June 22, 2020 - 10-K: Annual report pursuant to Section 13 and 15(d)

Form: 10-K

Documents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-K

______________________________



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

For the fiscal year ended December 31, 2019



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

For the transition period from to

Commission File Number: 001-38035

______________________________

ProPetro Holding Corp.

(Exact name of registrant as specified in its charter)

______________________________



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

1706 South Midkiff,

Midland, Texas 79701

(Address of principal executive offices)

Registrant’s telephone number, including area code: (432) 688-0012

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock ($0.001 par value)	PUMP	New York Stock Exchange
Preferred Stock Purchase Rights	N/A	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

______________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No ý

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ¨ No ý

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.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý

The aggregate market value of the Company’s Common Stock held by nonaffiliates on June 30, 2019, determined using the per share closing price on the New York Stock Exchange Composite tape of $20.70 on that date, was approximately $1,492.4 million.

The number of the registrant’s common shares, par value $0.001 per share, outstanding at June 9, 2020, was 100,849,840.

TABLE OF CONTENTS




EXPLANATORY NOTE	ii
FOWARD-LOOKING STATEMENTS	iv

PART I
BUSINESS	1
RISK FACTORS	11
UNRESOLVED STAFF COMMENTS	30
PROPERTIES	30
LEGAL PROCEEDINGS	30
MINE SAFETY DISCLOSURES	31

PART II
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	32
SELECTED FINANCIAL DATA	34
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	36
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	51
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	52
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	88
CONTROLS AND PROCEDURES	89
OTHER INFORMATION	92

PART III
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	93
EXECUTIVE COMPENSATION	104
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	136
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	138
PRINCIPAL ACCOUNTING FEES AND SERVICES	141

PART IV
EXHIBITS AND FINANCIAL SCHEDULES	143
FORM 10-K SUMMARY	147
SIGNATURES	148

EXPLANATORY NOTE

Audit Committee Internal Review

In May 2019, the Audit Committee (the “Committee”) of ProPetro Holding Corp.’s (the “Company”) board of directors (the “Board”), with assistance of independent outside counsel and accounting advisors, began conducting an internal review initially focused on the Company’s disclosure of agreements previously entered into with AFGlobal Corporation for the purchase of Durastim® hydraulic fracturing fleets and effective communications related thereto. The review was later expanded (collectively, the “Expanded Audit Committee Review”) to, among other items, review expense reimbursements, certain transactions involving related parties or potential conflicts of interest, and certain transactions entered into by our former chief executive officer.

Findings of the Expanded Audit Committee

Based on the information collected and reviewed by the Committee’s independent outside counsel and accounting advisors, the Expanded Audit Committee Review resulted in numerous factual findings, including but not limited to, the following significant findings:

•

approximately $370,000 of expenses reimbursed to members of senior management, including the former chief executive officer (approximately $346,000) and former chief financial officer (approximately $18,000), were incorrectly recorded as expenses of the Company and should have been the responsibility of the officers individually; each of these officers has reimbursed the Company in full for the identified amounts. These improper reimbursements were attributable to inadequate documentation stemming from the lack of a more robust employee expense review and approval procedure;


•	the Company’s former chief accounting officer entered into a related party transaction that was not properly disclosed in the Company’s filings with the Securities and Exchange Commission (the “SEC”);


•	a number of internal and disclosure control deficiencies and material weaknesses were identified, as described in more detail in Part II - Item 9A. “Controls and Procedures,” including, but not limited to, the following:


◦	the Company’s former executive management team did not establish and promote a control environment with an appropriate tone of compliance and control consciousness throughout the entire Company;


◦	the Company did not appropriately identify and monitor conflicts of interest;


◦	certain whistleblower allegations were not properly investigated and elevated to the Committee;


◦	instances were identified of non-compliance with the Company’s internal policies, including its Insider Trading Compliance Policy and Code of Conduct and Ethics; and


◦	management did not appropriately communicate information internally and externally, including communication between management and the Board.

The Expanded Audit Committee Review did not identify any material accounting errors in the Company’s consolidated financial statements, and no restatement or revision was required of the Company’s consolidated financial statements previously reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Annual Report”) and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 (the “2019 First Quarter 10-Q”).

Following completion of the Expanded Audit Committee Review and in connection with performing additional procedures to position the Company’s current principal executive and principal financial officers to be in a position to certify the Company’s future filings with the SEC, the Company determined that its former chief executive officer entered into a pledge agreement covering all of the Company’s common stock owned by him at

that time as collateral for a personal loan in January 2017, in violation of the shareholders agreement then in place through the pledging of shares. The Company formally adopted its Insider Trading Compliance Policy in March 2017 (in connection with its initial public offering), which prohibits pledging the Company’s securities as collateral to secure loans. The Company also believes that, in 2018 in connection with another personal loan, its former chief executive officer executed a share pledge agreement that was subsequently replaced with a negative pledge with respect to all of the Company’s common stock owned by him at that time or acquired thereafter and engaged in other inappropriate conduct in connection with these personal loans. The Company did not appropriately disclose such pledges in the Company’s prior SEC filings that included management share ownership. Also in connection with performing additional procedures, the Company determined that it had previously failed to appropriately disclose in its annual proxy statements certain perquisites as compensation paid to some of the Company’s named executive officers in 2017 and 2018, including, among other later reimbursed perquisites, ticket purchases, charitable donations, and costs associated with pilots provided by the Company for its former chief executive officer’s personal use of his plane. See "Executive Compensation—Summary Compensation Table" and "Executive Compensation—Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table—Perquisites" for more information regarding these perquisites.

Internal Control over Financial Reporting and Disclosure Controls and Procedures

As a result of the material weaknesses in the Company’s internal control over financial reporting described above and as further described in Part II - Item 9A. “Controls and Procedures,” the Company concluded that (i) its disclosure controls and procedures were not effective as of December 31, 2019 and 2018 and March 31, June 30 and September 30, 2019 and (ii) its internal control over financial reporting was not effective as of December 31, 2019 and 2018. Due to the existence of such material weaknesses, the Company’s internal control over financial reporting remained ineffective as of March 31, June 30 and September 30, 2019. The Company previously announced on November 13, 2019 that investors should no longer rely on management’s report on internal control over financial reporting or the internal control over financial reporting opinion of the Company’s independent registered public accounting firm included in the 2018 Annual Report. The conclusions regarding effectiveness previously expressed by the Company’s former management in Part II, Item 9A, “Controls and Procedures” in the 2018 Annual Report and Part I, Item 4, “Controls and Procedures” in the 2019 First Quarter 10-Q are hereby amended by the conclusions expressed in Part II - Item 9A. “Controls and Procedures” of this Annual Report on Form 10-K. In light of the disclosures herein, the Company does not intend to file amendments to the 2018 Annual Report or the 2019 First Quarter 10-Q to reflect these conclusions.

Remediation Plan

The Company’s remediation efforts are ongoing, and it will continue its initiatives to implement and document policies, procedures, and internal controls. The Board and management have implemented a number of measures to address the material weaknesses identified, including appointing new executive officers with extensive public company experience; enhancing certain of the Company’s policies and monitoring compliance with such policies; designing and implementing control activities related to the identification and approval of related party transactions and potential conflicts of interest, as well as the evaluation of whistleblower allegations; forming a disclosure committee and appointing a chief disclosure officer. The Company’s remediation efforts are described in more detail in Part II - Item 9A. “Controls and Procedures.”

iii

FORWARD‑LOOKING STATEMENTS

This Annual Report on Form 10-K (the “Annual Report”) contains forward‑looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “may,” “could,” “plan,” “project,” “budget,” “predict,” “pursue,” “target,” “seek,” “objective,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” and other expressions that are predictions of, or indicate, future events and trends and that do not relate to historical matters identify forward‑looking statements. Our forward‑looking statements include, among other matters, statements about our business strategy, industry, future profitability, expected capital expenditures and the impact of such expenditures on our performance and capital programs.

A forward‑looking statement may include a statement of the assumptions or bases underlying the forward‑looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward‑looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:


•	the severity and duration of world health events, including the recent outbreak of the novel coronavirus (“COVID-19”) pandemic, related economic repercussions and the resulting severe disruption in the oil and gas industry and negative impact on demand for oil and gas, which is negatively impacting our business;

•

the current significant surplus in the supply of oil and actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;


•	uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for crude oil and natural gas and therefore the demand for our services;


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


•	changes in general economic and geopolitical conditions;


•	competitive conditions in our industry;


•	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;


•	changes in the availability and cost of capital;


•	our ability to successfully implement our business plan;


•	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;


•	operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;


•	changes in our tax status;


•	technological changes;


•	our ability to successfully implement technological developments and enhancements, including the new DuraStim® fleets and associated power solutions;


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


•	acts of terrorism, war or political or civil unrest in the United States or elsewhere;


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


•	the effects of current and future litigation, including the Logan Lawsuit, the Boca Raton Lawsuit and the Chang Lawsuit (each defined herein);


•	the timing and outcome of, including potential expense associated with, the SEC pending investigation;


•	the potential impact on our business and stock price of any announcements regarding the SEC's pending investigation, the Logan Lawsuit, the Boca Raton Lawsuit or the Chang Lawsuit;


•	the material weaknesses in our internal controls over financial reporting and disclosure controls and procedures described under Part I, Item 9, “Controls and Procedures” in this Annual Report;


•	matters related to the Expanded Audit Committee Review and related findings, as well as the implementation and effectiveness of the Company's remediation plan; and


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

You should not place undue reliance on our forward‑looking statements. Although forward‑looking statements reflect our good faith beliefs at the time they are made, forward‑looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Item 1A. Risk Factors” of this Annual Report, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward‑looking statements. We undertake no obligation to publicly update or revise any forward‑looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

Unless the context indicates otherwise, all references to “ProPetro Holding Corp.,” “the Company,” “we,” “our” or “us” or like terms refer to ProPetro Holding Corp. and its consolidated subsidiary, ProPetro Services, Inc.

PART I

Item 1. Business.

Our Company

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 longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower (“HHP”).

Changes to our customers’ well design, shale formations, operating conditions and new technology have resulted in continuous changes to the number of pumps that constitute a fleet. As a result of the asymmetric nature of the number of pumps that constitute a fleet across our customer base, which we believe will continue to evolve, we view HHP to also be an appropriate metric to measure our available hydraulic fracturing capacity. At the beginning of the year, our fleet size was 28 conventional hydraulic fracturing fleets. During 2019, we reconfigured our existing fleet size to 24 conventional fleets with the objective of increasing our HHP per fleet, and we subsequently purchased 54,000 HHP of new DuraStim® hydraulic pumps, bringing our total HHP at December 31, 2019 to 1,469,000 HHP. Our total HHP as of December 31, 2019 was comprised of 1,415,000 HHP of conventional HHP and 54,000 HHP of our newly purchased DuraStim® hydraulic fracturing technology. With the continuous evaluation and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline as we reconfigure our fleets to increase active HHP and back up HHP based on our customers’ operational needs.

In 2019, we entered into a purchase commitment for 108,000 HHP DuraStim® hydraulic fracturing pumps. We believe that one DuraStim® fleet could require between 6 to 9 frac pumps or 36,000 to 54,000 HHP per fleet, depending on the shale formation in which it operates and the customer’s well design. The first DuraStim® hydraulic fracturing pumps were delivered in December 2019 and the remaining DuraStim® hydraulic fracturing pumps are expected to be delivered in 2020. We also have an option to purchase up to three additional DuraStim® fleets in the future through April 2021. We believe the DuraStim® hydraulic fracturing pump technology could represent the future of our industry and is designed to drive down well costs for our customers while improving safety and the useful life of the equipment and reducing environmental impact. The DuraStim® technology is powered by electricity. We purchased two gas turbines to provide electrical power for our DuraStim® fleets. The electrical power sources for future DuraStim® fleets are still being evaluated and could either be supplied by the Company, customers or a third-party supplier.

All of our hydraulic fracturing fleets have been designed to handle the most challenging Permian Basin 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.

In addition to our core pressure pumping segment operations, which includes our cementing operations, we also offer a suite of complementary well completion and production services, including coiled tubing and other services. We believe these complementary services create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well.

Commodity Price and Other Economic Conditions

The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in early March 2020 as a direct result of failed negotiations between OPEC and Russia. In response to the global economic slowdown, OPEC had recommended a decrease in production levels in order to accommodate reduced demand. Russia

rejected the recommendation of OPEC as a concession to U.S. producers. After the failure to reach an agreement, Saudi Arabia, a dominant member of OPEC, and other Persian Gulf OPEC members announced intentions to increase production and offer price discounts to buyers in certain geographic regions.

