ProPetro Holding Corp.: Form 10-Q for the period ended Sep 30, 2018

The financial information, discussion and analysis that follow should be read in conjunction with our consolidated financial statements and the related notes included in the Form 10-K as well as the financial and other information included therein.

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

Overview

We are a growth-oriented, Midland, Texas-based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated long-standing customer relationships with some of the region's most active and well-capitalized E&P companies. The Permian Basin is widely regarded as the most prolific oil-producing area in the United States, and we believe we are currently one of the largest providers of hydraulic fracturing services in the region by hydraulic horsepower ("HHP"). At September 30, 2018, our fleet, which consists of 19 hydraulic fracturing fleets with an aggregate deployed capacity of 860,000 HHP. In October 2018, we deployed and put in service one new hydraulic fracturing fleet with 45,000 HHP, bringing our aggregate capacity to 905,000 HHP or 20 fleets. Our fleet has been designed to handle the highest intensity and most complex hydraulic fracturing jobs in the region.

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

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

Industry Trends and Outlook

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

Most recently, WTI crude oil prices averaged $69 per barrel in September of 2018. Recent prices have resulted in a considerable increase in drilling and completion activity, and associated demand for our services. The Permian Basin, our primary area of operation, is leading the recovery with the number of active drilling rigs in the basin increasing from a low of 137 rigs in May 2016 to 486 rigs in September 2018, according to Baker Hughes. In addition to increased activity levels in the Permian Basin, several evolving industry trends, including increasingly longer horizontal wellbore laterals, a greater number of fractured stages per lateral and increasing amounts of proppant employed per well, have significantly increased demand for our hydraulic fracturing and other completion services.

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

Rising producer activity levels, increasing basin service intensity and continued drilling and completion efficiencies have combined to drive the optimal utilization of our fleet and build a sizable backlog of addressable demand for our services. During the recent downturn, we saw our competitors defer necessary maintenance capital spending and cannibalize existing units for spare parts and idle HHP. This has resulted in tightening hydraulic fracturing supply and demand fundamentals and could drive pricing improvement for our hydraulic fracturing services. Moreover, we believe the other complementary services we provide are well-positioned to similarly benefit from a continued industry recovery.

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

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

How We Evaluate Our Operations

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

Adjusted EBITDA and Adjusted EBITDA margin

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

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

Note Regarding Non-GAAP Financial Measures

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

Reconciliation of net income (loss) to adjusted EBITDA:

($ in thousands)

(1) Other general and administrative expense relates to legal settlement expense.

($ in thousands)

(1) Other general and administrative expense relates to legal settlement expense.

Results of Operations

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

The following table sets forth the results of operations for the periods presented:

(in thousands, except for percentages)

(1) Exclusive of depreciation and amortization.

(2) Inclusive of stock-based compensation.

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

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

Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues. Revenues increased 53.5%, or $151.3 million, to $434.0 million for the three months ended September 30, 2018, as compared to $282.7 million for the three months ended September 30, 2017. 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 55.0%, or $149.5 million, for the three months ended September 30, 2018, as compared to the three months ended September 30, 2017. Revenues from services other than pressure pumping increased 16.6%, or $1.8 million, for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017. The increase in revenues from services other than pressure pumping was primarily attributable to the increase in customer demand for our flowback and coil tubing services in the three months ended September 30, 2018.

Cost of Services. Cost of services increased 42.0%, or $94.7 million, to $320.1 million for the three months ended September 30, 2018, as compared to $225.4 million during the three months ended September 30, 2017. Cost of services in our pressure pumping segment increased $94.1 million for the three months ended September 30, 2018, as compared to the three months ended September 30, 2017. The increases were primarily attributable to higher activity levels, fleet size and an increase in headcount in connection with increased activity levels. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 73.9% for the three months ended September 30, 2018, as compared to 79.9% for the three months ended September 30, 2017. The decrease in cost of services as a percentage of revenue for our pressure pumping segment resulted from greater pricing power as demand for our services increased, without a corresponding increase in costs, which resulted in significantly higher realized Adjusted EBITDA margins during the three months ended September 30, 2018.

General and Administrative Expenses. General and administrative expenses increased 15.4%, or $1.7 million, to $12.8 million for the three months ended September 30, 2018, as compared to $11.1 million for the three months ended September 30, 2017. The net increase was primarily attributable to the increase in stock compensation expense of $0.9 million, and net increase of $0.8 million in other remaining general and administrative expenses.

Depreciation and Amortization. Depreciation and amortization increased 57.5%, or $8.5 million, to $23.2 million for the three months ended September 30, 2018, as compared to $14.7 million for the three months ended September 30, 2017. The increase was primarily attributable to the increase in our fixed asset base as of September 30, 2018, resulting from the additional property and equipment purchased in the fourth quarter of 2017 and during the nine months ended September 30, 2018. We calculate depreciation of property and equipment using the straight-line method.

