UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

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

For the quarterly period ended September 30, 2013 

 

OR

 

[  ] 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: 333-184491

 

U.S. WELL SERVICES, LLC

(Exact name of registrant as specified in its charter)

 

 

 

 

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 [x] 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 [x] No [ ]

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

 

 

 

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

 

 

 

 

 

---

 

TABLE OF CONTENTS

 

 

---

 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

U.S. Well Services, LLC's (together with its subsidiary, “we,” “us,” or “our”) reports, filings and other public announcements may from time to time contain certain forward-looking statements. When used, statements which are not historical in nature, including those containing words such as “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “will,” “future” and similar expressions are intended to identify forward-looking statements in this report regarding us and our subsidiary.

 

These forward-looking statements reflect our current views with respect to future events and are based on assumptions and subject to risks and uncertainties. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the factors that could cause actual results to differ materially are the risks and uncertainties described under “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2012 and Part II, Item 1A of this Quarterly Report on Form 10-Q, including the following:

 

---

 

 

Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements.

 

Many of these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

 

All forward-looking statements included in this Quarterly Report on Form 10-Q are made only as of the date of this Quarterly Report on Form 10-Q, and we do not undertake any obligation to publicly update or correct any forward-looking statements to reflect events or circumstances that subsequently occur, or of which we become aware after the date of this Quarterly Report on Form 10-Q. You should read this Quarterly Report on Form 10-Q completely and with the understanding that our actual future results may be materially different from what we expect. We may not update these forward-looking statements, even if our situation changes in the future. All forward-looking statements attributable to us are expressly qualified by these cautionary statements.

 

---

 

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

U.S. WELL SERVICES, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

---

 

U.S. WELL SERVICES, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

---

 

U.S. WELL SERVICES, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

---

 

U.S. WELL SERVICES, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

---

 

U.S. WELL SERVICES, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

(Unaudited)

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

 

---

 

 

NOTE 1 - DESCRIPTION OF BUSINESS

On February 21, 2012, U.S. Well Services, LLC (the “Company,” “we,” “our” or “USWS”) was formed as a Delaware limited liability company.  The Company is a Houston, Texas based oilfield service provider of well stimulation services to the upstream oil and natural gas industry.  We engage in high-pressure hydraulic fracturing in unconventional oil and natural gas basins. The fracturing process consists of pumping a specially formulated fluid into perforated well casing, tubing or open holes under high pressure, causing the underground formation to crack or fracture, allowing nearby hydrocarbons to flow more freely up the wellbore.

The predecessor to the Company was U.S. Well Services, Inc. (“USWS, Inc.”), which was incorporated in Delaware on August 18, 2011. The Company was capitalized via a contribution by USWS, Inc. of substantially all of the assets and contracts of USWS, Inc. in exchange for 167,500 of the Company’s Series C Units (the “Restructuring”). Contemporaneously with the formation of the Company, ORB Investments, LLC, a Louisiana limited liability company (“ORB”), made a $30 million equity investment in the Company (the “Sponsor Equity Investment”), in exchange for 600,000 of the Company’s Series A Units and 600,000 of the Company’s Series B Units. In addition, concurrently with the formation of the Company, USW Financing Corp. ("USW Finance") was formed as a wholly-owned finance subsidiary of the Company for the purpose of acting as a co-obligor for an offering of 85,000 units with each unit consisting of $1,000 principal amount of 14.50% Senior Secured Notes due 2017 (the "Original Notes") and a warrant to purchase the Company’s Series B Units (the “Unit Offering”).

The predecessor company was a development stage enterprise and had primarily been involved in start-up activities, including acquiring property and equipment and securing customer contracts.

The Company began operations under a take or pay contract with Antero Resources Appalachian Corporation (“Antero”), for a 24 month service period commencing on April 12, 2012 to perform hydraulic fracturing services in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania (the “Original Antero Contract”). Prior to beginning operations in the second quarter of 2012, the Company was in the development stage.

 

NOTE 2 - BASIS OF PRESENTATION

The accompanying unaudited condensed consolidated financial statements  include the accounts of the Company and its subsidiary, USW Finance.  All significant intercompany balances and transactions have been eliminated in consolidation.

These unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments necessary for the fair presentation of the Company’s financial position, results of operations and cash flows for the interim periods presented have been included.  These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012.

 

NOTE 3 – SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. We regularly evaluate estimates and judgments based on historical experience and other relevant facts and circumstances. Significant estimates included in these financial statements primarily relate to estimated useful lives of property and equipment and the valuation of unit-based compensation. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with an original maturity at the date of acquisition of three months or less. Cash and cash equivalents consist of cash on deposit with domestic banks and, at times, may exceed federally insured limits.

The Company maintains zero balance cash disbursement accounts with a  certain bank. Outstanding checks in excess of funds on deposit with the bank, referred to as cash overdrafts, are classified as part of Accounts Payable on the Condensed Consolidated Balance Sheet, and totaled $2.0 million  as of September 30, 2013.  There were no cash overdrafts as of December 31, 2012. Changes in these overdraft amounts are recorded as financing activities on the Condensed Consolidated Statements of Cash Flows.