As the breadth of the COVID-19 health crisis expanded throughout the month of March 2020 and governmental authorities implemented more restrictive measures to limit person-to-person contact, global economic activity continued to decline commensurately. The associated impact on the energy industry has been adverse and continued to be exacerbated by the unresolved conflict regarding production. In the second week of April 2020, OPEC+ reconvened to discuss the matter of production cuts in light of unprecedented disruption and supply and demand imbalances that expanded since the failed negotiations in early March 2020. Tentative agreements were reached to cut production by up to 10 million barrels of oil per day, or BOPD, with allocations to be made among the OPEC+ participants. Some of these production cuts went into effect in the first half of May 2020, however, commodity prices remain depressed as a result of an increasingly utilized global storage network and near-term demand loss attributable to the COVID-19 health crisis and related economic slowdown.

The combined effect of COVID-19 and the energy industry disruptions led to a decline in WTI crude oil prices of approximately 67 percent from the beginning of January 2020, when prices were approximately $62 per barrel, through the end of March 2020, when they were just above $20 per barrel. Overall crude oil price volatility has continued despite apparent agreement among OPEC+ regarding production cuts and as of June 17, 2020, the WTI price for a barrel of crude oil was approximately $38.

Despite a significant decline in drilling and completion activity by U.S. producers starting in mid-March 2020, domestic supply continues to exceed demand which has led to significant operational stress with respect to capacity limitations associated with storage, pipeline and refining infrastructure, particularly within the Gulf Coast region. The combined effect of the aforementioned factors is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.

In order to mitigate the impact of COVID-19 and the economic effects of the unprecedented decline in economic activity and global energy markets, we undertook several actions since March 2020 in support of the efficient continuity of our operations. These actions are described in greater detail in Part 2, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our Services

We have historically conducted our business through five operating segments: hydraulic fracturing, cementing, coiled tubing, flowback and drilling. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment: pressure pumping. Our coiled tubing, flowback, and drilling operating segments and corporate administrative expense are aggregated into our “All Other” reportable segment. For additional financial information on our reportable segment, please see reportable segment information in Part II - Item 8. “Financial Statements and Supplementary Data.”

Pressure Pumping

Hydraulic Fracturing

We primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. We have significant expertise in multi‑stage fracturing of horizontal oil‑producing wells in unconventional geological formations. We took delivery of 54,000 HHP of new DuraStim® hydraulic fracturing pumps in December 2019, bringing our total fleet capacity to 1,469,000 HHP as of December 31, 2019.

The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, which in our business are comprised primarily of sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return of hydrocarbons for the operator.

We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also refer to all of our fracturing units, other equipment and vehicles necessary to perform a fracturing job as

a “fleet” and the personnel assigned to each fleet as a “crew.” Our conventional hydraulic fracturing units consist primarily of a high pressure hydraulic pump, diesel engine, transmission and various hoses, valves, tanks and other supporting equipment like blenders, irons and data vans. The new DuraStim® hydraulic fracturing fleet is powered by electricity and the electrical power equipment could either be provided by us or our customers.

We provide dedicated equipment, personnel and services that are tailored to meet each of our customer’s needs. Each fleet has a designated team of personnel, which allows us to provide responsive and customized services, such as project design, proppant and other consumables procurement, real‑time data provision and post‑completion analysis for each of our jobs. Many of our hydraulic fracturing fleets and associated personnel have continuously worked with the same customer for the past several years promoting deep relationships and a high degree of coordination and visibility into future customer activity levels. Furthermore, in light of our substantial market presence and historically high fleet utilization levels, we have established a variety of entrenched relationships with key equipment, sand and other downhole consumable suppliers. These strategic relationships ensure ready access to equipment, parts and materials on a timely and economic basis and allow our dedicated procurement logistics team to ensure consistently safe and reliable operations.

Cementing

We provide cementing services for completion of new wells and remedial work on existing wells. 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. Cementing provides isolation between fluid zones behind the casing to minimize potential damage to hydrocarbon bearing formations or the integrity of freshwater aquifers, and provides structural integrity for the casing by securing it to the earth. Cementing is also done when recompleting wells, where one zone is plugged and another is opened.

As of December 31, 2019, we had a total of 25 cementing units. We believe that our cementing segment provides an organic growth opportunity for us to expand our service offerings within our existing customer base.

Other Services

Coiled Tubing

Coiled tubing services involve injecting coiled tubing into wells to perform various completion well intervention operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck‑mounted reel for onshore applications. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas.

The principal advantages of using coiled tubing include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe used with a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole motor or manipulate down‑hole tools and (v) enhance access to remote fields due to the smaller size and mobility.

As of December 31, 2019, we had a total of 9 coiled tubing units of various sizes.

Flowback Services

Our flowback services consist of production testing, solids control and hydrostatic testing. Flowback involves the process of allowing fluids to flow from the well following a treatment, either in preparation for an impending phase of treatment or to return the well to production. Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment that combine to form up to a total of five well‑testing spreads. We provide flowback services in the Permian Basin and mid‑continent markets. Our flowback business segment has continued to decline in profitability over the years, and as a result, the Company shut down its flowback operations in 2020 and disposed of the assets.

Drilling

Our vertical drilling assets in our drilling segment have been idled since 2016. The Company is considering strategic alternatives for the use of its drilling rigs including exploring options to dispose of the remaining drilling rigs and ancillary assets. If the market for vertical drilling does not improve and the equipment continues to be idled, the estimated fair value for the drilling rigs may decline, thus resulting in future additional impairment charges.

Competitive Strengths

Our primary business objective is to serve as a strategic long-term partner for our customers. We achieve this objective by providing reliable, high‑quality services that are tailored to our customers’ needs and synchronized with their well development programs. This alignment assists our customers in optimizing the long‑term development of their unconventional resources. We believe that the following competitive strengths differentiate us from our peers and uniquely position us to achieve our primary business objective.

•

Strong market position in the Permian Basin. We believe we are one of the largest hydraulic fracturing providers by HHP in the Permian Basin, which is one of the most prolific oil producing areas in the United States. Our longstanding customer relationships and substantial Permian Basin market presence uniquely position us to maintain our market position and grow as the basin is developed in the future. The Permian Basin is a mature, liquids‑rich basin with well-known geology and a large, exploitable resource base that delivers attractive E&P producer economics. As a result of its significant size, coupled with the presence of multiple prospective geologic benches and other favorable characteristics, the Permian Basin has become widely recognized as one of the most attractive and economic oil resources in North America.

Our operational focus has historically been in the Permian Basin’s Midland sub‑basin in support of our customers’ core operations. More recently, however, many of our customers have made sizeable acquisitions in the Delaware sub-basin, and we have expanded our services into the Delaware sub-basin to help develop their acreage. Further, we believe that we are uniquely positioned to capture a large addressable growth opportunity as the basin develops. For the foreseeable future, we expect both the Midland sub-basin and the Delaware sub-basin to continue to command a disproportionate share of future North American E&P spending.

•

Deep relationships and operational alignment with high‑quality, Permian Basin‑focused customers. Our deep local roots, operational expertise and commitment to safe and reliable service have allowed us to cultivate longstanding customer relationships with the most active and well‑capitalized Permian Basin operators. Many of our current customers have worked with us since our inception and have integrated our fleet scheduling with their well development programs. We have a long-term partnership agreement with one customer, an E&P company focused in the Permian Basin, to continue to provide pressure pumping and other complementary services for up to 10 years. This relationship differentiates us from our peers. This high degree of operational alignment and partnership with our customers has allowed us to maintain relatively high utilization rates over time compared to our peers. If our customers increase activity levels, we expect to continue to leverage our strong relationships to keep our fleets utilized.

•

Proven cross‑cycle financial performance. Over the past several years, we have maintained high cross‑cycle fleet utilization rates. From late 2017 through 2018 our fleets were consistently fully utilized. In 2019, following a decline in certain of our customers’ operations in the last quarter of 2019, our fleets utilization decreased slightly, and our utilization has decreased dramatically in 2020 as a result of COVID-19 and related matters. Historically, our consistent track record of steady growth, coupled with our ability to quickly deploy new HHP on a dedicated and fully utilized basis, has resulted in revenue growth across the industry’s cycles. We believe that we will be able to continue to operate more efficiently than our competitors while preserving attractive profitability and cash flows as a result of our differentiated service offerings and wellsite efficiencies. Furthermore, we believe that our philosophy of maintaining modest financial leverage and a healthy balance sheet has left us more conservatively capitalized than most of our peers. We expect that improving market fundamentals, our superior execution and our customer‑focused approach should continue to result in strong financial performance.

•

Seasoned management and operating team. We have a seasoned executive management team, with our senior members contributing more than 100 years of collective industry and financial experience. We believe their deep roots and relationships throughout the West Texas community, provide a meaningful competitive advantage for our business. In addition, our management team has assembled a loyal group of highly‑motivated and talented managers and field personnel, and we have had minimal manager‑level turnover in our core service divisions

over the past several years. We employ a balanced decision‑making structure that empowers managerial and field personnel to work directly with customers to develop solutions while leveraging senior management’s oversight. This collaborative approach fosters strong customer links at all levels of the organization and effectively institutionalizes customer relationships beyond the executive suite.

Strategy

Our strategy is to:

•

Capture an increasing share of demand for hydraulic fracturing services in the Permian Basin. We intend to continue to position ourselves as a Permian Basin‑focused hydraulic fracturing business, as we believe the Permian Basin hydraulic fracturing market offers supportive long‑term growth fundamentals. These fundamentals are characterized by increased demand for our HHP and well completion intensity levels. We have historically operated at a high utilization relative to our peers, and we believe we are strategically positioned to deploy our idle horse-power if overall market condition and demand for pressure pumping services increases.


•	Capitalize on improving efficiency gains. We intend to continue to work with our customers and vendors to improve our operational efficiencies and enhance our profitability. We believe that improving our efficiencies will result in greater revenue and enhanced profitability as fixed costs are spread over a broader revenue base.

•

Cross‑sell our complementary services. In addition to our hydraulic fracturing services, we offer a broad range of complementary services in support of our customers’ development activities, including cementing and coiled tubing. These complementary services create operational efficiencies for our customers, and allow us to capture a greater percentage of their capital spending across the lifecycle of an unconventional well. We believe that, if our customers increase spending levels, we are well positioned to continue cross‑selling and growing our complementary service offerings.

•

Maintain financial stability and flexibility to pursue growth opportunities. Consistent with our historical practices, we plan to continue to maintain a conservative balance sheet, which will allow us to better react to potential changes in industry and market conditions and opportunistically grow our business. In the near term, we intend to continue our past practice of aligning our growth capital expenditures with visible customer demand by strategically deploying new equipment on a dedicated basis in response to inbound customer requests. We will also selectively evaluate potential strategic acquisitions that increase our scale and capabilities or diversify our operations.

Our Customers

Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 77.1%, 68.7% and 66.0% of our revenue, for the years ended December 31, 2019, 2018 and 2017, respectively. For the year ended December 31, 2019, Pioneer Natural Resources USA Inc. (“Pioneer”), XTO Energy Inc., CrownQuest Operating, LLC, accounted for 25.5%, 20.9%, and 13.2%, respectively, of total revenue. No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2019.

Competition

The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, 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, equipment quality, ability to handle the most complex Permian Basin well completions and commitment to safety and reliability.

We provide our services primarily in the Permian Basin, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. Our major competitors for hydraulic fracturing services include Nextier Oilfield Solutions Inc., Halliburton Company, Patterson‑UTI Energy Inc., RPC, Inc., Schlumberger Limited, Liberty Oilfield Services, FTS International, Inc., Superior Energy Services and a number of locally oriented businesses.

Seasonality

Our results of operations have historically reflected seasonal tendencies, generally in the fourth quarter, relating to the conclusion of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather during which we may experience declines in our operating results.

Operating Risks and Insurance

Our operations are subject to hazards inherent in the oilfield services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause personal injury or loss of life, damage or destruction of property, equipment, natural resources and the environment and suspension of operations.

In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.

Our business involves the transportation of heavy equipment and materials, and as a result, we may also experience traffic accidents which may result in spills, property damage and personal injury.

