from a greater pricing power as demand for our services increased, without a corresponding increase in costs, which resulted in significantly higher realized Adjusted EBITDA margins during the three months ended September 30, 2017.

General and Administrative Expenses. General and administrative expenses increased 89.7%, or $5.3 million, to $11.1 million for the three months ended September 30, 2017, as compared to $5.9 million for the three months ended September 30, 2016. The increase was primarily attributable to increases in legal and professional fees, insurance expense and payroll, totaling $4.5 million, and a net increase in other remaining general and administrative expenses totaling $0.7 million.

Depreciation and Amortization. Depreciation and amortization increased 36.7%, or $4.0 million, to $14.7 million for the three months ended September 30, 2017, as compared to $10.8 million for the three months ended September 30, 2016. The increase was primarily attributable to additional property and equipment purchased in 2017. We calculate depreciation of property and equipment using the straight-line method.

Loss on Disposal of Assets. Loss on the disposal of assets increased 47.6%, or $2.8 million, to $8.7 million for the three months ended September 30, 2017, as compared to $5.9 million for the three months ended September 30, 2016. The increase was primarily attributable to greater service intensity of jobs completed coupled with higher fleet size, activity levels and utilization of our equipment.

Interest Expense. Interest expense decreased 85.8%, or $3.9 million, to $0.6 million for the three months ended September 30, 2017, as compared to $4.6 million for the three months ended September 30, 2016. The decrease in interest expense was primarily attributable to a reduction in our average debt balance during 2017 due to the early retirement of our Term Loan and Revolving Credit Facility in the first quarter of 2017.

Other Expense. Other expense was $0.2 million for the three months ended September 30, 2017, as compared to other expense of $0.1 million for the three months ended September 30, 2016. The marginal net increase was primarily attributable to decrease in the unrealized gain resulting from the change in the fair value of our interest rate swap liability at September 30, 2017 compared to September 30, 2016, and partially offset by a decrease in other lender related expenses.

Income Tax Expense/(Benefit). For the three months ended September 30, 2017, we utilized the discrete effective tax rate method as allowed by Accounting Standards Codification (“ASC”) 740-270-30-18, Income Taxes - Interim Reporting to calculate its interim tax provision. The discrete method treats the year to date period as if it was the annual period and determines the income tax expense or benefit on that basis. We believe that, at this time, the use of this discrete method is more appropriate than the annual effective tax rate method as the annual effective tax rate is not reliable because small changes in estimated “ordinary” income would result in significant changes in the estimated annual effective tax rate. Total income tax benefit was $0.1 million resulting in a negative effective tax rate of 0.4% for the three months ended September 30, 2017 as compared to total income tax benefit of $6.9 million and an effective tax rate of 33.8% for the three months ended September 30, 2016. The negative effective tax rate is primarily due to our full valuation allowance position, impact of indefinite lived assets, state tax expense and alternative minimum tax expense, which creates a deviation from the customary relationship between income tax expense (benefit) and pre-tax income/(loss).

Revenues. Revenues increased 144.7%, or $395.2 million, to $668.2 million for the nine months ended September 30, 2017, as compared to $273.0 million for the nine months ended September 30, 2016. The increase was primarily attributable to the increase in customer activity, fleet size and demand for our services, which has led to an increase in pricing for our hydraulic fracturing and other services. Our pressure pumping segment revenues increased 154.3%, or $387.9 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. Revenues from services other than pressure pumping increased 33.4%, or $7.2 million, in the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. The increase in revenues from services other than pressure pumping during the nine months ended September 30, 2017 was primarily attributable to the increase in revenues and customer demand for our flowback, coil tubing and surface drilling services, offset by the decrease in revenue from idling of our Permian drilling rigs.

Cost of Services. Cost of services increased 116.1%, or $296.4 million, to $551.8 million for the nine months ended September 30, 2017, from $255.4 million during the nine months ended September 30, 2016. Cost of services in our pressure pumping segment increased $294.2 million for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. The increases were primarily attributable to higher activity levels, coupled with an increase in personnel headcount following the increased activity levels. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 82.9% for the nine months ended September 30, 2017, as compared to 93.7% for the nine months ended September 30, 2016. The decrease in cost of services as a percentage of revenue for the pressure pumping segment resulted from greater pricing power as demand for our services increased, without a corresponding increase in costs, which resulted in significantly higher realized Adjusted EBITDA margins during the nine months ended September 30, 2017.