---

 

Fair Value of Financial Instruments

Fair value is defined under Accounting Standards Codification (ASC) 820, Fair Value Measurement, as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 also establishes a three-level hierarchy, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels are defined as follows:

Level 1–inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2–inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3–inputs are unobservable for the asset or liability.

The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of September 30, 2013:  

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities. These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date.

14.50% Senior Secured Notes due 2017. The fair value of the notes is estimated using level 2 inputs by obtaining from the broker the quoted price as of September 30, 2013. The carrying value of these notes as of September 30, 2013 was $80.4 million, and the fair value was $82.0 million  (102.0% of carrying value).

Major Customer and Concentration of Credit Risk

The concentration of our customers in the oil and natural gas industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.

During the three months ended September 30, 2013 and 2012, Antero accounted for approximately 92.2% and 99.4%, respectively, of our consolidated revenues. No customer other than Antero accounted for more than 10% of our consolidated revenues during the three months ended September 30, 2013 and 2012.  

Antero accounted for approximately 86.8% and 99.0% of our consolidated revenues for the nine months ended September 30,  2013 and 2012, respectively. No customer other than Antero accounted for more than 10% of our consolidated revenues during the nine months ended September 30, 2013 and the period from February 21, 2012 (inception) through September 30, 2012.

Receivables outstanding from Antero were approximately 78.6% of our total accounts receivable as of September 30, 2013. One other customer accounted for approximately 21.3% of our total accounts receivable as of September 30, 2013.  

Recently Issued Accounting Pronouncements

We do not expect the adoption of recently issued accounting pronouncements to have a material impact on the Company’s results of operations, balance sheet or cash flows.

 

NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

 

 

---

 

 

Depreciation and amortization expense for the three months ended September 30, 2013 and 2012 was $3,536,235 and $2,134,227, respectively. Depreciation and amortization expense for the nine months ended September 30, 2013 was $9,255,710. Depreciation and amortization expense for the period February 21, 2012 (inception) through September 30, 2012 was $3,619,089.  

The Company capitalized interest of $153,089 for the three months and nine months ended September 30, 2013. The Company capitalized interest of $50,029 for the three months ended September 30, 2012 and $248,225 for the period February 21, 2012 (inception) through September 30, 2012. 

 

NOTE 5 – SHORT-TERM NOTE PAYABLE

On March 15, 2013, the Company obtained insurance for its general liability, workers' compensation, umbrella, auto and pollution coverage needs.  The Company made an initial down payment and entered into a premium finance agreement with a credit finance institution to pay the remainder of the premiums. The aggregate amount of the premiums financed is $1,748,721 at an interest rate of 3.9%.  Under the terms of the agreement, the Company has agreed to pay 9 equal monthly payments of $197,473 beginning April 15, 2013 through maturity on December 15, 2013.  As of September 30, 2013, the note had a balance of $393,188.

 

NOTE 6 – REVOLVING CREDIT FACILITY

On May 9, 2013, we entered into a Credit and Security Agreement (the “Credit Agreement”) with Wells Fargo Bank, National Association (the “Lender”) pursuant to which the Lender agreed to extend credit to us in the form of a revolving credit facility up to $7.5 million (the “Revolving Credit Facility”). The Revolving Credit Facility includes a sublimit for the issuance of letters of credit in an aggregate amount of up to $1.0 million.

The Lender will make revolving loans (“Loans”) by way of Fixed Rate LIBOR Loans and Variable Rate LIBOR Loans to the Company in aggregate amounts outstanding at any time not to exceed an amount (the “Borrowing Base”) that is the lesser of (i) $7.5 million less the sum of (A) the aggregate undrawn amount of all outstanding letters of credit, and (B) the aggregate amount of outstanding reimbursement obligations with respect to letters of credit, which remain unreimbursed or which have not been paid through a Loan, or (ii) an amount equal to the result of: (A) the lesser of (y) 85% (less the amount, if any, of the Dilution Reserve (as defined in the Credit Agreement), if applicable) of the amount of Eligible Accounts (as defined in the Credit Agreement), and (z) $7.5 million, minus (B)$500,000, as such amount may be adjusted by the Lender from time to time, in its sole discretion, minus (C) the aggregate amount of Reserves (as defined in the Credit Agreement), if any, established by the Lender in its Permitted Discretion (as defined in the Credit Agreement). Loans may be repaid by the Company and, subject to the terms and conditions of the Credit Agreement, reborrowed at any time during the term of the Credit Agreement.

The interest rate per annum on the Revolving Credit Facility is equal to (i) at our option, (A) the daily three month LIBOR with respect to Variable Rate LIBOR loans, which interest rate shall change whenever daily three month LIBOR changes, or (B) LIBOR for the specified interest period with respect to Fixed Rate LIBOR loans, and (ii) the applicable margin. The applicable margin is determined as one percentage point when the Interest Rate is based on the Prime Rate, or three percentage points with respect to Fixed Rate LIBOR loans or Variable Rate LIBOR loans. 