Despite our efforts to maintain safety standards, we have suffered accidents from time to time in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain commercial general liability, workers’ compensation, business auto, commercial property, umbrella liability, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. Further, we have pollution legal liability coverage for our business entities, which would cover, among other things, third party liability and costs of clean up relating to environmental contamination on our premises while our equipment is in transit and on our customers’ job site. With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental clean‑up and liability to third parties arising from any surface or subsurface contamination. We also have certain specific coverages for some of our businesses, including our hydraulic fracturing services.

Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See “Risk Factors” for a description of certain risks associated with our insurance policies.

Environmental and Occupational Health and Safety Regulations

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, and occupational health and safety. Numerous federal, state and local governmental agencies issue regulations that often require difficult and costly compliance measures that could carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may, for example, restrict the types, quantities and concentrations of various substances that can be released into the environment, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, or require action to prevent or remediate pollution from current or former operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental, health and safety laws and regulations occur frequently, and any changes that result in more stringent and costly requirements could materially adversely affect our operations and financial position. We have not experienced any material adverse effect from compliance with these requirements, however, this trend may not continue in the future.

Below is an overview of some of the more significant environmental, health and safety requirements with which we must comply. Our customers’ operations are subject to similar laws and regulations. Any material adverse effect of these laws and regulations on our customers’ operations and financial position may also have an indirect material adverse effect on our operations and financial position.

Waste Handling. We handle, transport, store and dispose of wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws and regulations, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the U.S. Environmental Protection Agency (“EPA”) or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or recategorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and natural gas exploration, development and production wastes as hazardous wastes. Several environmental organizations have also petitioned the EPA to modify existing regulations to recategorize certain oil and natural gas exploration, development and production wastes as hazardous. Any such changes in these laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”) and analogous state laws generally impose liability without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state laws. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such hazardous substances have been released.

NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials (“NORM”) associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.

Water Discharges. The Clean Water Act, Safe Drinking Water Act, Oil Pollution Act and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Also, spill prevention, control and countermeasure plan requirements require appropriate containment berms and similar structures to help prevent the contamination of regulated waters.

Air Emissions. The Clean Air Act (“CAA”) and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other emissions control requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants from specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.

Climate Change. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gases (“GHG”) emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States. For example, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities, otherwise known as Subpart OOOOa. Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by some candidates seeking the office of the President of the United States in 2020. Some of these pledges have included calls to ban hydraulic fracturing, which could adversely impact our operations. Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result.

Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.

Endangered and Threatened Species. Environmental laws such as the Endangered Species Act (“ESA”) and analogous state laws may impact exploration, development and production activities in areas where we operate. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and various state analogs. The U.S. Fish and Wildlife Service (“FWS”) may identify previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas (including areas where our customers operate), was a candidate species for listing under the ESA by the FWS for many years. As a result of a recent settlement with the environmental groups, the FWS has agreed to act on a petition to list the dunes sagebrush lizard by June 30, 2020, which would result in a formal one-year review to consider listing the species if the petition is accepted. To the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.

Regulation of Hydraulic Fracturing and Related Activities. Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has previously issued a series of rules under

the CAA that establish new emission control requirements for certain oil and natural gas production and natural gas processing operations and associated equipment. There have been several attempts to modify or rescind such regulations and litigation is ongoing. Separately, the Bureau of Land Management (“BLM”) previously finalized a rule governing hydraulic fracturing on federal lands, but in June 2016, a federal district court judge in Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule. While this ruling was initially challenged, in December 2017, the BLM published a rulemaking to rescind the final rule and reinstate the regulations that existed immediately before the published effective date of the rule. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have previously been proposed in Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. For example, the United States Geological Survey identified eight states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, Arkansas, Ohio and Alabama. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells that impose permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission’s well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission has adopted similar rules. In addition, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. However, the EPA has imposed no regulatory limits as a result of this study.

Increased regulation of hydraulic fracturing and related activities (whether as a result of the EPA study results or resulting from other factors) could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.

OSHA Matters. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.

Employees

As of December 31, 2019, we employed approximately 2,200 people. None of our employees are represented by labor unions or subject to collective bargaining agreements.

Primarily as a result of the significant decline in oil prices and our customers’ rapid response to reduce their drilling and completion activities, we have implemented significant reductions in our workforce since December 31, 2019. As of June 10, 2020, we had approximately 700 employees.

Availability of Filings

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, are made available free of charge on our internet web site at www.propetroservices.com, as soon as reasonably practicable after we have electronically filed the material with, or

furnished it to, the SEC. The SEC maintains an internet site that contains our reports, proxy and information statements and our other SEC filings. The address of that web site is www.sec.gov. Please note that information contained on our website, whether currently posted or posted in the future, is not a part of this Annual Report or the documents incorporated by reference in this Annual Report.

Item 1A. Risk Factors.

The following is a description of significant factors that could cause actual results to differ materially from those contained in forward-looking statement made in this Annual Report and presented elsewhere by management from time to time. Such factors may have a material adverse effect on our business, financial condition and results of operations. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all our potential risks or uncertainties. Due to these, and other factors, past performance should not be considered an indication of future performance.

Our business and financial performance depends on the oil and natural gas industry and particularly on the level of capital spending and exploration and production activity within the United States and in the Permian Basin, and a decline in prices for oil and natural gas has had and may continue to have an adverse effect on our revenue, cash flows, profitability and growth.

Demand for most of our services depends substantially on the level of capital expenditures in the Permian Basin by companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of capital spending and activity in oil and gas exploration, development and production. Prolonged low oil and gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the hydraulic fracturing services that we provide. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. West Texas Intermediate (“WTI”) oil prices declined significantly in 2015 and 2016 to approximately $30 per barrel, but subsequently recovered in 2017 and 2018. However, in 2019, oil and natural gas prices were highly volatile. The average WTI oil prices per barrel was approximately $57, $65 and $51 for the years ended December 31, 2019, 2018 and 2017, respectively. Demand for our services is largely dependent on oil and natural gas prices, and our customers’ completion budgets and rig count. In March 2020, WTI oil prices declined significantly, to a low of approximately $20 per barrel towards the end of March 2020. On June 17, 2020 the WTI oil price was approximately $38 per barrel. The decline in and unpredictable nature of oil and natural gas prices have caused a reduction in our customers’ spending and associated drilling and completion activities, which has had and may continue to have an adverse effect on our revenue and cash flows. We are also experiencing pricing pressure on our services from substantially all of our customers which has decreased margins for us. If prices continue to decline or remain low and are highly unpredictable, additional declines in our customers’ spending would have a further adverse effect on our revenue, margins and cash flows. In addition, a worsening of these conditions may result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in further spending reductions, delays in the collection of amounts owed to us and similar impacts.

Many factors over which we have no control affect the supply of, and demand for our services, and our customers’ willingness to explore, develop and produce oil and natural gas, and therefore, influence prices for our services, including:


•	the severity and duration of world health events, including the recent COVID-19 pandemic, related economic repercussions and the resulting severe disruption in the oil and gas industry and negative impact on demand for oil and gas, which is negatively impacting our business;


•	the current significant surplus in the supply of oil and actions by the members of OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;


•	uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for crude oil and natural gas and therefore the demand for our services;


•	the domestic and foreign supply of, and demand for, oil and natural gas;


•	the level of prices, and expectations about future prices, of oil and natural gas;


•	the level of global oil and natural gas exploration and production;


•	the cost of exploring for, developing, producing and delivering oil and natural gas;


•	the supply of and demand for drilling and hydraulic fracturing equipment;


•	the expected decline rates of current production;


•	the price and quantity of foreign imports;


•	political and economic conditions in oil and natural gas producing countries and regions, including the United States, the Middle East, Africa, South America and Russia;


•	operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;


•	speculative trading in crude oil and natural gas derivative contracts;


•	the level of consumer product demand;


•	the discovery rates of new oil and natural gas reserves;


•	contractions in the credit market;


•	the strength or weakness of the U.S. dollar;


•	available pipeline and other transportation capacity;


•	the levels of oil and natural gas storage;


•	weather conditions and other natural disasters;


•	domestic and foreign tax policy;


•	domestic and foreign governmental approvals and regulatory requirements and conditions;


•	the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;


•	political or civil unrest in the United States or elsewhere;


•	technical advances affecting energy consumption;


•	the proximity and capacity of oil and natural gas pipelines and other transportation facilities;


•	the price and availability of alternative fuels;


•	the ability of oil and natural gas producers to raise equity capital and debt financing;


•	merger and divestiture activity among oil and natural gas producers; and


•	overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in March 2020, Saudi Arabia and Russia failed to agree on a plan to cut production of oil and gas within OPEC and Russia. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. These events, combined with the continued outbreak of COVID-19 that has reduced economic activity and disrupted the supply chain of certain of our customers, have contributed to a sharp drop in prices for oil in the first quarter of 2020, continuing into the second quarter. Regulatory action to curtail production has been contemplated; for example, the Texas Railroad Commission, which regulates the production of oil and gas in the state of Texas, held a hearing in April 2020 regarding potential production cuts for producers in Texas in light of the recent decline in oil prices globally. The Railroad Commission ultimately declined to institute mandatory production cuts, but the agency may choose to revisit the issue if market weakness persists, which could further reduce demand for our services. While an agreement to cut production was reached in April 2020, oil prices have remained low, and global oil demand is expected to remain challenged at least until the COVID-19 outbreak can be contained. The impacts of these price declines have had, and may continue to have, a material adverse effect on our business, results of operation and financial condition.

The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.

We derive our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have experienced, and may in the future experience, significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, the decline in and unpredictable nature of oil and gas prices in 2019 and early 2020, combined with adverse changes in the capital and credit markets and the COVID-19 outbreak in early 2020, caused many exploration and production companies to reduce their capital budgets and drilling activity. This has resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies can charge for their services. These factors have materially and adversely affected our business, results of operations and financial condition. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (for example, a day, a week or a month) for the actual period of time the service is provided to our customers. By contracting services on a short‑term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and resulting volatility in our revenues.

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.

We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or any other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, to address the COVID-19 outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees. For example, in response to COVID-19, we have reduced headcount, officer salaries and director compensation, closed yard locations, reduced third party expenses and streamlined operations, reduced capital expenditures and recorded impairment expenses.

The COVID-19 pandemic has spread across the globe and impacted financial markets and worldwide economic activity and adversely affected our operations. In addition, the effects of COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility, impacted the operations and activity levels of our customers and materially and adversely affected the demand for oilfield services. These factors may also negatively impact our current suppliers and their ability or willingness to provide the necessary equipment, parts or raw materials, and they may otherwise fail to deliver the products timely and in the quantities required. Any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. As the potential impact from COVID-19 is difficult to predict, the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our business, results of operations and financial condition.

Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.

A prolonged economic slowdown or recession in the United States, adverse events relating to the energy industry or regional, national and global economic conditions and factors, particularly a further slowdown in the exploration and production industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas and decreased prices for oil and natural gas. The COVID-19 pandemic and the recent turmoil between the members of OPEC+ have caused oil prices to fall substantially and have impacted the global economy; such factors have heightened the risk of a prolonged economic slowdown or recession in the United States.

The majority of our operations are located in the Permian Basin, making us vulnerable to risks associated with operating in one major geographic area.

Our operations are geographically concentrated in the Permian Basin. For the years ended December 31, 2019, 2018 and 2017, approximately 99.4%, 99.0% and 97.0%, respectively, of our revenues were attributable to our operations

in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Permian Basin caused by significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.

We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our business, results of operations and financial condition.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re‑market or otherwise use the production could have a material adverse effect on our business, results of operations and financial condition. In weak economic environments, we may experience increased delays and failures to pay due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets or other sources of capital. The decline in and unpredictable nature of oil and gas prices in 2019 and 2020 has negatively impacted the financial condition and liquidity of our customers, and future declines, sustained lower prices, or continued volatility could impact their ability to meet their financial obligations to us. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, results of operations, and financial condition.

We face significant competition that may cause us to lose market share, and competition in our industry has intensified during the industry downturn.

The oilfield services industry is highly competitive and has relatively few barriers to entry. The principal competitive factors impacting sales of our services are price, reputation and technical expertise, equipment and service quality and health and safety standards. The market is also fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. For instance, our larger competitors may offer services at below‑market prices or bundle ancillary services at no additional cost to our customers. We compete with large national and multi‑national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis.