Loss on Disposal of Assets. Loss on the disposal of assets increased 87.7%, or $7.7 million, to $16.4 million for the three months ended September 30, 2018, as compared to $8.7 million for the three months ended September 30, 2017. The increase is attributable to the increase in fleet size, greater service intensity of jobs completed, and higher activity levels on certain of our equipment.

Interest Expense. Interest expense increased 129.8%, or $0.8 million, to $1.5 million for the three months ended September 30, 2018, as compared to $0.6 million for the three months ended September 30, 2017. The increase in interest expense was primarily attributable to an increase in our average debt balance during the three months ended September 30, 2018 compared to the three months ended September 30, 2017.

Other Expense. Other expense was $0.1 million for the three months ended September 30, 2018, as compared to $0.2 million for the three months ended September 30, 2017. The decrease is primarily attributable to the decrease in lender related and other expenses.

Income Tax Expense/benefit. Total income tax expense was $13.6 million resulting in an effective tax rate of 22.7% for the three months ended September 30, 2018 as compared to an income tax benefit of $0.1 million and an effective tax rate of 0.4% for the three months ended September 30, 2017. The increase in income tax expense during the three months ended September 30, 2018 is primarily attributable to the increase in book income in 2018 compared to 2017, and the effect of the full valuation allowance in 2017.

The following table sets forth the results of operations for the periods presented:

(in thousands, except for percentages)

(1) Exclusive of depreciation and amortization.

(2) Inclusive of stock-based compensation.

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

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

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues. Revenues increased 91.4%, or $611.0 million, to $1,279.1 million for the nine months ended September 30, 2018, as compared to $668.2 million for the nine months ended September 30, 2017. 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 94.3%, or $602.9 million, for the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017. Revenues from services other than pressure pumping increased 28.0%, or $8.1 million, for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. The increase in revenues from services other than pressure pumping was primarily attributable to the increase in customer demand for our flowback and coil tubing services in the nine months ended September 30, 2018.

Cost of Services. Cost of services increased 75.8%, or $418.4 million, to $970.2 million for the nine months ended September 30, 2018, as compared to $551.8 million during the nine months ended September 30, 2017. Cost of services in our pressure pumping segment increased $413.8 million for the nine months ended September 30, 2018, as compared to the nine months ended September 30, 2017. The increases were primarily attributable to higher activity levels, fleet size, and 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 76.0% for the nine months ended September 30, 2018, as compared to 82.9% for the nine months ended September 30, 2017. The decrease in cost of services as a percentage of revenue for the pressure pumping segment resulted from a greater pricing power as demand for our services increased, without a corresponding increase in costs, which resulted in significantly higher realized Adjusted EBITDA margins during the nine months ended September 30, 2018.

General and Administrative Expenses. General and administrative expenses was flat, with a net marginal increase of 0.2%, or $0.1 million, to $38.9 million for the nine months ended September 30, 2018, as compared to $38.9 million for the nine months ended September 30, 2017. The net increase was primarily attributable to increases in payroll expense of $5.4 million, property taxes of $1.9 million, travel of $0.5 million, insurance expense of $1.3 million, and net aggregate increase in other remaining general and administrative expenses of $2.1 million, offset by decreases in nonrecurring legal expense of $0.7 million, stock based compensation of $4.9 million and deferred IPO bonus expense of $5.5 million.

Depreciation and Amortization. Depreciation and amortization increased 64.3%, or $24.8 million, to $63.4 million for the nine months ended September 30, 2018, as compared to $38.6 million for the nine months ended September 30, 2017. The increase was primarily attributable to the increase in our fixed asset base as of September 30, 2018, resulting from the additional property and equipment purchased in the fourth quarter of 2017 and during the nine months ended September 30, 2018. We calculate depreciation of property and equipment using the straight-line method.

Loss on Disposal of Assets. Loss on the disposal of assets increased 48.6%, or $14.1 million, to $43.1 million for the nine months ended September 30, 2018, as compared to $29.0 million for the nine months ended September 30, 2017. The increase is attributable to the increase in fleet size, greater service intensity of jobs completed and higher activity levels on certain of our equipment.

Interest Expense. Interest expense decreased 23.1%, or $1.5 million, to $5.0 million for the nine months ended September 30, 2018, as compared to $6.5 million for the nine months ended September 30, 2017. The decrease in interest expense was primarily attributable to a reduction in our average debt balance during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.

Other Expense. Other expense was $0.5 million for the nine months ended September 30, 2018, as compared to $0.8 million for the nine months ended September 30, 2017. The decrease is primarily attributable to the decreases in nonrecurring listing expenses, lender related expenses and unrealized net gain resulting from the change in fair value of our interest rate swap.

