For the fiscal year ended December 31, 2017

For the transition period from                      to                     

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

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  ý  No  ¨ 

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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. 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, 2017, determined using the per share closing price on the New York Stock Exchange Composite tape of $13.96 on that date, was approximately $674.2 million.

The number of the registrant’s common shares, par value $0.001 per share, outstanding at March 16, 2018, was 83,039,854.

On March 22, 2017, we closed our initial public offering, or IPO, at which time we issued and sold 13,250,000 shares of common stock, and certain selling shareholders sold 11,750,000 shares of common stock, at a price to the public of $14.00 per share. We received cash proceeds of approximately $170.1 million from this transaction, net of underwriting discounts and commissions and offering expenses, which we used (i) to repay $71.8 million in outstanding borrowings and accrued interest under our term loan, (ii) $86.8 million to fund the purchase of additional hydraulic fracturing units and other equipment, and (iii) the remaining for general corporate purposes.

In connection with the IPO, the Company executed a stock split, such that each holder of common stock of the Company received 1.45 shares of common stock for every one share of previous common stock. Accordingly, any information related to, or dependent upon, the share or option counts in our comparative 2016 and 2015 consolidated financial statements have been updated to reflect the effect of the stock split.

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, 2017, we had one 2”, one 2³/₈” and one 1¹/₄” coiled tubing unit, all of which were operating in the Permian Basin. We believe these units are well suited for the performance requirements of the unconventional resource markets we serve. The average age of these units is less than four years old.

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

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 naturally occurring radiation in excess

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. The EPA has determined that GHGs present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of GHGs under existing provisions of the CAA. The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities. The U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one‑half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. And in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four‑year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

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 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, which 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

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.

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 on Form 10-K 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.

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 $305.3 million, $46.0 million and $71.7 million during the years ended December 31, 2017, 2016 and 2015. 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 facilities. 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. 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. 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.

As of December 31, 2017, we had approximately $261.0 million of federal net operating loss carryforwards that will begin to expire in 2032 and state net operating losses of approximately $47.0 million that 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 have experienced 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.

As of December 31, 2017, there were 83,039,854 shares of common stock outstanding, held of record by 18 holders. The number of record holders of our common stock does not include DTC participants or beneficial owners holding shares through nominee names.

On March 22, 2017, we consummated our IPO in which 25,000,000 shares of our common stock, par value $0.001 per share, were sold at a public offering price of $14.00 per share, with 13,250,000 shares issued and sold by the Company and 11,750,000 shares sold by existing stockholders. We received net proceeds of approximately $170.1 million after deducting $10.9 million of underwriting discounts and commissions, and $4.5 million of other offering expenses. At closing, we used the proceeds (i) to repay $71.8 million in outstanding borrowings under the term loan, (ii) $86.8 million to fund the purchase of additional hydraulic fracturing units and other equipment, and (iii) the remaining for general corporate purposes.

___________________

The following table presents selected historical financial and operating data of ProPetro Holding Corp. for the years indicated. The selected historical financial data as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015 are derived from the audited consolidated financial statements appearing elsewhere in this annual report. The 2015 balance sheet selected historical financial data was derived from the audited financial statements for the year ended December 31, 2015, not included in this Form 10-K. Historical results are not necessarily indicative of future results.

_________________

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

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 the most prolific oil‑producing area in the United States, and we believe we are currently one of the largest providers of hydraulic fracturing services in the region by hydraulic horsepower, or HHP, with an aggregate deployed capacity of 690,000 HHP at December 31, 2017. Our fleet has been designed to handle the highest intensity, most complex hydraulic fracturing jobs, and has been 100% utilized since September 2016. In the quarter ended December 31, 2017, we put one new hydraulic fracturing unit into service bringing our total fleet to 16 units as of December 31, 2017. During the year ended December 31, 2017, we put a total of six new hydraulic fracturing units into service. In addition, we have deployed two new hydraulic fracturing units into service through March of 2018, bringing our current fleet total to 18 deployed units, or 780,000 HHP.

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. West Texas Intermediate (“WTI”) oil prices which declined significantly close to the end of the second half of 2014 have recently recovered. The average WTI oil prices per barrel was $50.8, $43.3 and $48.7 for the years ended December 31, 2017, 2016 and 2015, respectively, and is expected to continue to increase in 2018. As a result of the recent recovery in oil prices, our industry has experienced a significant increase in both drilling and pressure pumping activity levels. Looking forward, assuming oil prices remain at or above recent levels, we believe U.S. rig counts will continue to increase, which may result in an increase in demand for drilling and pressure pumping services. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices, as well as rig count.