Some jobs are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. The amount of equipment available may exceed demand, which could result in active price competition. In addition, some exploration and production companies have commenced completing their wells using their own hydraulic fracturing equipment and personnel. Any increase in the development and utilization of in‑house fracturing capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

Pressure on pricing for our services resulting from the industry downturn has impacted, and may continue to impact, our ability to maintain utilization and pricing for our services or implement price increases. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results of operations. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial condition and results of operations.

Furthermore, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. We cannot assure that we will be able to maintain our competitive position.

New technology may cause us to become less competitive.

The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent or other intellectual property protections. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to develop, implement or acquire and deploy certain technology improvements at a substantial cost, such as our new DuraStim® fleets or the cost of implementing or purchasing a technology like the new DuraStim® fleets may be substantially higher than anticipated, and we may not be able to successfully implement the DuraStim® fleets or other technologies we may purchase. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies could have a material adverse effect on our business, financial condition, prospects or results of operations.

Our business depends upon our ability to obtain specialized equipment, parts and key raw materials, including frac sand and chemicals, from third‑party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

We purchase specialized equipment, parts and raw materials (including, for example, frac sand, chemicals and fluid ends) from third party suppliers and affiliates. At times during the business cycle, there is a high demand for hydraulic fracturing and other oilfield services and extended lead times to obtain equipment and raw materials needed to provide these services. Should our current suppliers be unable or unwilling to provide the necessary equipment, parts or raw materials or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, future price increases for this type of equipment, parts and raw materials could negatively impact our ability to purchase new equipment, to update or expand our existing fleets, to timely repair equipment in our existing fleets or meet the current demands of our customers. In addition, the COVID-19 pandemic may have a negative impact on our suppliers’ ability or willingness to provide necessary equipment, parts or raw materials, and they may otherwise fail to deliver the products timely and in the quantities required.

We may be required to pay fees to certain of our sand suppliers based on minimum volumes under long-term contracts regardless of actual volumes received.

We enter into purchase agreements with our sand suppliers (the “Sand suppliers”) to secure supply of sand as part of its normal course of business. The agreements with the Sand suppliers require that we purchase a minimum volume of sand, constituting substantially all of its sand requirements, from the Sand suppliers, otherwise certain penalties may be charged. Under certain of the purchase agreements, a shortfall fee applies if we purchase less than the minimum volume of sand. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Under one of the purchase agreements, we are obligated to purchase a specified percentage of our overall sand requirements, or we must pay the supplier the difference between the purchase price of the minimum volumes under the purchase agreement and the purchase price of the volumes actually purchased. Our minimum volume commitments under the purchase agreements are either based on a percentage of our total usage or fixed minimum quantity. Our agreements with the Sand suppliers expire at different times prior to April 30, 2022.

If the activity level of our customers declines and the demand for our services is materially and adversely affected, we may be required to pay for more sand from our Sand suppliers than we need in the performance of our services, regardless of whether we take physical delivery of such sand. In such an event, we may be required to pay shortfall fees or other penalties under the purchase agreements, which could have a material adverse effect on our business, financial condition, or results of operations. The decrease in our customers’ activity resulting from the COVID-19 pandemic and recent turmoil between the members of OPEC+, among other factors, has heightened the risk that we may be required to pay shortfall fees or other penalties to the Sand suppliers in the future.

Reliance upon a few large customers may adversely affect our revenue and operating results.

The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services with recurring customers and the limited availability of our fracturing units, we have had some degree of customer concentration. Our top ten customers represented approximately 95.5%, 85.5% and 87.0% of our consolidated revenue for the years ended December 31, 2019, 2018 and 2017, respectively. It is likely that we will depend on a relatively small number of customers for a significant portion of our revenue in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.

Certain of our completion services, particularly our hydraulic fracturing services, are substantially dependent on the availability of water. Restrictions on our or our customers’ ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of unconventional shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Over the past several years, certain of the areas in which we and our customers operate have experienced extreme drought conditions and competition for water in such areas is growing. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. For instance, some states require E&P companies to report certain information regarding the water they use for hydraulic fracturing and to monitor the quality of groundwater surrounding some wells stimulated by hydraulic fracturing. Generally, our water requirements are met by our customers from sources on or near their sites, but there is no assurance that our customers will be able to obtain a sufficient supply of water from sources in these areas. Our or our customers’ inability to obtain water from local sources or to effectively utilize flowback water could have an adverse effect on our financial condition, results of operations and cash flows.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, such as our Chief Executive Officer, Chief Operating Officer, Senior Vice President of Operations, Chief Financial Officer, Chief Strategy and Administrative Officer, Chief Accounting Officer and General Counsel could disrupt our operations. We do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.

The delivery of our services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. As a result of the downturn in the oil and gas industry resulting from the COVID-19 pandemic and recent turmoil between the members of OPEC+, among other factors, we have made reductions in the size of workforce due to reduced demand for our services. If demand for our services increases, we may experience difficulty in hiring or re-hiring skilled and unskilled workers in the future to meet that demand. At times, the demand for skilled workers in our geographic areas of operations is high, and the supply is limited. As a result, competition for experienced oilfield service personnel is intense, and we face significant challenges in competing for crews and management with large and well‑established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. Furthermore, a significant decrease in the wages paid by us or our competitors as a result of reduced industry demand could result in a reduction of the available skilled labor force, and there is no assurance that the availability of skilled labor will improve following a subsequent increase in demand for our services or an increase in wages. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could limit our ability to grow.

The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures incurred were approximately $400.7 million, $592.6 million and $305.3 million during the years ended December 31, 2019, 2018 and 2017. We have historically financed capital expenditures primarily with funding from cash on hand, cash flow from operations, equipment and vendor financing and borrowings under our credit facility. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment or properly maintaining our existing equipment. With the current depressed oil and gas market conditions, our remaining availability under our ABL Credit Facility will be adversely impacted by the expected decline in our customers’ activity and we may be unable to borrow under our ABL Credit Facility if our eligible accounts receivable continues to decline. Further, any disruptions or continuing volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. For example, our borrowing base declined from $181.2 million as of December 31, 2019 to approximately $16.8 million as of June 19, 2020 due to decreased activity levels and the resulting decrease to our eligible accounts receivable. Based on current and expected market conditions and customer activity levels, we expect our borrowing base to materially decline further in the near term. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, geopolitical issues, public health crises (including the COVID-19 pandemic), interest rates, inflation, the availability and cost of credit and the United States and foreign financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices, including the significant decline in WTI oil prices beginning February 2020. The decline in and unpredictable nature of oil and natural gas prices have caused a reduction in our customers’ spending and associated drilling and completion activities, which had and may continue to have an adverse effect on our revenue and cash flows. If the current economic climate in the United States or abroad continues, deteriorates further or remains uncertain, worldwide demand for petroleum products could diminish further, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and adversely impact our results of operations, liquidity and financial condition.

Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:


•	increasing our vulnerability to general adverse economic and industry conditions;


•	the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;


•	our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;


•	any failure to comply with the financial or other debt covenants, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;


•	our level of debt could impair our ability to obtain additional financing, or obtain additional financing on favorable terms, in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and


•	our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.

Restrictions in our ABL Credit Facility (as defined herein) and any future financing agreements may limit our ability to finance future operations or capital needs or capitalize on potential acquisitions and other business opportunities.

The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our ABL Credit Facility restricts or limits our ability to:


•	grant liens;


•	incur additional indebtedness;


•	engage in a merger, consolidation or dissolution;


•	enter into transactions with affiliates;


•	sell or otherwise dispose of assets, businesses and operations;


•	materially alter the character of our business as currently conducted; and


•	make acquisitions, investments and capital expenditures.

Furthermore, our ABL Credit Facility contains certain other operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the ABL Credit Facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our ABL Credit Facility, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. Further, our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable. Changes to our operational activity levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. For example, our borrowing base declined from $181.2 million as of December 31, 2019 to approximately $16.8 million as of June 19, 2020 due to decreased activity levels and the resulting decrease to our eligible accounts receivable. Based on current and expected market conditions and customer activity levels, we expect our borrowing base to materially decline further in the near term. If our borrowing base is reduced below the amount of our outstanding borrowings, we will be required to repay the excess borrowings immediately on demand by the lenders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our ABL Credit Facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility and Other Financing Arrangements.”

We may become more leveraged and our indebtedness could adversely affect our operations and financial condition.

Our business is capital intensive and we may seek to raise debt capital to fund our business and growth strategy. Indebtedness could have negative consequences that could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, such as:


•	requiring us to dedicate a substantial portion of our cash flow from operating activities to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, research and development efforts, potential strategic acquisitions and other general corporate purposes;


•	limiting our ability to obtain additional financing to fund growth, working capital or capital expenditures, or to fulfill debt service requirements or other cash requirements;


•	increasing our vulnerability to economic downturns and changing market conditions; and


•	placing us at a competitive disadvantage relative to competitors that have less debt.

Furthermore, interest rates on future indebtedness could be higher than current levels, causing our financing costs to increase accordingly. In addition, LIBOR and other “benchmark” rates are subject to ongoing national and international regulatory scrutiny and reform. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At this time, no consensus exists as to what rate or rates may become acceptable alternatives to LIBOR and we are unable to predict the effect of any such alternatives on our business and results of operations. However, if LIBOR is phased out without a replacement benchmark, our only option under the ABL Credit Facility will be to borrow at the Base Rate (as defined in the ABL Credit Facility) until an alternative benchmark rate is selected. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt.

We may record losses or impairment charges related to goodwill and long-lived assets.

Changes in future market conditions and prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses in our results of operations. These events could result in the recognition of impairment charges or losses from asset sales that negatively impact our financial results. Significant impairment charges or losses from asset sales as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. For example, in 2019, we recorded an impairment charge related to our drilling and flowback assets of $3.4 million. If the depressed oil and natural gas prices continue to trade at depressed price levels as experienced in the beginning of March 2020, and our equipment remains idle or under-utilized, the estimated fair value of such equipment may decline, which will result in additional impairment expense in the future.

During the first quarter of 2020, management determined the reductions in commodity prices driven by the potential impact of the novel COVID-19 virus and global supply and demand dynamics coupled with the sustained decrease in the Company’s share price were triggering events for goodwill and asset impairment. As a result of the triggering events, we performed an interim goodwill impairment test on the hydraulic fracturing reporting unit and a recoverability tests on each of the assets groups. As a result, we expect to recognize impairments and charges in the first quarter of 2020 as follows:


•	goodwill impairment of approximately $9.4 million;


•	drilling asset group impairment of approximately $1.1 million as a result of our recoverability tests; and


•	write-off of $6.1 million of deposits related to options to purchase additional DuraStim® equipment for which options expire at various times through the end of April 2021 as it is not probable we would exercise our options due to the events described above.

If the depressed oil prices and the current economic conditions continue for a longer period of time, actual results may differ from estimates and future assumptions may change resulting in additional impairment charges in the future.

Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry, for which we may not be adequately insured and which could cause us to lose customers and substantial revenue.

Our operations are exposed to the risks inherent to our industry, such as equipment defects, vehicle accidents, worksite injuries to our or third-party personnel, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards, such as oil spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. In addition, our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean‑up responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations or the loss of

customers. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.

Our insurance may not be adequate to cover all losses or liabilities we may suffer. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub‑limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean‑up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

A terrorist attack, armed conflict or political or civil unrest could harm our business.

Terrorist activities, anti‑terrorist efforts, other armed conflicts and political or civil unrest could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. Terrorist activities, the threat of potential terrorist activities, political or civil unrest and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

In connection with our business operations, including the transportation and relocation of our hydraulic fracturing equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the DOT and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials. Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Certain motor vehicle operators require registration with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.

We are subject to environmental laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.

The nature of our operations, including the handling, transporting and disposing of a variety of fluids and substances, including hydraulic fracturing fluids and other regulated substances, air emissions, and wastewater discharges exposes us to some risks of environmental liability, including the release of pollutants from oil and natural gas wells and associated equipment to the environment. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against us for personal injury or property damage allegedly caused by the release of pollutants into the environment. Environmental laws and regulations have changed in the past, and they may change in the future and become more stringent. Current and future claims and liabilities may have a material adverse effect on us because of potential adverse outcomes, defense costs, diversion of management resources, unavailability of insurance coverage and other factors. The ultimate costs of these liabilities are difficult to determine and may exceed any reserves we may have established. If existing environmental requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. For example, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities, otherwise known as Subpart OOOOa. Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy

companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation and financial risks may result in our oil and natural gas customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has previously issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. There have been several attempts to modify or rescind such regulations, and litigation is ongoing. Separately, the BLM finalized a rule governing hydraulic fracturing on federal lands but this rule was subsequently rescinded. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. For example, the United States Geological Survey identified eight states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, Arkansas, Ohio and Alabama. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission released well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission has adopted similar rules. In addition, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. However, the EPA has imposed no regulatory limits as a result of this study.