Income Tax Expense. Total income tax expense was $36.0 million resulting in an effective tax rate of 22.8% for the nine months ended September 30, 2018 as compared to $0.1 million and an effective tax rate of 4.8% for the nine months ended September 30, 2017. The increase in income tax expense during the nine months ended September 30, 2018 is primarily attributable to the increase in book income in 2018 compared to 2017, and the effect of the full valuation allowance in 2017.

Liquidity and Capital Resources

On March 22, 2017, we completed our IPO of 13,250,000 shares of common stock at $14.00 per share, from which we received net proceeds of $170.1 million which we used (i) to repay the balance on our then outstanding term loan, (ii) to acquire additional hydraulic fracturing fleets and (iii) for general corporate purposes.

On March 22, 2017, we entered into a new revolving credit facility with a $150.0 million borrowing capacity ("ABL Credit Facility"). Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with no LIBOR floor. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company. The ABL Credit Facility has a tenor of 5 years and a borrowing base of 85% of eligible accounts receivable less customary reserves. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. In addition, the ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio of 1.0x when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $12.0 million. The ABL has a commitment fee of 0.375%, which reduces to 0.25% if utilization is greater than 50% of the borrowing base.

On February 22, 2018, we entered into an amendment with our lenders to increase the capacity of the ABL Credit Facility. The amendment increased total capacity under the facility from $150.0 million to $200.0 million. The amended ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio of 1.0x when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the Borrowing Base and (ii) $15.0 million.

As of September 30, 2018, our cash and cash equivalents were $78.2 million, as compared to $23.9 million at December 31, 2017. Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our primary uses of cash will be to fund our operations, support growth opportunities and satisfy debt payments.

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

Cash and Cash Flows

The following table sets forth the historical cash flows for the nine months ended September 30, 2018 and 2017 :

($ in thousands)

Operating Activities

Net cash provided by operating activities was $251.1 million for the nine months ended September 30, 2018, compared to net cash provided in operating activities of $78.7 million for the nine months ended September 30, 2017. The net increase of $172.4 million was primarily due to the increase in our revenue generating assets (fleet size), which has resulted in increases in revenue and net income in the period, offset by our working capital needs resulting from higher fleet size and expanding activity levels.

Investing Activities

Net cash used in investing activities increased to $208.9 million for the nine months ended September 30, 2018, from $189.6 million for the nine months ended September 30, 2017. The increase was primarily attributable to the additional equipment purchased during the period, and an increase in maintenance capital expenditures during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.

Financing Activities

Net cash provided by financing activities was $12.0 million for the nine months ended September 30, 2018, and $28.3 million for the nine months ended September 30, 2017. Our net cash provided from financing activities during the nine months ended September 30, 2018, was primarily driven by cash provided from borrowings of $77.4 million, and offset by the use of cash for the repayment of borrowings of $61.9 million, insurance financing of $3.2 million, and debt issuance cost of $0.4 million. Our net cash provided from financing activities during the nine months ended September 30, 2017, was primarily driven by our borrowings of $27.1 million and IPO proceeds of $185.5 million, offset by our use of cash for repayment of borrowings of $164.6 million, insurance financing of $2.9 million, debt issuance cost of $1.7 million and IPO costs of $15.1 million.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2018.

Critical Accounting Policies and Estimates

There have been no material changes during the nine months ended September 30, 2018 to the methodology applied by our management for critical accounting policies previously disclosed in our Form 10-K. Please refer to Part II, Item 7, "Management Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our Form 10-K for a discussion of our critical accounting policies and estimates.

Recently Issued Accounting Standards

Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Condensed Consolidated Financial Statements (Unaudited) contained in this Form 10-Q.

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for West Texas Intermediate (WTI) oil and natural gas and expectations about future prices. For many years, WTI oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. WTI oil prices declined significantly close to the end of the second half of 2014. The closing price of WTI oil, which was as high as $105.68 per barrel during the third quarter of 2014, averaged $48.69 during 2015 and reached a twelve-year low of $26.19 in February 2016. However, beginning in the third quarter of 2016, WTI oil prices started recovering, and reaching an average of $69 per barrel in September of 2018. As a result of the recent recovery in WTI oil prices, our industry has experienced a significant increase in both drilling and pressure pumping activity levels. Looking forward, assuming commodity prices remain at or above recent levels, we believe U.S. rig counts will continue to increase. We expect WTI oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Higher WTI oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices.

As of September 30, 2018, there have been no material changes in market risk from the information provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or “Quantitative and Qualitative Disclosures of Market Risk” in our Form 10-K.

Evaluation of Disclosure Controls and Procedures

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

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2018.

Changes in Internal Control over Financial Reporting

No changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarterly period ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

There have been no material changes to our principal risks that we believe are material to our business, results of operations, and financial condition from the risk factors previously disclosed in our Form 10-K, which is accessible on the SEC’s website at www.sec.gov (http://www.sec.gov).