Expendables. Expendables are the largest expenses incurred, and 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 61.3% , 61.0% and 58.9% of total costs of service for the years ended December 31, 2017, 2016 and 2015, respectively.

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 26.5%, 24.4% and 24.3% of total costs of service for the years ended December 31, 2017, 2016 and 2015, respectively.

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 12.2%, 14.5% and 16.9% of total costs of service for the years ended December 31, 2017, 2016 and 2015, respectively.

Our strategic focus on our pressure pumping segment and other complementary services will reduce the relative financial contribution of the drilling operating segment in our results of operations. We expect revenues and costs of services related to our drilling operating segment to comprise a lower percentage of total revenues and total costs of service in future results of operations when compared to historic results due to our increased focus on pressure pumping and other complementary service offerings. We idled all seven of our Permian vertical drilling rigs during 2016. As a result, during the year ended December 31, 2017, no revenue was generated by our drilling segment as compared to $9.9 million of revenue (or 2.3% of revenues) for the year ended December 31, 2016, and $35.7 million (or 6.3% of revenues) for the year ended December 31, 2015. Likewise cost of services related to drilling was $0.4 million for the year ended December 31, 2017, as compared to $8.5 million (2.1% of all costs of services) for the year ended December 31, 2016, and $30.8 million (or 6.4% of cost of service) for the year ended December 31, 2015. We anticipate the financial significance of this service line relative to the financial results from pressure pumping and other service offerings to continue to decline.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

____________________

Revenues.  Revenues increased 124.7%, or $544.9 million, to $981.9 million for the year ended December 31, 2017, as compared to $436.9 million for the year ended December 31, 2016. The increase was primarily attributable to the increase in customer activity, fleet size and demand for our services, which has led to an increase in pricing for our hydraulic fracturing and other services. Our pressure pumping segment revenues increased 131.1%, or $536.0 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016. Revenues from services other than pressure pumping increased 32.0%, or $8.9 million, for the year ended December 31, 2017, as compared to the year ended December 31, 2016. The increase in revenues from services other than pressure pumping during the year ended December 31, 2017 was primarily attributable to the increase in revenues and customer demand for our flowback, coil tubing and surface drilling services, offset by the decrease in revenue from idling of our drilling rigs.

Cost of Services.  Cost of services increased 101.4%, or $409.7 million, to $813.8 million for the year ended December 31, 2017, from $404.1 million during the year ended December 31, 2016. Cost of services in our pressure pumping segment increased $404.5 million during the year ended December 31, 2017, as compared to the year ended December 31, 2016. The increases were primarily attributable to higher activity levels, coupled with an increase in personnel headcount following the increased activity levels. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 83.0% for the year ended December 31, 2017, as compared to 92.9% for the year ended December 31, 2016. The decrease in cost of services as a percentage of revenue for the pressure pumping segment resulted from greater pricing power as demand for our services increased, without a corresponding increase in certain costs, which resulted in significantly higher realized Adjusted EBITDA margins during the year ended December 31, 2017.

General and Administrative Expenses.  General and administrative expenses increased 84.9%, or $22.6 million, to $49.2 million for the year ended December 31, 2017, as compared to $26.6 million for the year ended December 31, 2016. The net increase was primarily attributable to increases in payroll, insurance, advertising, communication, office expense, travel and legal costs, totaling $8.3 million, and an IPO bonus of $8.4 million to key employees, along with $7.8 million increase in stock compensation recorded during the year ended December 31, 2017, and offset by a decrease in property taxes of $1.6 million, and other remaining general and administrative expenses of $0.3 million. General and administrative expenses as a percentage of total revenues decreased to 5.0% for the year ended December 31, 2017, as compared to 6.1% for the year ended December 31, 2016, excluding non-recurring deferred IPO bonus of $8.4 million and stock compensation expense of $6.8 million, general and administrative expenses as a percentage of total revenues decreased to 3.5% for the year ended December 31, 2017, as compared to 6.1% for the year ended December 31, 2016. The decrease in general and administrative expenses as a percentage of total revenue is as a result of the higher revenue during the year ended December 31, 2017.

Depreciation and Amortization.  Depreciation and amortization increased 27.8%, or $12.1 million, to $55.6 million for the year ended December 31, 2017, as compared to $43.5 million for the year ended December 31, 2016. The increase was primarily attributable to additional property and equipment purchased and put into service in the year ended December 31, 2017. We calculate depreciation of property and equipment using the straight-line method.