The Credit Agreement contains financial covenants, which require us to:

    maintain a fixed charge coverage ratio, measured monthly on a trailing twelve-month basis at the end of each month, commencing no later than the month ended May 31, 2014, of not less than 1.0:1.0.

     maintain (i) liquidity of at least $5 million, (ii) gross availability of at least $1 million, and (iii) cash plus availability of at least $1 million, in each case, at all times during the period commencing on August 1, 2013, through and including the date upon which the Company has maintained a fixed charge coverage ratio of not less than 1.0:1.0 for two consecutive calendar months.  After the Company has maintained a fixed charge coverage ratio of not less than 1.0:1.0 for two consecutive calendar months, the Lender shall not test the covenants set forth in Section 8.1(b) of the Credit Agreement regarding maintenance of liquidity, gross availability and cash plus availability.

All obligations of the Company under the Credit Agreement are secured by a continuing security interest in all of the Company's right, title, and interest in and to substantially all of the Company's assets.

---

 

All of the Company's obligations outstanding under the Credit Agreement shall be payable in full on the earliest of (i) May 9, 2017, or (ii) ninety days prior to the maturity date of the Company's 14.50% Senior Secured Notes due 2017, or (iii) ninety days prior to the maturity date of the Company's Series A Units, or (iv) the date the Company terminates the Revolving Credit Facility, or (v) the date the Revolving Credit Facility terminates pursuant to the Credit Agreement following an Event of Default.

 

As of September 30, 2013, we had borrowings of $0.1 million outstanding under the Revolving Credit Facility, leaving $6.9 million of available borrowing capacity under our current Borrowing Base. The weighted average interest rate on the outstanding borrowings under the Revolving Credit Facility was 3.4% for the three months and nine months ended September 30, 2013.

 

NOTE 7 – LONG TERM DEBT

Long-term debt consisted of the following:

 

 

 

Senior Secured Notes.    On April 10, 2013, the Company completed an offering of $12.0 million in aggregate principal amount of 14.50% Senior Secured Notes due 2017 (the "April 2013 Additional Notes" and together with the Original Notes and the October 2013 Additional Notes (as defined below), the "Notes"), the net proceeds of which were used to acquire a third hydraulic fracturing fleet. We issued the April 2013 Additional Notes as additional notes under the Indenture dated February 21, 2012 (the “Base Indenture”), by and among us, the guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent, as supplemented by that First Supplemental Indenture dated as of July 16, 2012 (the “First Supplemental Indenture”), and as further supplemented by that Second Supplemental Indenture dated as of April 10, 2013 (the “Second Supplemental Indenture”) and by that Third Supplemental Indenture dated as of October 18, 2013 (the “Third Supplemental Indenture” and, together with the Base Indenture, the First Supplemental Indenture and the Second Supplemental Indenture, the “Indenture”). On February 21, 2012, we issued $85.0 million aggregate principal amount of the Original Notes under the Base Indenture. In August 2012, we repurchased and retired $21,066,046 aggregate principal amount of the Original Notes (the “Second Contract Repurchase”) and made our first interest payment on the Original Notes by increasing the principal amount of the outstanding notes by $4,480,706. In November 2012, we repurchased but did not retire $2.5 million aggregate principal amount of the Original Notes. As of September 30, 2013, we had outstanding $80.4 million aggregate principal amount of the Notes. The Notes will mature on February 15, 2017. The Notes have a fixed annual interest rate of 14.50% on the principal amount which is due semi-annually, on February 15 and August 15 of each year.  Accrued interest on the Notes was $1,457,516 at September 30, 2013.  

Our sole subsidiary, USW Finance, is a co-issuer of the Notes. The Notes may be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of our current and future domestic subsidiaries, other than subsidiaries designated as unrestricted subsidiaries.  None of our future foreign subsidiaries will guarantee the Notes.  The Notes and any future guarantees are subject to a lien on substantially all of our and our future subsidiaries' assets, subject to certain exceptions.  If and when we incur permitted first lien indebtedness, the liens on the assets securing the Notes and any future guarantees will likely be contractually subordinated and junior to liens securing such permitted first lien indebtedness pursuant to an intercreditor agreement. The indenture governing the Notes restricts us and our restricted subsidiaries from making certain payments, including dividends and intercompany loans or advances.