General and Administrative Expenses. General and administrative expenses increased 126.1%, or $21.7 million, to $38.9 million for the nine months ended September 30, 2017, as compared to $17.2 million for the nine months ended September 30, 2016. The increase was primarily attributable to increases in legal and professional fees, insurance expense and payroll, totaling $6.7 million, IPO bonus of $7.7 million to key employees, along with $7.6 million increase in stock compensation recorded during 2017, and partially offset by a $0.3 million decrease in other remaining general and administrative expenses. General and administrative expenses, excluding non-recurring deferred IPO bonus of $7.7 million and stock compensation compensation expense of $6.8 million, as a percentage of total revenues decreased to 3.6% for the nine months ended September 30, 2017, as compared to 6.3% for the nine months ended September 30, 2016, and the decrease is as a result of the higher revenue in the nine months ended September 30, 2017.

Depreciation and Amortization. Depreciation and amortization increased 18.2%, or $5.9 million, to $38.6 million for the nine months ended September 30, 2017, as compared to $32.7 million for the nine months ended September 30, 2016. The increase was primarily attributable to additional property and equipment purchased and put into service during the nine months ended September 30, 2017. We calculate depreciation of property and equipment using the straight-line method.

Loss on Disposal of Assets. Loss on the disposal of assets increased 125.3%, or 16.1 million, to $29.0 million for the nine months ended September 30, 2017, as compared to $12.9 million for the nine months ended September 30, 2016. The increase was primarily attributable to greater service intensity of jobs completed coupled with higher fleet size, activity levels and utilization of our equipment.

Interest Expense. Interest expense decreased 59.4%, or $9.5 million, to $6.5 million for the nine months ended September 30, 2017, as compared to $15.9 million for the nine months ended September 30, 2016. The decrease in interest expense was primarily attributable to a reduction in our average debt balance during 2017 due to the early retirement of our Term Loan and Revolving Credit Facility in the first quarter of 2017.

Other Expense. Other expense was $0.8 million for the nine months ended September 30, 2017, as compared to $0.4 million for the nine months ended September 30, 2016. The increase was primarily attributable to an increase in lenders related expenses, non-recurring listing related expenses, and partially offset by an increase in the unrealized gain resulting from the change in the fair value of our interest rate swap liability at September 30, 2017 compared to September 30, 2016.

Gain on Extinguishment of Debt. There was no debt extinguishment gain or loss during the nine months ended September 30, 2017, compared to the gain on extinguishment of debt, net of cost, of $7.0 million during the nine months ended September 30, 2016. The gain on extinguishment of debt during 2016 was as a result of the auction process with our lenders to repurchase $37.5 million of our Term Loan at a 20% discount to par value.

Income Tax Expense/(Benefit). For the nine months ended September 30, 2017, the Company has utilized the discrete effective tax rate method as allowed by Accounting Standards Codification (“ASC”) 740-270-30-18, Income Taxes - Interim Reporting to calculate its interim tax provision. The discrete method treats the year to date period as if it was the annual period

and determines the income tax expense or benefit on that basis. The Company believes that, at this time, the use of this discrete method is more appropriate than the annual effective tax rate method as the annual effective tax rate is not reliable because small changes in estimated “ordinary” income would result in significant changes in the estimated annual effective tax rate. Total income tax expense was $0.1 million resulting in an effective tax rate of 4.8% for the nine months ended September 30, 2017, compared to total income tax benefit of $18.6 million and an effective tax rate of 34.2% for the nine months ended September 30, 2016. The change in effective tax rate is primarily due to the Company’s full valuation allowance position, impact of indefinite lived assets, alternative minimum tax expense and state tax expense.

As of September 30, 2017, our cash and cash equivalents were $51.0 million, as compared to $133.6 million at December 31, 2016. 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 continue to fund our operations, support organic 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.



($ in thousands)	September 30, 2017		December 31, 2016
Current Assets:
Cash and cash equivalents	$	51,008	$	133,596
Accounts receivable - net of allowance for doubtful accounts	160,047		115,179
Inventories	9,148		4,713
Prepaid expenses	5,543		4,608
Other current assets	975		6,684
Total current assets	$	226,721	$	264,780

Current Liabilities:
Accounts payable	$	181,660	$	129,093
Accrued liabilities	11,074		13,619
Current portion of long-term debt	7,441		16,920
Accrued interest payable	86		109
Total current liabilities	$	200,261	$	159,741
Working capital	$	26,460	$	105,039

Net cash provided by operating activities was $78.7 million for the nine months ended September 30, 2017, compared to net cash used in operating activities of $5.7 million for the nine months ended September 30, 2016. The net increase of $84.3 million was primarily due to increase in revenue and net income in the period, offset by our working capital needs resulting from higher fleet size and expanding activity levels.