Increased regulation of hydraulic fracturing and related activities (whether as a result of the EPA study results or resulting from other factors) could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.

Conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The commercial development of economically‑viable alternative energy sources and related products (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could have a similar effect. In addition, certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development, including the allowance of percentage depletion for oil and natural gas properties, may be eliminated as a result of proposed legislation. Any future decreases in the rate at which oil and natural gas reserves are discovered or developed, whether due to the passage of legislation, increased governmental regulation leading to limitations, or prohibitions on exploration and drilling activity, including hydraulic fracturing, or other factors, could have a material adverse effect on our business and financial condition, even in a stronger oil and natural gas price environment.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

We operate with most of our customers under master service agreements (“MSAs”). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and process and record operational and accounting data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary information, personal information and other data, or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses we

may experience as a result of the realization of such risks. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate the effects of cyber incidents.

We may grow through acquisitions and our failure to properly plan and manage those acquisitions may adversely affect our performance.

We have completed and may in the future pursue, asset acquisitions or acquisitions of businesses. Any acquisition of assets or businesses involves potential risks, including the failure to realize expected profitability, growth or accretion; environmental or regulatory compliance matters or liability; title or permit issues; the incurrence of significant charges, such as impairment of goodwill, or property, plant and equipment or restructuring charges; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may also involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount of time and resources and may divert management’s attention from existing operations or other priorities.

We must plan and manage any acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. Any failure to manage acquisitions effectively or integrate acquired assets or businesses into our existing operations successfully, or to realize the expected benefits from an acquisition or minimize any unforeseen operational difficulties, could have a material adverse effect on our business, financial condition, prospects or results of operations.

Our ability to use our net operating loss carryforwards may be limited.

As of December 31, 2019, we had approximately $304.7 million of federal net operating loss carryforwards some of which will begin to expire in 2035. After January 1, 2018, federal net operating loss carryforwards can be carried forward indefinitely. Approximately $229.5 million of our federal net operating loss carryforward relates to pre-2018 periods which are not subject to an annual 80% limitation of taxable income. Our state net operating losses is approximately $50.4 million and will begin to expire in 2024. Utilization of these net operating loss carryforwards (“NOLs”) depends on many factors, including our future income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382). Generally, a change of more than 50% in the ownership of a corporation’s stock, by value, over a three‑year period constitutes an ownership change for U.S. federal income tax purposes. Any unused annual limitation may, subject to certain limitations, be carried over to later years. We may experience ownership changes, which may result in annual limitation under Section 382 determined by multiplying the value of our stock at the time of the ownership change by the applicable long‑term tax‑exempt rate as defined in Section 382, increased under certain circumstances as a result of recognizing built‑in gains in our assets existing at the time of the ownership change. The limitations arising from ownership changes may prevent utilization of our NOLs prior to their expiration. Future ownership changes or regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows if we attain profitability.

The SEC’s pending investigation, the Logan Lawsuit, the Boca Raton Lawsuit, and the Chang Lawsuit could have a material adverse effect on our business, financial condition, results of operation, and cash flows.

In September 2019, a complaint, captioned Richard Logan, Individually and On Behalf of All Others Similarly Situated, Plaintiff, v. ProPetro Holding Corp., et al., (the “Logan Lawsuit”), was filed against the Company and certain of its current and former officers and directors in the U.S. District Court for the Western District of Texas.

In April 2020, Lead Plaintiffs Nykredit Portefølje Administration A/S, Oklahoma Firefighters Pension and Retirement System, Oklahoma Law Enforcement Retirement System, Oklahoma Police Pension and Retirement System, and Oklahoma City Employee Retirement System, and additional named plaintiff Police and Fire Retirement System of the City of Detroit, individually and on behalf of a putative class of shareholders who purchased the Company’s common stock between March 17, 2017 and March 13, 2020, filed a second amended class action complaint in the U.S. District Court for the Western District of Texas in the Logan Lawsuit, alleging violations of Sections 10(b) and 20(a) of the Exchange Act, as amended, and Rule l0b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act, as amended, based on allegedly inaccurate or misleading statements, or omissions of material facts, about the Company’s business, operations and prospects.

In January 2020, Boca Raton Firefighters’ and Police Pension Fund (“Boca Raton”) filed a shareholder derivative suit in the U.S. District Court for the Western District of Texas (the “Boca Raton Lawsuit”) against certain of the

Company’s current and former officers and directors (the “Boca Raton Defendants”). The Company was named as a nominal defendant only. The claims include (i) breaches of fiduciary duties, (ii) unjust enrichment and (iii) contribution. Boca Raton did not quantify any alleged damages in its complaint but, in addition to attorneys’ fees and costs, Boca Raton seeks various forms of relief, including (i) damages sustained by the Company as a result of the Boca Raton Defendants’ alleged misconduct, (ii) punitive damages and (iii) equitable relief in the form of improvements to the Company’s governance and controls.

In April 2020, Jye-Chun Chang filed a shareholder derivative suit in the U.S. District Court for the Western District of Texas (the “Chang Lawsuit”) against certain of the Company’s current and former officers and directors (the “Chang Defendants”). The Company was named as a nominal defendant only. The claims include (i) violations of section 14(a) of the Exchange Act, (ii) breach of fiduciary duties, (iii) unjust enrichment, (iv) abuse of control, (v) gross mismanagement and (vi) waste of corporate assets. Chang did not quantify any alleged damages in its complaint but, in addition to attorneys’ fees and costs, Chang seeks various forms of relief, including (i) declaring that Chang may sustain the action on behalf of the Company, (ii) declaring that the Chang Defendants breached their fiduciary duties to the Company, (iii) damages sustained by the Company as a result of the Chang Defendants’ alleged misconduct, (iv) equitable relief in the form of improvements to the Company’s governance and controls and (v) restitution.

In October 2019, the Company received a letter from the SEC indicating that the SEC has opened an investigation into the Company and requesting that the Company provide information and documents, including documents related to the Expanded Audit Committee Review and related events.

We are presently unable to predict the duration, scope or result of the SEC’s investigation, the Logan Lawsuit, the Boca Raton Lawsuit, the Chang Lawsuit, or any other related lawsuit or investigation.

The ongoing SEC investigation, the Logan Lawsuit, the Boca Raton Lawsuit, the Chang Lawsuit and any related future litigation give rise to risks and uncertainties that could adversely affect our business, results of operations and financial condition. Such risks and uncertainties include, but are not limited to, uncertainty as to the scope, timing and ultimate findings of the matters under review by the SEC; adverse effects of the investigation, including the potential impact to the Company or members of its management team in the event of an adverse outcome and on the market price of the Company’s common stock; the costs and expenses of the SEC investigation, the Logan Lawsuit, the Boca Raton Lawsuit, and the Chang lawsuit including legal fees and possible monetary penalties in the event of an adverse outcome; the risk of additional potential litigation or regulatory action arising from these matters, including the Logan Lawsuit, the Boca Raton Lawsuit, and the Chang Lawsuit; the timing of the review by, and the conclusions of, the Company’s independent registered public accounting firm regarding these matters; the potential identification of additional deficiencies in internal controls over financial reporting or disclosure controls and procedures and the impact of the same; and potential reputational damage that the Company may suffer as a result of these matters.

The SEC has a broad range of civil sanctions available should it commence an enforcement action, including injunctive relief, disgorgement, fines, penalties, or an order to take remedial action. The imposition of any of these sanctions, fines, or remedial measures could have a material adverse effect on our business, results of operation and financial condition.

The outcome of the Logan Lawsuit, the Boca Raton Lawsuit, the Chang Lawsuit or any other litigation is necessarily uncertain. We could be forced to expend significant resources in the defense of these lawsuits or future ones, and we may not prevail.

We maintain director and officer insurance; however, our insurance coverage is subject to certain exclusions (including, for example, any required SEC disgorgement or penalties) and we are responsible for meeting certain deductibles under the policies. Moreover, we cannot assure you that our insurance coverage will adequately protect us from claims made in the Logan Lawsuit, the Boca Raton Lawsuit, the Chang Lawsuit, the SEC investigation or any future claims. Further, as a result of the pending litigation and investigation the costs of insurance may increase and the availability of coverage may decrease. As a result, we may not be able to maintain our current levels of insurance at a reasonable cost, or at all.

We have identified material weaknesses in our internal control over financial reporting and may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our periodic reporting obligations.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”). Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. As disclosed in Item 9A, following the filing of our Annual Report on Form 10-K for the year ended December 31, 2018, management identified certain material weaknesses in our internal control over financial reporting that existed as of December 31, 2018 relating to related party transactions and other areas, which resulted in the failure of the following COSO principles: (i) the organization demonstrates commitment to integrity and ethical values; (ii) the board of directors demonstrates independence from management and exercises oversight of the development and performance of internal control; (iii) management establishes, with board oversight, structures, reporting lines, and appropriate authorities and responsibilities in pursuit of objectives; (iv) the organization demonstrates a commitment to attract, develop, and retain competent individuals in alignment with objectives; (v) the organization holds individuals accountable for their internal control related responsibilities in the pursuit of objectives; (vi) the organization internally communicates information, including objectives and responsibilities for internal control, necessary to support the functioning of internal control; (vii) the organization communicates with external parties regarding matters affecting the functioning of internal control; (viii) the organization selects and develops control activities that contribute to the mitigation of risks to the achievement of objectives to acceptable levels; (ix) the organization deploys control activities through policies that establish what is expected and procedures that put policies into action; and (x) controls designed to sufficiently identify, evaluate, and disclose related party transactions. A material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. As such, management concluded that we did not design and implement effective control activities based on the criteria established in the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in “2013 Internal Control-Integrated Framework.” As a result of these material weaknesses, the COSO components of Control Environment, Information and Communication and Control Activities were not present and functioning.

We have begun taking steps to implement controls to remediate the material weaknesses, including: (i) appointing new executive officers with extensive public company experience to improve the tone at the top, communication with the Board and compliance with policies within the Company; (ii) enhancing certain policies of the Company, including the Code of Ethics and Conduct, Expense Reimbursement, Travel and Entertainment, and Delegation of Responsibilities and Authority policies and enhancing monitoring of compliance with such policies; (iii) designing and implementing control activities related to transactions involving potential conflicts of interest and related parties, and evaluation of whistleblower allegations; and (iv) forming a disclosure committee and appointing a Chief Disclosure Officer to provide improved corporate governance related to disclosures the Company provides to the public and other external parties.

The material weaknesses described above or any newly identified material weakness could limit our ability to prevent or detect a misstatement of our accounts or disclosures that could result in a material misstatement of our annual or interim financial statements. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the control deficiencies that led to the material weaknesses in our internal control over financial reporting described above or to avoid potential future material weaknesses.

Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. If we are unable to successfully remediate our existing material weaknesses or any future material weakness in our internal control over financial reporting, or identify any additional material weaknesses that may exist, the accuracy and timing of our financial reporting may be adversely affected, we may be unable to maintain compliance with securities law requirements regarding timely filing of periodic reports in addition to applicable stock exchange listing requirements, we may be unable to prevent fraud, investors may lose confidence in our financial reporting, we may lose customers, our ability to obtain financing may be reduced, and our stock price may decline as a result, each of which could have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. For example, as a result of the ineffective control environment and other related matters, the Company did not timely file its Quarterly Reports on Form

10-Q for the quarters ended June 30, 2019, September 30, 2019 and March 31, 2020 and its Annual Report on Form 10-K for the year ended December 31, 2019.

Certain provisions of our certificate of incorporation, bylaws and stockholder rights plan, as well as Delaware law, may discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our certificate of incorporation authorizes our board of directors (the “Board”) to issue preferred stock without shareholder approval. If our Board elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders, including:


•	limitations on the removal of directors;


•	limitations on the ability of our shareholders to call special meetings;


•	advance notice provisions for shareholder proposals and nominations for elections to the Board to be acted upon at meetings of shareholders;


•	providing that the Board is expressly authorized to adopt, or to alter or repeal our bylaws; and


•	establishing advance notice and certain information requirements for nominations for election to our Board or for proposing matters that can be acted upon by shareholders at shareholder meetings.