The Notes are subject to optional redemption features whereby: (a) on or after February 15, 2015, we may redeem some or all of the Notes at a premium that will decrease over time, (b) prior to February 15, 2015, we may, at our option, redeem up to 35% of the aggregate principal amount of the Notes using the net proceeds of certain equity offerings at a price equal to 110% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, to the date of redemption;

---

 

provided that, following any and all such redemptions, at least 65% of the aggregate principal amount of the Notes originally issued under the indenture remain outstanding and the redemption occurs within 90 days of the closing of such equity offering, and (c) at any time prior to February 15, 2015, we may, at our option, redeem all or a part of the Notes, upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Notes redeemed, plus a specified make-whole premium, plus accrued and unpaid interest and additional interest, if any, to the applicable date of redemption.  The Notes are also subject to certain mandatory redemption provisions whereby within 45 days after each March 31 or September 30 beginning on March 31, 2013 but not including March 31, 2014, for which our cash and cash equivalents are greater than $12.1 million, we are required to offer to repurchase Notes in the amount of such excess cash amount at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

Equipment financing agreement.  On July 30, 2012, the Company entered into a security agreement with a financing institution for the purchase of certain fracturing equipment.  The aggregate principal amount of the financing agreement is $1,951,610 and bears effective interest at 6.5%.  Under the terms of the agreement, the Company is required to pay 48 equal monthly payments of $46,386, including interest, beginning September 13, 2012 through maturity on September 13, 2016.  As of September 30, 2013, the financing agreement had a balance of $1,434,266, of which $436,530 is due within one year.

 

NOTE 8 - REDEEMABLE SERIES A UNITS

As part of the Sponsor Equity Investment, the Company authorized and issued 600,000 of its Series A Units. The holders of the Series A Units are not entitled to receive any ordinary distributions from the Company, are subject to certain drag-along rights, and do not have any preemptive rights relating to the Company.  Pursuant to the terms of our Amended and Restated Limited Liability Company Agreement (the “Company Agreement”), ORB has the right to appoint all of the members of the Company's Board of Managers, except for one position on the Board of Managers which is required to be filled by the Company's Chief Executive Officer. The Board of Managers is to have the discretion to manage and conduct all the business and affairs of the Company.

The holders of Series A Units, in certain instances, are entitled to have their Series A Units redeemed by the Company for a distribution in an amount that provides each Series A Unit holder with an internal rate of return of 13% on their investment with respect to their Series A Units.  The payment of the redemption price to Series A Unit holders shall be paid, upon the occurrence of one of the following triggering events:  (i) a liquidation of the Company (whether by consent of the Company’s Board of Managers and ORB, or withdrawal of all members or in accordance with Section 18-202 of the Delaware Limited Liability Company Act), (ii) a transfer of all of the assets or units of the Company, a merger or similar transaction or certain initial public offerings of the Company’s or its successor’s securities, or (iii) February 17, 2017.  The payment of the redemption price to the Series A Unit holders shall occur before any distribution is made to the holders of the Series B, C or D Units.

The Series A Units have an optional redemption feature pursuant to which, subject to the prior approval of ORB, the Company retains the option to redeem all or any portion of the Series A Units at any time in exchange for payment of an amount that provides each Series A Unit holder with an internal rate of return of 13% on their capital contribution with respect to their Series A Units.

Because of the mandatory redemption features of the Series A Units which unconditionally obligate the Company to provide each holder with an internal rate of return of 13% on their investment, regardless of the triggering events, the units demonstrate characteristics of debt and therefore are accounted for as a long-term liability.

At September 30, 2013, the mandatorily redeemable Series A Units totaling $29,994,000 are reported as a long-term liability on the balance sheet with accrued interest in the amount of $6,762,999.  The maximum amount the Company could be required to pay to redeem the units on the mandatory redemption date of February 17, 2017 includes the face value of the units of $29,994,000 and interest to be accrued of $26,213,401.

 

NOTE 9 – MEMBERS’ INTEREST

The Company’s equity consists of four classes of membership interests, each designated with its own series of units.  Series A Units are the Company’s preferred equity and Series B, C and D Units represent the Company’s common equity. See Note 8 - Redeemable Series A Units for further discussion of Series A Units. The Series B, C and D Units are equal in most respects, except that the Series B Units have anti-dilution protections and pre-emptive rights that the Series C and D Units generally do not have. Series D Units granted to certain officers have anti-dilution protections. Additionally, the Series B Units have more limited transfer restrictions than the Series C and D Units have. The Series D Units constitute profits interests, and are granted to certain officers and employees of the Company as performance incentives.  See Note 10 - Unit-Based Compensation for further discussion of the Series D Units.

---

 

As of September 30, 2013 and December 31, 2012, there were 630,000 Series B Units, 192,500 Series C Units, and 47,706 Series D Units issued and outstanding.

In conjunction with the Unit Offering, the Note holders received 85,000 warrants that entitle each holder to receive 1.7647 Series B Units at an exercise price of $0.01 per unit, representing approximately 150,000 Series B Units in aggregate or 15% of the Company’s common equity interests.  The holders of the warrants have anti-dilution protections. The warrants became exercisable after they separated from the Notes on April 21, 2012 and will expire on February 21, 2019.  As of September 30, 2013, none of these warrants had been exercised.

 

NOTE 10 – UNIT-BASED COMPENSATION

During the three months ended September 30, 2013 and 2012, we recognized unit-based compensation expense totaling $39,251 and $24,727, respectively, which were included in selling, general and administrative expenses. During the nine months ended September 30, 2013, we recognized unit-based compensation expense totaling $117,753, which was included in selling, general and administrative expenses. For the period from February 21, 2012 (inception) to September 30, 2012, we recognized unit-based compensation expense totaling $241,651, of which $77,700 was included in cost of services and $163,951 was included in selling, general and administrative expenses.