Net cash used in investing activities increased to $189.6 million for the nine months ended September 30, 2017, from $18.2 million during the nine months ended September 30, 2016. The increase was primarily attributable to the additional hydraulic fracturing fleets and other ancillary equipment purchased during the period, and a slight increase in maintenance capital expenditures, during the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016.

Net cash provided by financing activities was $28.3 million for the nine months ended September 30, 2017, and net cash used in financing activities was $5.2 million for the nine months ended September 30, 2016. The net increase in cash provided was primarily due to the receipt of $185.5 million of IPO proceeds, borrowings of $27.1 million, partially offset by payment of IPO costs of $15.1 million, repayment of insurance financing of $2.9 million, debt issuance cost of $1.7 million and $164.6 million in repayment of borrowings, during the nine months ended September 30, 2017, compared to net cash used of $42.2

In February 2016, the FASB issued ASU No. 2016-02, Leases, a new standard on accounting for leases. The ASU introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in the current accounting guidance as well as the FASB’s new revenue recognition standard. However, the ASU eliminates the use of bright-line tests in determining lease classification as required in the current guidance. The ASU also requires additional qualitative disclosures along with specific quantitative disclosures to better enable users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The new standard is effective for annual reporting periods beginning after December 15, 2018, including periods within that reporting period, using a modified retrospective approach. Early adoption is permitted. We have not completed an evaluation of the impact the pronouncement will have on our consolidated financial statements and related disclosures.

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. Oil prices declined significantly close to the end of the second half of 2014. The closing price of 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, oil prices have recovered in the third quarter of 2016, and reaching a high in excess $50 during the third quarter of 2017. As a result of the recent recovery in oil prices, our industry has

experienced a significant increase in both drilling and pressure pumping activity levels. Looking forward, assuming commodity prices remain at or above recent levels, we believe U.S. rig counts will continue to increase. We expect 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 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, principal financial officer and principal accounting 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, principal financial officer and principal accounting officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2017.

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.

There have been no material changes to our principal risks that we believe are material to our business, results of operations, and financial condition from the risk factors previously disclosed in our final prospectus dated March 16, 2017, and filed with the SEC pursuant to Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 20, 2017, which is accessible on the SEC’s website at www.sec.gov.



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.



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



		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	1
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016	2
	Condensed Consolidated Statement of Changes in Shareholders' Equity for the nine months ended September 30, 2017	3
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016	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	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	28
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
Item 3.	Defaults Upon Senior Securities	29
Item 4.	Mine Safety Disclosures	29
Item 5.	Other Information	29
Item 6.	Exhibits	30
	Signatures	31



Expected volatility	45		%
Expected dividends	$	—
Expected term (in years)	6.25
Risk free rate	1.35		%



Expected volatility	45		%
Expected dividends	$	—
Expected term (in years)	6.25
Risk free rate	1.83		%



Expected volatility	55		%
Expected dividends	$	—
Expected term (in years)	5.8
Risk free rate	1.22		%



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



($ in thousands)
2017	$	1,778
2018	14,298
2019	805
2020	36
2021 and thereafter	25,000

Total	$	41,917



(In thousands)	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Stock options	789	4,646	789	4,646
Performance stock units	—	—	170	—
Non-vested restricted stock	—	372	318	372
	789	5,018	1,277	5,018



	Number of Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2017	372,335		$	3.89
Granted	691,585		$	13.65
Vested	—		$	—
Exercised	—		$	—
Forfeited	(1,170	)	$	13.65
Expired	—		$	—
Canceled	(372,335	)	$	3.89
Outstanding at September 30, 2017	690,415		$	13.65



Period Granted	Target Shares Outstanding at Beginning of Period	Target Shares Granted	Target Shares Vested	Target Shares Forfeited	Target Shares Outstanding at End of Period	Weighted Average Grant Date Fair Value per Share
2017	—	169,635	—	—	169,635	$	10.73

Total	—	169,635	—	—	169,635


•	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;


•	technological changes;


•	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;


•	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.



SIGNATURES

Date:	November 2, 2017	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)