In addition, our Board adopted a short-term stockholder rights plan that would likely discourage a hostile attempt to acquire control of us.

Our business could be negatively affected as a result of the actions of activist shareholders.

Publicly traded companies have increasingly become subject to campaigns by investors seeking to increase shareholder value by advocating corporate actions such as financial restructuring, increased borrowing, special dividends, stock repurchases, sales of assets or even sale of the entire company. Given our shareholder composition and other factors, it is possible such shareholders or future activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by such activist shareholders or others in the future would be costly and time-consuming, disrupt our operations and divert the attention of our Board and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the Board may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our business, financial condition, revenues, results of operations and cash flows could be adversely affected.

Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and

regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.

The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our certificate of incorporation to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation regarding exclusive forum. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

The New York Stock Exchange could commence procedures to delist our common stock, in the event we do not timely file all required periodic reports with the SEC, in which case the market price of our shares might decline and become more volatile and our stockholders’ ability to trade in our stock could be adversely affected.

As a result of our failure to timely file our Quarterly Reports on Form 10-Q for the three months ended June 30, 2019, for the three months ended September 30, 2019 and Annual Report on Form 10-K for the year ended December 31, 2019 with the SEC, as previously disclosed, on August 15, 2019 we received a notice from the New York Stock Exchange (the “NYSE”) informing us that we were not in compliance with the NYSE’s continued listing requirements under the timely filing criteria set forth in Section 802.01E of the NYSE Listed Company Manual as a result of our failure to timely file our Quarterly Report on Form 10-Q for the three months ended June 30, 2019. Under the NYSE rules, we were provided with six months from August 15, 2019 to file the delinquent Quarterly Report on Form 10-Q for the three months ended June 30, 2019. On February 14, 2020, the NYSE granted us an additional extension to July 15, 2020 to file our all delinquent Quarterly and Annual Reports. Subsequently, we have failed to timely file our Quarterly Report for the three months ended March 31, 2020. While we intend to become current before July 15, 2020, we remain subject to the procedures set forth in the NYSE’s listing standards related to late filings and subject to the risk of delisting. If our common stock were delisted, there could be no assurance whether or when it would again be listed for trading on NYSE or any other exchange. Further, the market price of our shares might decline and become more volatile, and our stockholders may find that their ability to trade in our stock would be adversely affected. Furthermore, institutions whose charters do not allow them to hold securities in unlisted companies might sell our shares, perhaps very promptly, which could have a further adverse effect on the price of our stock.

The market price of our common stock is subject to volatility.

The market of our common stock could be subject to wide fluctuations in response to, and the level of trading of our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our limited trading volume, the concentration of holdings or our common stock, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this report. Significant sales of our common stock, or the expectation of these sales, by significant shareholders, officers or directors could materially and adversely affect the market price of our common stock.

There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.

We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the

sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Our corporate headquarters is located at 1706 S. Midkiff, Midland, Texas 79701. In addition to our headquarters, we also own and lease other properties that are used for field offices, yards or storage in the Permian Basin. We believe that our facilities are adequate for our current operations.

Item 3. Legal Proceedings.

In September 2019, a complaint, captioned Richard Logan, Individually and On Behalf of All Others Similarly Situated, Plaintiff, v. ProPetro Holding Corp., et al., was filed against the Company and certain of its current and former officers and directors in the U.S. District Court for the Western District of Texas.

In January 2020, Boca Raton Firefighters’ and Police Pension Fund filed a shareholder derivative suit in the U.S. District Court for the Western District of Texas against certain of the Company’s current and former officers and directors. The Company was named as a nominal defendant only. The claims include (i) breaches of fiduciary duties, (ii) unjust enrichment and (iii) contribution. Boca Raton did not quantify any alleged damages in its complaint but, in addition to attorneys’ fees and costs, Boca Raton seeks various forms of relief, including (i) damages sustained by the Company as a result of the Boca Raton Defendants’ alleged misconduct, (ii) punitive damages and (iii) equitable relief in the form of improvements to the Company’s governance and controls.

In April 2020, Jye-Chun Chang filed a shareholder derivative suit in the U.S. District Court for the Western District of Texas against certain of the Company’s current and former officers and directors. The Company was named as a nominal defendant only. The claims include (i) violations of section 14(a) of the Exchange Act, (ii) breach of fiduciary duties, (iii) unjust enrichment, (iv) abuse of control, (v) gross mismanagement and (vi) waste of corporate assets. Chang did not quantify any alleged damages in its complaint but, in addition to attorneys’ fees and costs, Chang seeks various forms of relief, including (i) declaring that Chang may sustain the action on behalf of the Company, (ii) declaring that the Chang Defendants breached their fiduciary duties to the Company, (iii) damages sustained by the Company as a result of the Chang Defendants’ alleged misconduct, (iv) equitable relief in the form of improvements to the Company’s governance and controls and (v) restitution.

From time to time, we may be subject to various other legal proceedings and claims incidental to or arising in the ordinary course of our business.

Item 4. Mine and Safety Disclosures

None.

Part II


Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

On March 22, 2017, we consummated our initial public offering (“IPO”) of our common stock at a price of $14.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol “PUMP”.

Holders

As of December 31, 2019, there were 100,624,099 shares of common stock outstanding, held of record by 4 holders. The number of record holders of our common stock does not include Depository Trust Company participants or beneficial owners holding shares through nominee names.

Dividend

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business and repay borrowings under our ABL Credit Facility. Our future dividend policy is within the discretion of our Board and will depend upon then‑existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our Board may deem relevant. In addition, our ABL Credit Facility places restrictions on our ability to pay cash dividends.

Performance Graph

The quarterly changes for the periods shown in the following graph are based on the assumption that $100 had been invested in our common stock, the Russell 2000 Index (“Russell 2000”) and a self-constructed peer group index of comparable companies (“Peer Group”) on March 17, 2017 (the first trading date of our common stock), and that all dividends were reinvested at the closing prices of the dividend payment dates. The relevant companies included in our Peer Group consists of Liberty Oilfield Services, Inc., Nextier Oilfield Solution Inc., RPC, Inc., Calfrac Well Services Ltd., Patterson-UTI Energy, Inc. and Mammoth Energy Services, Inc. Subsequent measurement points are the last trading days of each quarter. We did not provide a five-year graph because we became a publicly traded company in March of 2017. The total cumulative dollar returns shown on the graph represent the value that such investments would have had on the last trading date of 2019. The calculations exclude trading commissions and taxes. The stock price performance on the following graph and table is not necessarily indicative of future stock price performance.



Date	Peer Group		Russell 2000		ProPetro Holding Corp.
3/17/2017	$	100.0	$	100.0	$	100.0
3/31/2017	$	97.0	$	100.1	$	88.9
6/30/2017	$	93.2	$	102.6	$	96.3
9/29/2017	$	105.2	$	108.4	$	99.0
12/29/2017	$	114.3	$	112.0	$	139.0
3/29/2018	$	91.0	$	111.9	$	109.6
6/29/2018	$	86.9	$	120.6	$	108.1
9/28/2018	$	85.1	$	124.9	$	113.7
12/31/2018	$	52.9	$	99.7	$	85.0
3/31/2019	$	65.2	$	114.2	$	155.4
6/30/2019	$	47.5	$	116.6	$	142.8
9/30/2019	$	35.1	$	113.8	$	62.7
12/31/2019	$	38.8	$	125.1	$	77.6

Item 6. Selected Historical Financial Data.

The following table presents the available selected historical financial data of ProPetro Holding Corp. for the years indicated. There were no factors that materially affect the comparability of the information in the selected historical financial data presented, except for the purchase of certain pressure pumping assets (510,000 HHP) and real property from Pioneer and Pioneer Pressure Pumping Services, LLC, consummated on December 31, 2018 (the “Pioneer Pressure Pumping Acquisition”) and expansion of our fleet size over the years presented, that has resulted in higher revenues and profitability.

The selected historical consolidated financial and operating data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this Annual Report on Form 10-K.



(In thousands, except for per share data)
	Year Ended December 31,
	2019			2018			2017			2016			2015
Statement of Operations Data:
Revenue:
Pressure pumping	$	2,001,627		$	1,658,403		$	945,040		$	409,014		$	510,198
All other	50,687			46,159			36,825			27,906			59,420
Total revenue	2,052,314			1,704,562			981,865			436,920			569,618
Costs and Expenses:
Cost of services⁽¹⁾	1,470,356			1,270,577			813,823			404,140			483,338
General and administrative⁽²⁾	105,076			53,958			49,215			26,613			27,370
Depreciation and amortization	145,304			88,138			55,628			43,542			50,134
Impairment expense	3,405			—			—			7,482			36,609
Loss on disposal of assets	106,811			59,220			39,086			22,529			21,268
Total costs and expenses	1,830,952			1,471,893			957,752			504,306			618,719
Operating Income (Loss)	221,362			232,669			24,113			(67,386		)	(49,101		)
Other Income (Expense):
Interest expense	(7,141		)	(6,889		)	(7,347		)	(20,387		)	(21,641		)
Gain on extinguishment of debt	—			—			—			6,975			—
Other expense	(717		)	(663		)	(1,025		)	(321		)	(499		)
Total other income (expense)	(7,858		)	(7,552		)	(8,372		)	(13,733		)	(22,140		)
Income (loss) before income taxes	213,504			225,117			15,741			(81,119		)	(71,241		)
Income tax (expense) benefit	(50,494		)	(51,255		)	(3,128		)	27,972			25,388
Net income (loss)	$	163,010		$	173,862		$	12,613		$	(53,147	)	$	(45,853	)

Share Information:
Net income (loss) per common share:
Basic	$	1.62		$	2.08		$	0.17		$	(1.19	)	$	(1.31	)
Diluted	$	1.57		$	2.00		$	0.16		$	(1.19	)	$	(1.31	)
Weighted average common shares outstanding:
Basic	100,472			83,460			76,371			44,787			34,993
Diluted	103,750			87,046			79,583			44,787			34,993

Balance Sheet Data as of:
Cash and cash equivalents	$	149,036		$	132,700		$	23,949		$	133,596		$	34,310
Property and equipment — net	$	1,047,535		$	912,846		$	470,910		$	263,862		$	291,838
Total assets	$	1,436,111		$	1,274,522		$	719,032		$	541,422		$	446,454
Long-term debt — net	$	130,000		$	70,000		$	57,178		$	159,407		$	236,876
Total shareholders’ equity	$	969,305		$	797,355		$	413,252		$	221,009		$	69,571

Cash Flow Statement Data:
Net cash provided by operating activities	$	455,290		$	393,079		$	109,257		$	10,659		$	81,230
Net cash used in investing activities	$	(495,299	)	$	(280,604	)	$	(281,469	)	$	(41,688	)	$	(62,776	)
Net cash provided by (used in) financing activities	$	56,345		$	(3,724	)	$	62,565		$	130,315		$	(15,216	)


(1)	Exclusive of depreciation and amortization.


(2)	Inclusive of stock‑based compensation.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forward‑looking statements that involve risks and uncertainties. You should read the “Risk Factors” section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward‑looking statements contained in the following discussion and analysis.

Basis of Presentation

This discussion of our results of operations omits our results of operations for the year ended December 31, 2017 and the comparison of our results of operations for the years ended December 31, 2018 and 2017, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 1, 2019.

Unless otherwise indicated, references in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to “ProPetro Holding Corp.,” “the Company,” “we,” “our,” “us” or like terms refer to ProPetro Holding Corp. and its subsidiary.

Overview

Our Business

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, or E&P, of North American unconventional oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower.

Changes to our customers’ well design, shale formations, operating conditions and new technology have resulted in continuous changes to the number of pumps, or units, that constitute a fleet. As a result of the asymmetric nature of the number of pumps that constitute a fleet across our customer base, which we believe will continue to evolve, we view HHP to also be an appropriate metric to measure our available hydraulic fracturing capacity. As such, our total available HHP at December 31, 2019 was 1,469,000 HHP, which was comprised of 1,415,000 HHP of conventional HHP and 54,000 HHP of our newly purchased DuraStim® hydraulic fracturing technology. With the continuous evaluation and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline as we reconfigure our fleets to increase active HHP and back up HHP based on our customers’ and operational needs. Our first DuraStim® hydraulic fracturing pumps of 54,000 HHP was delivered in December 2019 and deployed to a customer in January 2020. We expect that the additional DuraStim® hydraulic fracturing pumps of 54,000 HHP will be delivered during 2020. We also have an option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic fracturing pumps in the future through April 30, 2021. The DuraStim® technology is powered by electricity. We purchased two gas turbines to provide electrical power for the DuraStim® fleets. The electrical power sources for future DuraStim® fleets are still being evaluated and could either be supplied by the Company, customers or a third-party supplier.