As of September 30, 2013, the total unrecognized compensation cost related to unvested awards was approximately $286,031, which is expected to be recognized over a weighted-average period of 0.88 years.

 

NOTE 11 – EMPLOYEE BENEFIT PLAN

On March 1, 2013, the Company established the U.S. Well Services 401(k) Plan. We match 100% of employee contributions up to 6% of the employee’s salary, subject to cliff vesting after two years of service. Our matching contributions were $157,512 and $307,358 for the three months ended and nine months ended September 30, 2013, respectively. 

 

NOTE 12 – COMMITMENTS AND CONTINGENCIES

Litigation

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

In August 2012, the Company, together with certain of its officers, became co-defendants in an action filed by Calfrac Well Services, Ltd. and Calfrac Well Services Corp. (collectively, "Calfrac") alleging conspiracy to steal Calfrac's trade secrets, proprietary business and confidential information, customers and employees and other information for the purpose of setting up the Company's predecessor. Further, Calfrac sought actual and compensatory damages in connection with allegations of breach of contract and certain duties by certain of the Company's officers. On June 28, 2013, the Company entered into a settlement agreement and mutual release with Calfrac. The Company recorded a loss relating to the settlement during the second quarter of 2013.

Sand Purchase Agreement

On November 9, 2012, we entered into an agreement with a supplier to purchase sand for use in our hydraulic fracturing operations. The agreement is effective on November 1, 2012 for a term of two years, subject to renewal options. Under the terms of this agreement, we are required to purchase from this supplier a quarterly minimum quantity of sand at a fixed price, amounting to approximately $1.1 million per quarter. In the event we fail to purchase any portion of sand required to be purchased on a quarterly basis, we are required to make payments to the supplier for amounts not taken, up to the contractual minimum and subject to the terms of the agreement. For the three months ended and nine months ended September 30, 2013, the total amount purchased under the agreement was $3.3 million and $11.9 million. We do not believe that non-performance on our part would have a material impact on our financial position, cash flows or results of operations.

 

NOTE 13 – SUBSEQUENT EVENTS

Issuance of New Notes

On October 18, 2013, the Company completed the issuance and sale of $46.0 million in aggregate principal amount of 14.50% Senior Secured Notes due 2017 (the “October 2013 Additional Notes” and together with the April 2013 Additional Notes, the “Additional Notes”), under the Indenture. We will use substantially all of the proceeds from the October 2013 Additional Notes to acquire both a fourth and fifth hydraulic fracturing fleet and associated heavy equipment and materials.

---

 

Agreement to Issue New Membership Units

Concurrently with the issuance and sale of the October 2013 Additional Notes, the Company entered into a subscription agreement (the “Series E Subscription Agreement”) with one of our existing investors and an affiliate thereof. Pursuant to the Series E Subscription Agreement, the investors agreed to purchase, and the Company agreed to issue, $14.0 million of Series E Units, provided that the number of Series E Units to be issued to such investors will be subject to reduction as a result of any other participating investors.  The Series E Units will be governed by and issued pursuant to the First Amendment to the Company Agreement, which, among other things, will entitle the holders of Series E Units to a 13% preferred return on their equity contribution compounded semiannually and payable upon the occurrence of certain liquidation or exit events. The investors have prefunded the purchase price for the Series E Units, which will be issued at a closing expected to occur prior to the end of the year.

Equipment Purchase Commitment

In October 2013, we entered into agreements with various vendors for the purchase of the fourth hydraulic fracturing fleet, which is expected to consist of nine fracturing pumps and associated heavy equipment.  As of November 6, 2013, we had paid approximately $9.6 million towards the purchase of our fourth fleet. We anticipate delivery of the fourth fleet to be completed in mid-November 2013. 

Construction began in October 2013, pursuant to agreements we entered into with various vendors, for the fracturing pumps and associated heavy equipment that are expected to compose the fifth hydraulic fracturing fleet, which will be a proprietary designed “Clean Fleet.” The Clean Fleet is a proprietary, patent-pending design that incorporates existing industry equipment configured in a novel manner to provide fracturing services at a lower cost with a smaller environmental and physical footprint, as well as with enhanced safety features, compared to traditional fracturing equipment. The Clean Fleet is expected to consist of 16 fracturing pumps and associated heavy equipment powered by electric motors, with electricity produced by mobile turbine generators that can burn a variety of hydrocarbon fuels, including natural gas. As of November 6, 2013, we had paid approximately $8.8 million towards the purchase of our fifth fleet. We anticipate delivery of the fifth fleet in April 2014 with operations beginning in May 2014.  

Series D Unit Agreements

In October and November 2013, we entered into Amended and Restated Series D Unit agreements (“Amended Agreements”) with certain officers and key employees, pursuant to which 110,503 units became vested upon the execution of the Amended Agreements. A total of 65,049 units remain unvested until the occurrence of a liquidation or exit event. The vesting of such Series D Units triggered certain anti-dilution protections granted to the holders of our Series B Units in our Company Agreement and certain of our executive officers in their Series D Unit Agreements.