Property and Equipment Impairment Expense. There was no property and equipment impairment expense during the year ended December 31, 2017, compared to $6.3 million during the year ended December 31, 2016. The non‑cash impairment expense in 2016 was associated with our drilling rigs, and was recognized as a result of depressed commodity prices and a negative future near‑term outlook for these assets.

Goodwill Impairment Expense. There was no goodwill impairment expense during the year ended December 31, 2017, compared to $1.2 million during the year ended December 31, 2016. The non‑cash goodwill impairment expense in 2016 was as a result of the write‑down of goodwill related to our surface drilling reporting unit.

Loss on Disposal of Assets.  Loss on the disposal of assets increased 73.5%, or $16.6 million, to $39.1 million for the year ended December 31, 2017, as compared to $22.5 million for the year ended December 31, 2016. The increase was primarily attributable to greater service intensity of jobs completed, coupled with higher fleet size, activity levels and utilization of our equipment.

Interest Expense.  Interest expense decreased 64.0%, or $13.0 million, to $7.3 million for the year ended December 31, 2017, as compared to $20.4 million for the year ended December 31, 2016. The decrease in interest expense was primarily attributable to a reduction in our average debt balance during 2017 due to the early retirement of our term loan and revolving credit facility in the first quarter of 2017.

Gain on Extinguishment of Debt.  There was no debt extinguishment gain or loss during the year ended December 31, 2017, compared to the gain on extinguishment of debt, net of cost, of $7.0 million during the year ended December 31, 2016. The gain on extinguishment of debt during 2016 was as a result of the auction process with our lenders to repurchase $37.5 million of our term loan at a 20% discount to par value.

Other Expense.  Other expense was $1.0 million for the year ended December 31, 2017, as compared to $0.3 million for the year ended December 31, 2016. The increase was primarily attributable to an increase in lenders related expenses, non-recurring listing related expenses, and partially offset by an increase in the unrealized gain resulting from the change in the fair value of our interest rate swap liability at December 31, 2017 compared to December 31, 2016.

Income Tax Expense/(Benefit).  Income tax expense was $3.1 million for the year ended December 31, 2017, compared to income tax benefit of $28.0 million, for the year ended December 31, 2016. The change from an income tax benefit to income tax expense is primarily due to the Company’s reporting income before taxes during the year ended December 31, 2017, compared to a loss before taxes recorded during the year ended December 31, 2016. The income before taxes generated is attributable to the increase in our revenue during the year ended December 31, 2017, compared to December 31, 2016. Additionally, the income tax expense during the year ended December 31, 2017, included a one-time deferred tax benefit offset of $3.4 million, resulting from the U.S. government enacted tax legislation commonly referred to as the Tax Cuts and Jobs Act (“Tax Act”). 

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

____________________

Revenues. Revenues decreased 23.3%, or $132.7 million, to $436.9 million for the year ended December 31, 2016 as compared to $569.6 million for the year ended December 31, 2015. The decrease was primarily attributable to a reduction in customer activity, a decline in pricing for our hydraulic fracturing services as a result of an over‑supply of HHP in our areas of operations, and the idling of our seven drilling rigs. Our pressure pumping segment revenues decreased 19.8%, or $101.2 million, for the year ended December 31, 2016 as compared to the year ended December 31, 2015. Revenues other than pressure pumping decreased 53.0%, or $31.5 million, for the year December 31, 2016 as compared to the year ended December 31, 2015. The decrease was primarily attributable to a decline in demand and pricing for these ancillary services. The overall decrease in revenues was attributable to a competitive market environment caused by the decrease in U.S. onshore drilling and completion activity as a result of decreased oil and natural gas commodity prices. Average oil and natural gas prices have decreased 11.0% and 3.8%, respectively, from the year ended December 31, 2015 as compared to the year ended December 31, 2016. The

Cost of Services. Cost of services decreased 16.4%, or $79.2 million, to $404.1 million for the year ended December 31, 2016 from $483.3 million as compared to the year ended December 31, 2015. Cost of services in our pressure pumping segment decreased $52.6 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015. The decreases were primarily attributable to lower activity levels, coupled with reduced personnel headcount. As a percentage of pressure pumping segment revenues, pressure pumping cost of services increased to 92.9% for the year ended December 31, 2016 as compared to 84.7% for the year ended December 31, 2015. The increase in cost of services as a percentage of sales for the pressure pumping segment resulted from lower revenue generating activity levels without a corresponding reduction in costs as well as depressed pricing for our services, which resulted in significantly lower realized EBITDA margins.