Pioneer Pressure Pumping Acquisition

On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer Natural Resources USA, Inc.(“Pioneer”) and Pioneer Pumping Services, LLC (the “Pioneer Pressure Pumping Acquisition”). The pressure pumping assets acquired included hydraulic fracturing pumps of 510,000 HHP, four coiled tubing units and the associated equipment maintenance facility. In connection with the acquisition, we became a long-term service provider to Pioneer under a Pressure Pumping Services Agreement (the “Pioneer Services Agreement”), providing pressure pumping and related services for a term of up to 10 years; provided, that Pioneer has the right to terminate the Pioneer Services Agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026. Pioneer can increase the number of committed fleets prior to December 31, 2022. Pursuant to the Pioneer Services Agreement, the Company is entitled to receive compensation if Pioneer were to idle committed fleets (“idle fees”); however, we are first required to use all economically reasonable effort to deploy the idled fleets to another customer. At the present, we

have eight fleets committed to Pioneer. During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues.

Commodity Price and Other Economic Conditions

The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in early March 2020 as a direct result of failed negotiations between OPEC, and Russia. In response to the global economic slowdown, OPEC had recommended a decrease in production levels in order to accommodate reduced demand. Russia rejected the recommendation of OPEC as a concession to U.S. producers. After the failure to reach an agreement, Saudi Arabia, a dominant member of OPEC, and other Persian Gulf OPEC members announced intentions to increase production and offer price discounts to buyers in certain geographic regions.

As the breadth of the COVID-19 health crisis expanded throughout the month of March 2020 and governmental authorities implemented more restrictive measures to limit person-to-person contact, global economic activity continued to decline commensurately. The associated impact on the energy industry has been adverse and continued to be exacerbated by the unresolved conflict regarding production. In the second week of April, OPEC reconvened to discuss the matter of production cuts in light of unprecedented disruption and supply and demand imbalances that expanded since the failed negotiations in early March 2020. Tentative agreements were reached to cut production by up to 10 million BOPD, with allocations to be made among the OPEC+ participants. Some of these production cuts went into effect in the first half of May 2020, however, commodity prices remain depressed as a result of an increasingly utilized global storage network and near-term demand loss attributable to the COVID-19 health crisis and related economic slowdown.

2019 Operational Highlights

Over the course of the year ended December 31, 2019, we:


•	Placed in service, at the beginning of 2019, pressure pumping and related assets (510,000 HHP) acquired in connection with the Pioneer Pressure Pumping Acquisition, which resulted in an increase to our revenue and profitability in 2019;


•	Purchased 108,000 HHP of DuraStim® hydraulic fracturing pumps with the first DuraStim® pumps of 54,000 HHP delivered in December 2019, while the remaining hydraulic fracturing pumps or 54,000 HHP expected to be delivered in 2020;


•	Entered into a purchase option agreement with our equipment supplier to purchase additional DuraStim® hydraulic fracturing pumps of 108,000 HHP;


•	Maintained a high fleet utilization for the year 2019; and


•	Improved operational and financial processes by making changes to senior management in 2019.

2019 Financial Highlights

Financial highlights for the year ended December 31, 2019:


•	Revenue increased $347.8 million, or 20.4%, to $2,052.3 million, as compared to $1,704.6 million for the year ended December 31, 2018, primarily a result of the increase in our fleet size in connection with the Pioneer Pressure Pumping Acquisition placed in service at the beginning of 2019;

•

Cost of services (exclusive of depreciation and amortization) increased $199.8 million or 15.7% to $1,470.4 million, as compared to $1,270.6 million for the year ended December 31, 2018, primarily a result of the increase in head count and higher activity levels resulting from the increase in fleet size. Cost of services as a percentage of revenue decreased to 71.6% in 2019 compared to 74.5% for the year ended December 31, 2018;

•

General and administrative expenses, inclusive of stock-based compensation (“G&A”), increased $51.1 million, or 94.7% to $105.1 million, as compared to $54.0 million for the December 31, 2018. G&A as a percentage of revenue increased to 5.1% in 2019 from 3.2% for the year ended December 31, 2018. The increase was driven by increase in legal and professional fees, payroll related expense and net increase in other G&A expenses resulting partly from the expansion of our business with the Pioneer Pressure Pumping Acquisition. Included in G&A was approximately $24.2 million related to legal and professional fees incurred in connection with the Audit Committee internal review;

•

Net income was $163.0 million, compared to $173.9 million for the December 31, 2018. Diluted net income per common share was $1.57, compared to $2.00 for the year ended December 31, 2018. Adjusted EBIDTA was approximately $519.1 million, compared to $388.5 million for the year ended December 31, 2018 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”); and


•	Maintained a conservative balance sheet and sufficient liquidity.

Actions to Address the Economic Impact of COVID-19 and Decline in Commodity Prices

Since March 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position, liquidity and the efficient continuity of our operations as follows:


◦	Growth Capital. We cancelled substantially all our planned growth capital expenditures for the remainder of 2020.


◦	Other Expenditures. We significantly reduced our maintenance expenditures and field level consumable costs due to our reduced activity levels. We have been seeking lower pricing for our expendable items, materials used in day-to-day operations and large component replacement parts. Also, we have been internalizing certain support services that were outsourced.


◦	Labor Force Reductions. We have reduced our workforce by over 60% due to the changing activity levels for our services. We will continue to make appropriate adjustments to our workforce to reflect outlook related to activity levels.


◦	Compensation Related Costs. The directors and officers have voluntarily reduced compensation at different levels up to 20%. We have taken efforts to manage work schedules, primarily related to hourly employees, to minimize overtime costs.


◦	Working Capital. We have negotiated more favorable payment terms with certain of our larger vendors and are continuing to increase our diligence in collecting and managing our portfolio of accounts receivables.

We are continuing to evaluate and consider additional cost saving measures. We will continue to prioritize the safety and welfare of our employees and customers through these turbulent times.

Our Assets and Operations

Through our pressure pumping segment, which includes cementing operations, we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our modern hydraulic fracturing fleets have 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. We continually reinvest in our equipment 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 and other services. We believe these complementary services create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well in the future.

How We Generate Revenue

We generate revenue primarily through our pressure pumping segment, and more specifically, by providing hydraulic fracturing services to our customers. We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also provide personnel and services that are tailored to meet each of our customers’ needs. We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job. We also could generate revenue from idle fees from Pioneer in certain circumstances.

In addition to hydraulic fracturing services, we generate revenue through the complementary services that we provide to our customers, including cementing, coiled tubing and other services. These complementary services are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.

Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. WTI oil prices declined significantly in 2015 and 2016 to approximately $30 per barrel, but subsequently recovered in 2017 and 2018. However, in 2019, oil and natural gas prices were highly volatile. The average WTI oil price per barrel was approximately $57, $65 and $51 for the years ended December 31, 2019, 2018 and 2017, respectively. Demand for our services is largely dependent on oil and natural gas prices, and our customers’ completion budgets and rig count. In March 2020, WTI oil prices declined significantly, to a low of approximately $20 per barrel towards the end of March 2020. On June 17, 2020 the WTI oil price was approximately $38 per barrel. If such depressed prices continue or do not improve, demand for our services will be negatively impacted and result in a significant decrease in our profitability and cash flows. We monitor the oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.

The historical weekly average Permian Basin rig count based on the Baker Hughes Incorporated rig count information were as follows:



	Year Ended December 31,
Drilling Type (Permian Basin)	2019		2018		2017
Directional	5		6		6
Horizontal	405		418		311
Vertical	32		43		39
Total	442		467		356

Average Permian Basin rig count to U.S rig count	46.9	%	45.2	%	40.6	%

Costs of Conducting our Business

The principal direct costs involved in operating our business are direct labor, expendables and other direct costs.

Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly attributable to the effective delivery of services are included in our operating costs. Direct labor costs amounted to 19.6% and 13.1% of total costs of service for the years ended December 31, 2019 and 2018, respectively. The percentage increase in our direct labor costs was driven primarily by the increase in the crew costs and also the increase in the number of our customers directly sourcing certain expendables like sand and chemical, as discussed below, which has the effect of reducing our revenues.

Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our pressure pumping and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 40.8%, and 56.0% of total costs of service for the years ended December 31, 2019 and 2018, respectively. The percentage decrease in our expendable product cost in 2019 is primarily attributable to the increase in the number of customers sourcing these expendables directly from the vendors and an increase in the use of less expensive regional sand, and overall depressed sand prices, which has the effect of reducing our revenues.

Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our hydraulic fracturing fleet and other equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are not included in other direct costs. Other direct costs were 39.6% and 30.9% of total costs of service for the years ended December 31, 2019 and 2018, respectively. The percentage increase in our other direct costs was primarily a result of the increase in the number of our customers directly sourcing certain expendables like sand and chemical, as discussed above, which has the effect of reducing our revenues.

How We Evaluate Our Operations

Our management uses a variety of financial metrics, Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.

Adjusted EBITDA and Adjusted EBITDA Margin

We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, 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) loss/(gain) on extinguishment of debt, (iii) stock-based compensation, and (iv) other unusual or non‑recurring (income)/expenses, such as impairment charges, severance, costs related to our IPO and costs related to asset acquisitions or one-time professional fees. 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 taxes). 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 generally accepted accounting principles in the United States of America (“GAAP”).

Note Regarding Non‑GAAP Financial Measures

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 (income) expenses and items outside the control of the Company. Net income (loss) 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 and 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.

Reconciliation of net income (loss) to Adjusted EBITDA ($ in thousands):



	Pressure Pumping		All Other			Total
Year ended December 31, 2019
Net income (loss)	$	281,090	$	(118,080	)	$	163,010
Depreciation and amortization	139,348		5,956			145,304
Interest expense	51		7,090			7,141
Income tax expense	—		50,494			50,494
Loss on disposal of assets	106,178		633			106,811
Impairment expense	—		3,405			3,405
Stock‑based compensation	—		7,776			7,776
Other expense	—		717			717
Other general and administrative expense ⁽¹⁾	—		25,208			25,208
Deferred IPO bonus, retention bonus and severance expense	7,093		2,110			9,203
Adjusted EBITDA	$	533,760	$	(14,691	)	$	519,069



	Pressure Pumping		All Other			Total
Year ended December 31, 2018
Net income (loss)	$	253,196	$	(79,334	)	$	173,862
Depreciation and amortization	83,404		4,734			88,138
Interest expense	—		6,889			6,889
Income tax expense	—		51,255			51,255
Loss (gain) on disposal of assets	59,962		(742		)	59,220
Stock‑based compensation	—		5,482			5,482
Other expense	—		663			663
Other general and administrative expense ⁽¹⁾	2		203			205
Deferred IPO bonus	1,832		977			2,809
Adjusted EBITDA	$	398,396	$	(9,873	)	$	388,523

	Pressure Pumping		All Other			Total
Year ended December 31, 2017
Net income (loss)	$	50,417	$	(37,804	)	$	12,613
Depreciation and amortization	51,155		4,473			55,628
Interest expense	—		7,347			7,347
Income tax expense	—		3,128			3,128
Loss on disposal of assets	38,059		1,027			39,086
Stock‑based compensation	—		9,489			9,489
Other expense	—		1,025			1,025
Other general and administrative expense ⁽¹⁾	—		722			722
Deferred IPO bonus	5,491		2,914			8,405
Adjusted EBITDA	$	145,122	$	(7,679	)	$	137,443

____________________


(1)	Other general and administrative expense primarily relates to nonrecurring professional fees paid to external consultants in connection with the Expanded Audit Committee Review and advisory services in 2019, and legal settlements in 2018 and 2017.