 

 

 

 

 

 

 

---

 

ITEM 2. 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 consolidated financial statements and the related notes and other financial information included elsewhere in this Quarterly Report on Form 10-Q. Some of the information contained in this discussion and analysis or set forth elsewhere in this Quarterly Report on Form 10-Q, including information with respect to our plans and strategy for our business and related financing, include forward-looking statements that involve risks and uncertainties. You should review the section entitled “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2012 and Part II, Item 1A of this Quarterly Report on Form 10-Q 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.  

Overview

We are a Houston, Texas based oilfield services provider of well stimulation services to the upstream oil and gas industry. We currently engage in high-pressure hydraulic fracturing in unconventional oil and natural gas basins. The fracturing process consists of pumping a specially formulated fluid into perforated well casing, tubing, or open holes under high pressure, causing the underground formation to crack or fracture, allowing nearby hydrocarbons to flow more freely up the wellbore.

We believe our hydraulic fracturing fleets are reliable and high performing fleets with the capability to meet the most demanding pressure and flow rate requirements in the field.  Our management team has extensive industry experience providing completion services to exploration and production companies.  We intend to focus on the most active shale and unconventional oil and natural gas plays in the United States.

We are Delaware limited liability company. Our corporate office is located at 770 South Post Oak Lane, Suite 405, Houston, Texas 77056 and our main telephone number is (832) 562-3730.

We began operations under a take or pay contract, our original contract, with Antero, for a 24-month service period commencing on April 12, 2012. Prior to beginning operations in the second quarter of 2012, we were in the development stage. We currently perform services in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania.  We are also evaluating opportunities with existing and new customers to expand our operations into new areas throughout North America, which may include the Bakken Shale in North Dakota and Montana, the Haynesville Shale in northwestern Louisiana and eastern Texas, the Eagle Ford Shale in southern Texas, and other formations in Texas, New Mexico, Colorado, Wyoming, Nebraska, Oklahoma and Canada.

Current Contracts

Original Antero Contract.  Our Original Antero Contract provides for a 24-month service period commencing when services began on April 12, 2012.  The contract is renewable for one additional year upon the mutual written consent of both parties. The Original Antero Contract includes minimum performance requirements related to the number of stages to be completed quarterly.

If Antero requires more than the minimum agreed upon fracturing days per quarter, it will give us written notice thereof, and we will charge a per-stage price for such additional services at the same rate. We will operate on a 24-hour service schedule. We will be paid mobilization fees (based on mileage from the location of our fleet, charged at the initial stage of each job), as well as operating stage/well rates described in the Original Antero Contract and standby time rates under certain circumstances, dedicated fracturing fleet charges ("DFFCs"), and agreed upon down-time rates per stage. If Antero does not provide us with the minimum quarterly stages through no fault of ours, Antero will owe us an agreed upon rate of DFFCs per stage for any stages less than the minimum quarterly stages. The Original Antero Contract also provides for force majeure payment rates and payments in the event a governmental body or regulatory agency issues a mandate that either makes it impossible for us to continue operations or causes an increase in our rate. Antero may terminate the contract on 60 days’ written notice, in which case it must pay us a lump sum payment of up to a maximum agreed upon amount within an agreed upon time. The Original Antero Contract also allows Antero to direct the stoppage of services on reasonable written notice to us, in which case it must pay us a standby time rate. The rates described in the Original Antero Contract are to be revised on an agreed upon schedule to reflect certain cost increases or decreases if the costs exceed an agreed upon percentage of start date costs.

Rider to Original Antero Contract. On June 5, 2012, we entered into Rider No. 1 to Contract to Provide Dedicated Fleet(s) for Fracturing Services with Antero (the "Rider").  The Rider amends certain terms of our Original Antero Contract.  The Rider gives Antero, in its sole discretion, a right of first refusal to engage all or any portion of our second hydraulic fracturing fleet at negotiated rates.  In addition, the Rider modifies our Original Antero Contract to discount all services performed by us for Antero (whether such services are performed under our original contract with Antero or in the future by our second hydraulic fracturing fleet) by ten percent.  We believe that entering into the Rider strengthened our relationship with Antero and provides us with the opportunity to grow revenues by participating in Antero's expanding drilling program.

---

 

Amendment to Original Antero Contract.  On October 9, 2013, we entered into an Amendment to Contract to Provide Dedicated Fleet(s) for Fracturing Services effective September 30, 2013 (the “Antero Contract Amendment”), with Antero. The Antero Contract Amendment extends the term of the Original Antero Contract for three years to April 12, 2017.