General and Administrative Expenses. General and administrative expenses decreased 2.8%, or $0.8 million, to $26.6 million for the year ended December 31, 2016 as compared to $27.4 million for the year ended December 31, 2015. The decrease was primarily attributable to a $2.2 million reduction in insurance expense due to a reduction in personnel headcount and a $1.0 million reduction in property taxes, partially offset by an increase in bonus expense of $2.5 million as compared to 2015. General and administrative expenses as a percentage of total revenues was 6.1% for the year ended December 31, 2016 as compared to 4.8% for the year ended December 31, 2015. This increase was due partially to pricing pressures in a competitive operating environment, as well as our decision to maintain equipment and retain key personnel during times of lower equipment utilization levels.

Depreciation and Amortization. Depreciation and amortization decreased 13.1%, or $6.6 million, to $43.5 million for the year ended December 31, 2016 as compared to $50.1 million for the year ended December 31, 2015. The decrease was primarily attributable to a decrease in average depreciable assets partially offset by approximately $46.0 million in capital expenditures during the year ended December 31, 2016. We calculate depreciation of property and equipment using the straight‑line method.

Property and Equipment Impairment Expense. Property and equipment impairment expense was $36.6 million for the year ended December 31, 2015, as compared to $6.3 million for the year ended December 31, 2016. The non‑cash impairment expense in 2015 was associated with our drilling rigs and acidizing assets and was recognized as a result of depressed commodity prices and a negative future near‑term outlook for these assets. The non‑cash impairment expense in 2016 was a result of the continuous depressed demand for our drilling rigs.

Goodwill Impairment Expense. Goodwill impairment expense was $1.2 million for the year ended December 31, 2016, as compared to no goodwill impairment expense for the year ended December 31, 2015. The impairment expense in 2016 was attributable to the write‑down of goodwill related to our surface drilling reporting unit.

Loss on Disposal of Assets. Loss on the disposal of assets increased 5.9%, or $1.3 million, to $22.5 million for the year ended December 31, 2016 as compared to $21.3 million for the year ended December 31, 2015. The increase was primarily attributable to greater service intensity of jobs completed despite lower pressure pumping activity levels.

Interest Expense. Interest expense decreased 5.8%, or $1.3 million, to $20.4 million for the year ended December 31, 2016 as compared to $21.6 million for the year ended December 31, 2015. The decrease in interest expense was primarily attributable to a reduction in our average debt balance during 2016.

Gain on Extinguishment of Debt. Gain on extinguishment of debt was $7.0 million, net of cost, for the year ended December 31, 2016, as compared to no debt extinguishment gain or loss for the year ended December 31, 2015. In June 2016, we conducted an auction process with our lenders to repurchase $37.5 million of our term loan at a 20% discount to par value.

Other Expense. Other expense decreased to $0.3 million for the year ended December 31, 2016 as compared to $0.5 million for the year ended December 31, 2015. The decrease was primarily attributable to an unrealized gain resulting from the change in the fair value of our interest rate swap liability at December 31, 2016 compared to 2015, partially offset by restructuring expenses related to the first amendment to our existing credit agreement incurred in 2016 and the reduction of other income in 2016 as compared to 2015.

Income Tax Benefit. The increase of $2.6 million in income tax benefit for the year ended December 31, 2016 as compared to the year ended December 31, 2015 is primarily attributable to a higher loss before income taxes, partially offset by the valuation allowance of $0.9 million recorded in the year.

Historically, our primary sources of liquidity and capital resources have been borrowings under our term loan and revolving credit facility, cash flows from our operations and capital contributions from our shareholders. Our primary uses of capital have been investing in and maintaining our property and equipment and repaying indebtedness. As of December 31, 2017, our cash and cash equivalents were $23.9 million, and as of December 31, 2016, were $133.6 million.

On March 22, 2017, we consummated our IPO in which 25,000,000 shares of our common stock, par value $0.001 per share, were sold at a public offering price of $14.00 per share, with 13,250,000 shares issued and sold by the Company and $11,750,000 shares sold by existing stockholders. We received net proceeds of approximately $170.1 million after deducting $10.9 million of underwriting discounts and commissions, and $4.5 million of other offering expenses. At closing, we used the proceeds (i) to repay $71.8 million in outstanding borrowings under our term loan, (ii) $86.8 million to fund the purchase of additional hydraulic fracturing units and other equipment, and (iii) the remaining for general corporate purposes.

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our primary uses of cash will be to continue to fund our operations, support organic growth opportunities and satisfy debt payments. As of December 31, 2017, our total liquidity consists of cash and cash equivalent of $23.9 million, and $79.0 million of availability under our ABL Credit Facility.

The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the year at December 31, 2017, 2016 and 2015, respectively.