Results of Operations

We conduct our business through five operating segments: hydraulic fracturing, cementing, coiled tubing, flowback and drilling. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment, pressure pumping. The comparability of the results of operations may have been impacted by the Pioneer Pressure Pumping Acquisition which was consummated on December 31, 2018. 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. The real estate lease for the crew camp was terminated in July 2019. In connection with the consummation of the transaction, we became a long-term service provider to Pioneer, providing pressure pumping and related services for a term of up to ten years. The Pioneer Pressure Pumping Acquisition resulted in an additional 510,000 HHP being deployed at the beginning of 2019.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018



($ in thousands, except percentages)
	Year Ended December 31,						Change
	2019			2018			Variance			%

Revenue	$	2,052,314		$	1,704,562		$	347,752		20.4	%
Less (Add):
Cost of services ⁽¹⁾	1,470,356			1,270,577			199,779			15.7	%
General and administrative expense ⁽²⁾	105,076			53,958			51,118			94.7	%
Depreciation and amortization	145,304			88,138			57,166			64.9	%
Impairment expense	3,405			—			3,405			100.0	%
Loss on disposal of assets	106,811			59,220			47,591			80.4	%
Interest expense	7,141			6,889			252			3.7	%
Other expense	717			663			54			8.1	%
Income tax expense	50,494			51,255			(761		)	(1.5	)%

Net income	$	163,010		$	173,862		$	(10,852	)	(6.2	)%

Adjusted EBITDA ⁽³⁾	$	519,069		$	388,523		$	130,546		33.6	%
Adjusted EBITDA Margin ⁽³⁾	25.3		%	22.8		%	2.5		%	11.0	%

Pressure pumping segment results of operations:
Revenue	$	2,001,627		$	1,658,403		$	343,224		20.7	%
Cost of services	$	1,428,620		$	1,236,262		$	192,358		15.6	%
Adjusted EBITDA	$	533,760		$	398,396		$	135,364		34.0	%
Adjusted EBITDA Margin ⁽⁴⁾	26.7		%	24.0		%	2.7		%	11.3	%

____________________


(1)	Exclusive of depreciation and amortization.


(2)	Inclusive of stock‑based compensation of $7.8 million and $5.5 million for 2019 and 2018, respectively.


(3)	For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin 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 revenues for the pressure pumping segment.

Revenue. Revenue increased 20.4%, or $347.8 million, to $2,052.3 million for the year ended December 31, 2019, as compared to $1,704.6 million for the year ended December 31, 2018. The increase was primarily attributable to the increase in our effectively utilized fleets from approximately 18.8 active fleets in 2018 to 23.9 in 2019, and an increase in demand for our pressure pumping services and certain customer activity, specifically driven by the Pioneer Pressure Pumping Acquisition. The increase in revenue was partly offset by the increase in the number of customers self-sourcing certain consumables like sand. Our pressure pumping segment revenues increased 20.7%, or $343.2 million for the year ended December 31, 2019, as compared to the year ended December 31, 2018.

Revenues from services other than pressure pumping increased 9.8%, or approximately $4.5 million, for the year ended December 31, 2019, as compared to the year ended December 31, 2018. The increase in revenues from services other than pressure pumping during the year ended December 31, 2019, was primarily attributable to the increase in demand for our coiled tubing services.

Cost of Services. Cost of services increased 15.7%, or $199.8 million, to $1,470.4 million for the year ended December 31, 2019, from $1,270.6 million during the year ended December 31, 2018. Cost of services in our pressure pumping segment increased $192.4 million during the year ended December 31, 2019, as compared to the year ended December 31, 2018. The increases were primarily attributable to higher activity levels, coupled with an increase in personnel headcount following the increase in our operations in connection with the Pioneer Pressure Pumping Acquisition. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 71.4% for the year ended December 31, 2019, as compared to 74.5% for the year ended December 31, 2018. The decrease in cost of services as a percentage of revenue in our pressure pumping segment is attributed to the increased revenue from operational efficiencies and a favorable change in our cost structure driven by our internal cost control initiatives, a decrease in the cost of certain consumables and an increase in the number of customers self-sourcing sand and other consumables, which resulted in significantly higher realized Adjusted EBITDA margins during the year ended December 31, 2019.

General and Administrative Expenses. General and administrative expenses increased 94.7%, or $51.1 million, to $105.1 million for the year ended December 31, 2019, as compared to $54.0 million for the year ended December 31, 2018. The net increase was primarily attributable to the increase in retention bonuses, stock-based compensation, and severance and related expenses of $11.0 million driven primarily by the increase in personnel following the Pioneer Pressure Pumping Acquisition, increase in nonrecurring professional fees of $25.0 million, primarily in connection with the Expanded Audit Committee Review, and net increase in our remaining other general and administrative expenses of approximately $15.1 million.

Depreciation and Amortization. Depreciation and amortization increased 64.9%, or $57.2 million, to $145.3 million for the year ended December 31, 2019, as compared to $88.1 million for the year ended December 31, 2018. The increase was primarily attributable to additional property and equipment purchased in connection with the Pioneer Pressure Pumping Acquisition and other equipment put into service during the year ended December 31, 2019.

Impairment Expense. Impairment expense of $3.4 million, a non-cash expense, was recorded during the year ended December 31, 2019 in connection with our vertical drilling rigs and flowback assets resulting from the depressed demand and negative future near-term outlook for our drilling assets and the shutdown of our flowback operations. No impairment expense was recorded in the year ended December 31, 2018.

Loss on Disposal of Assets. Loss on the disposal of assets increased 80.4%, or $47.6 million, to $106.8 million for the year ended December 31, 2019, as compared to $59.2 million for the year ended December 31, 2018. The increase was primarily attributable to an increase in our hydraulic fracturing fleet size, and greater intensity of jobs as well as the number of jobs completed. Upon sale or retirement of property and equipment, including certain major components like fluid ends and power ends of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.

Interest Expense. Interest expense increased 3.7%, or $0.3 million, to $7.1 million for the year ended December 31, 2019, as compared to $6.9 million for the year ended December 31, 2018. The increase in interest expense was primarily attributable to an increase in our average debt balance in 2019 compared to 2018.

Other Expense. Other expense was relatively flat at $0.7 million for the year ended December 31, 2019, similar to $0.7 million for the year ended December 31, 2018.

Income Tax Expense. Income tax expense was $50.5 million for the year ended December 31, 2019, as compared to $51.3 million for the year ended December 31, 2018. The slight decrease in our provision for income tax expense is attributable to the decrease in pre-tax book income in 2019 compared to 2018. Our effective tax rate was relatively flat at 23.7% during the year ended December 31, 2019 compared to 22.8% during the year ended December 31, 2018.

Liquidity and Capital Resources

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our revolving credit facility (“ABL Credit Facility”). Our primary uses of cash will be to continue to fund our operations, support growth opportunities and satisfy debt payments. Our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable. Our borrowing base as of December 31, 2019 was approximately $181.2 million and was approximately $16.8 million as of June 19, 2020. Changes to our operational activity levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. With the current depressed oil and gas market conditions, we believe our remaining monthly availability under our ABL Credit facility will be adversely impacted by the expected decline in our customers’ activity.

As of December 31, 2019, our borrowings under our ABL Credit Facility was $130.0 million and our total liquidity was $198.7 million, consisting of cash and cash equivalents of $149.0 million and $49.7 million of availability under our ABL Credit Facility.

As of June 19, 2020, we had no borrowings under our ABL Credit Facility and our total liquidity was approximately $57.4 million, consisting of cash and cash equivalents of $42.2 million and $15.2 million of availability under our ABL Credit Facility.

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 natural 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 long-term liquidity requirements.

The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in early March 2020. As a result of these developments, the Company expects a material adverse impact on the oil field services we provide and our revenue, results of operations and cash flows. These situations are rapidly changing and additional impacts to the business may arise that we are not aware of currently and the depressed oil and gas industry may take a longer time to recover thereby significantly impacting on revenue, results of operations and cash flows for a longer period of time.

Cash and Cash Flows

The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2019, 2018 and 2017, respectively.



	Year Ended December 31,
($ in thousands)	2019			2018			2017

Net cash provided by operating activities	$	455,290		$	393,079		$	109,257
Net cash used in investing activities	$	(495,299	)	$	(280,604	)	$	(281,469	)
Net cash provided by (used in) financing activities	$	56,345		$	(3,724	)	$	62,565

Operating Activities

Net cash provided by operating activities was $455.3 million for the year ended December 31, 2019, as compared to $393.1 million for the year ended December 31, 2018. The net increase of $62.2 million was primarily due to the expansion of our operations following the Pioneer Pressure Pumping Acquisition as well as the associated increase in revenue and cash operating profits, and also impacted by the timing of our receivable collections from our customers and payment to our vendors.

Investing Activities

Net cash used in investing activities increased to $495.3 million for the year ended December 31, 2019, from $280.6 million for the year ended December 31, 2018. The increase was primarily attributable to the cash payment of approximately $110.0 million in connection with the Pioneer Pressure Pumping Acquisition. In addition, during the year ended December 31, 2019, we paid approximately $145.3 million for 108,000 HHP of DuraStim® hydraulic fracturing units, ancillary equipment and turbines (including an option payment of $6.1 million to purchase an additional 108,000 HHP of DuraStim® fleets through the end of 2020). The remaining cash payments in 2019 were primarily incurred in connection with our maintenance capital expenditures and other growth initiatives.

Financing Activities

Net cash provided by financing activities was $56.3 million for the year ended December 31, 2019, compared to net cash used of $3.7 million for the year ended December 31, 2018. Our net cash provided by financing activities during the year ended December 31, 2019 was primarily driven by proceeds from borrowings of $110.0 million to fund our working capital needs and cash payment for fleets acquired in connection with the Pioneer Pressure Pumping Acquisition, proceeds from exercise of equity awards of $1.2 million which was partially offset by cash used in repayment of borrowings of $50.0 million, repayments of insurance financing of $4.5 million and finance lease payment of approximately $0.3 million. Our net cash used in financing activities during the year ended December 31, 2018 was primarily driven by repayment of borrowings of $80.9 million, repayment of insurance financing of $4.5 million, payment of debt issuance costs of $1.7 million, partially offset by proceeds from borrowings of $77.4 million to fund our working capital needs and proceeds from insurance financing of $5.8 million.

Future Sources and Use of Cash

Capital expenditures for 2020 are projected to be primarily related to maintenance capital expenditures to support our existing assets and growth initiatives, depending on market conditions. We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. Our maintenance capital expenditures are dependent on our operational activity and the intensity on the equipment, among other factors, which could vary throughout the year.

In addition, we have an agreement with our equipment manufacturer granting the Company the option to purchase additional DuraStim® hydraulic fracturing pumps of approximately 108,000 HHP with the purchase option expiring at different times through April 30, 2021. We believe the cost to acquire the DuraStim® pumps will be comparable to our previously purchased DuraStim® pumps. In the current economic environment it is not probable we would exercise these options.

We have repaid all our borrowings, as of June 19, 2020, under our ABL Credit Facility with cash flows from operations and our available cash. Our objective is to maintain a conservative leverage ratio. Through June 19, 2020, we repaid $130.0 million of our borrowings under the ABL Credit Facility.

Credit Facility and Other Financing Arrangements

ABL Credit Facility

Our ABL Credit Facility, as amended, has a total borrowing capacity of $300 million (subject to the Borrowing Base limit), with a maturity date of December 19, 2023. The ABL Credit Facility has a borrowing base of 85% of monthly eligible accounts receivable less customary reserves (the "Borrowing Base"). The Borrowing Base as of December 31, 2019 was approximately $181.2 million. The ABL Credit Facility includes a 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 or the Borrowing Base or (ii) $22.5 million. 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. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.

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 a LIBOR floor of zero. The weighted average interest rate under our ABL Credit Facility for the year ended December 31, 2019 was 4.4%.

In March 2020, we obtained a waiver from our lenders under the ABL Credit Facility to extend the time period for us to provide our lenders the Company’s audited financial statements for the year ended December 31, 2019 to July 31, 2020.

Off Balance Sheet Arrangements

We had no off balance sheet arrangements as of December 31, 2019.

Capital Requirements

Capital expenditures incurred were $400.7 million during the year ended December 31, 2019, as compared to $592.6 million during the year ended December 31, 2018. The higher capital expense in 2018 was primarily attributable to the Pioneer Pressure Pumping Acquisition. We financed the Pioneer Pressure Pumping Acquisition with a combination of cash from operations and borrowings under our ABL Credit Facility and the issuance of 16.6 million of our common shares to Pioneer.

Contractual Obligations

The following table presents our contractual obligations and other commitments as of December 31, 2019.

Large accelerated filer

Accelerated filer

Non-accelerated filer

☐(Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company