The Antero Contract Amendment includes minimum performance requirements related to the number of stages to be completed quarterly and requires that the services will be provided by a dedicated fleet to be acquired by us. The Antero Contract Amendment provides that Antero (i) has a right of first refusal to engage any of our additional fleets that are available to provide services similar to those to be performed for Antero at market rates, (ii) may terminate the agreement upon the payment of an early termination fee and (iii) may terminate the agreement, or grant an extension to the commencement date at Antero’s discretion, if the Company does not commence services utilizing a proprietary designed fleet by June 12, 2014.

Contract with Inflection Energy LLC.  On September 23, 2013, we entered into a Dedicated Fracturing Fleet Agreement, effective November 1, 2013 (the “Inflection Agreement”), with Inflection Energy LLC (“Inflection”), pursuant to which the Company has agreed to provide a dedicated fleet, consisting of certain specified equipment and materials, to perform fracturing services for Inflection in the Marcellus Shale in Pennsylvania. The Inflection Agreement terminates on December 31, 2014, unless terminated earlier pursuant to its terms.

Pursuant to the Inflection Agreement, the Company is to provide a minimum number of stages during the term of the Inflection Agreement. In the event that Inflection does not provide the Company with the minimum number of stages, Inflection will pay the Company an agreed upon dedicated fleet charge per stage for any stage less than the minimum number of stages. If the Company does not provide the minimum number of stages, then the Company will pay Inflection an agreed upon dedicated fleet charge per stage for any stage less than the minimum number of stages. If the Company performs the minimum number of stages, then Inflection has the option to extend the term of the Inflection Agreement. The Company will be paid an agreed upon mobilization fee (applied to the first stage of each pad) and an agreed upon operating rate for the provision of services under the Inflection Agreement. The Inflection Agreement also provides for force majeure payment rates.

Spot Market Projects. Although we have entered into term contracts with Antero and Inflection, we also have the flexibility to pursue spot market projects.  Our agreements with Antero and Inflection allow us to supplement monthly contract revenue by deploying equipment on short-term spot market jobs on those days when Antero or Inflection do not require our services or are not entitled to our services. When providing these types of short-term services we will charge prevailing market prices for spot market work. We may also charge fees for the set up and mobilization of equipment depending on the job.  These fees and other charges vary depending on the equipment and personnel required for the job and the market conditions in the region in which the services are performed.  We believe our ability to provide services in the spot market allows us to develop new customer relationships.

Chemicals and Proppants. We may also source chemicals and proppants that are consumed during the fracturing process and charge our customers a fee for providing such materials.  We may also charge our customers a handling fee for chemicals and proppants supplied by the customer.  Such charges for materials will generally reflect the cost of the materials plus a markup and will be based on the actual quantity of materials used in the fracturing process.

How We Obtain Our Equipment

On November 9, 2011, we entered into an agreement with a vendor to purchase a hydraulic fracturing fleet to service our original contract with Antero.  This is our initial hydraulic fracturing fleet and was manufactured to our specifications.  This hydraulic fracturing fleet is equipped to perform all aspects of hydraulic fracturing operations, including acid stimulation, high-pressure pumping and pressure testing.  The fleet includes twenty FT-2251T Trailer Mounted Fracturing Units with Triplex Pumps with 2,000 hydraulic horsepower ("HHP") per pump, three MT-132 Trailer Mounted 130bpm Fracturing Blenders with AccuFrac Systems, two data trailers, one chemical additive trailer and two CT-5CAS/HYD hydration units.  Initial deliveries of our first fracturing fleet began in February 2012 and were completed in April 2012.

In July and August 2012, we entered into agreements with various vendors for the purchase of our second hydraulic fracturing fleet.  The fleet includes fourteen FT-2251T Trailer Mounted Fracturing Units with Triplex Pumps with 2,000 HHP per pump, two MT-132 Trailer Mounted 130bpm Fracturing Blenders with AccuFrac Systems, one data van and two CT-5CAS/HYD hydration units.  Delivery of the equipment was completed in August 2012.

In April 2013, we entered into agreements with various vendors for the purchase of a third hydraulic fracturing fleet. The fleet includes twelve F-2500 Trailer-Mounted Fracturing Units with Quintuplex Pumps with 2,500 brake horsepower ("BHP") per pump, two Trailer Mounted 130bpm Fracturing Blenders, one data van, and one CT 250bbl hydration unit. Delivery of the equipment was completed in May 2013.

In April 2013, we entered into an agreement with a vendor for the purchase of additional fracturing equipment.  The fracturing equipment includes seven FT-2251Q Trailer Mounted Fracturing Units with Quintuplex Pumps with 2,250 BHP per pump, and one MT-132 Trailer Mounted 130bpm Fracturing Blender with AccuFrac System.  Delivery of the equipment was completed in early October 2013.

---

 

In October 2013, we entered into agreements with various vendors for the purchase of a fourth hydraulic fracturing fleet. The fleet includes nine Trailer-Mounted Fracturing Units with Quintuplex Pumps with 2,500 BHP per pump, three Trailer Mounted 1,600 BHP Fracturing Blenders, one data van, and one 250bbl hydration unit. Delivery of the equipment is expected to be completed in mid-November 2013.

In October 2013, we entered into agreements with various vendors for the purchase of a fifth hydraulic fracturing fleet, which will be a proprietary designed “Clean Fleet.” The Clean Fleet is a proprietary, patent-pending design that incorporates existing industry equipment configured in a novel manner to provide fracturing services at a lower cost with a smaller environmental and physical footprint, as well as with enhanced safety features, compared to traditional fracturing equipment. The Clean Fleet is expected to consist of 16 fracturing pumps and associated heavy equipment powered by electric motors, with electricity produced by mobile turbine generators that can burn a variety of hydrocarbon fuels, including natural gas. We anticipate delivery of the fifth fleet in April 2014 with operations beginning in May 2014.

Challenges

We face many challenges and risks in the industry in which we operate.  Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks, and we have taken steps to mitigate them to the extent practicable.  In addition, we believe that we are well positioned to capitalize on the current growth opportunities in the hydraulic fracturing market.  However, we may be unable to capitalize on our competitive strengths to achieve our business objectives and, consequently, our results of operations may be adversely affected.  Please read the "Risk Factors" section in our  Annual Report on Form 10-K for the year ended December 31, 2012 and the sections titled “Cautionary Statement Regarding Forward-Looking Statements” and "Risk Factors" in this Quarterly Report on Form 10-Q for additional information about the risks we face.

Hydraulic Fracturing Legislation and Regulation.  Congress has from time to time, including during the current session, considered legislation to provide for the federal regulation of hydraulic fracturing and to require public disclosure of the chemicals used in the fracturing process.  If such current or any future legislation becomes law, it could establish an additional level of regulation that could lead to us experiencing operational delays or increased operating costs.  The United States Environmental Protection Agency (the "EPA") promulgated rules that establish new air emission controls for oil and natural gas production and natural gas processing operations.  Among other controls, the rules require operators to use “green completions” for hydraulic fracturing by January 1, 2015 (unless required earlier under a state or local law), meaning operators will have to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process.  In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing.  The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our and our customers’ costs of compliance and adversely affect the quality of the hydraulic fracturing services that we provide for our customers.  Additionally, if hydraulic fracturing becomes further regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or if states or localities impose additional regulatory requirements, fracturing activities could become subject to additional permitting or regulatory requirements and also to permitting delays and potential cost increases, all of which could adversely affect our business and results of operations.

Financing Future Growth.  To date, we have used the proceeds of the Unit Offering, the Sponsor Equity Investment, the offering of Additional Notes, the Revolving Credit Facility, and cash flows generated from operations to acquire three hydraulic fracturing fleets and to fund our operations, and we will use the cash generated from the offering of the October 2013 Additional Notes and the new Series E Units to acquire two additional hydraulic fracturing fleets. The successful execution of our business strategy depends on our ability to raise capital as needed to, among other things, finance the purchase of additional hydraulic fracturing fleets and to maintain the equipment we have already purchased.  If we are unable to generate sufficient cash flows from operations or obtain additional capital, we may be unable to sustain or increase our current level of growth in the future.  There is no guarantee that we will be able to raise the additional capital that will be needed to grow our business on favorable terms or at all.

Outlook

While the demand for hydraulic fracturing services has increased significantly in recent years, the pressure pumping market currently has excess capacity.  We believe the following trends, among others, will lead to increased demand for our services and have the potential to continue to support the growth of our business going forward:

---

 

Results of Operations

Three Months Ended September 30, 2013

 

 

Revenue for the three months ended September 30, 2013 increased $26.6 million, or 124.0%, to $48.0 million from $21.4 million for the three months ended September 30, 2012, due mainly to three hydraulic fracturing fleets being operational in the third quarter of 2013 as compared to only two fleets in the third quarter of 2012.

Cost of services increased $18.2 million, or 111.1%, to $34.5 million for the three months ended September 30, 2013 compared to $16.3 million for the three months ended September 30, 2012. The increase was a direct result of increased hydraulic fracturing activity. 

Depreciation and amortization totaled $3.5 million for the three months ended September 30, 2013 compared to $2.1 million for the three months ended September 30, 2012. The $1.4 million, or 65.7%, increase is mainly due to depreciation expense for three fleets in the third quarter 2013 compared to only two fleets in the third quarter 2012.  

Our selling, general and administrative expenses remained the same at $1.5 million during the three months ended September 30, 2013 and 2012.  

Interest expense for the third quarter 2013 totaled $4.3 million compared to $6.7 million for the third quarter 2012. The 2.4 million, or 35.8% decrease is primarily due to the loss on extinguishment of debt in connection with the Second Contract Repurchase in August 2012.

Nine Months Ended September 30, 2013 

 

---

 

 

Revenues increased $92.5 million, or 302.2%, to $123.1 million for the nine months ended September 30, 2013 from $30.6 million for the period from February 21, 2012 (inception) to September 30, 2012. The increase is primarily due to increased hydraulic fracturing activity with three fleets being operational beginning May 2013, as compared to only two fleets in service for the period from February 21, 2012 to September 30, 2012, with the second fleet only operational beginning August 2012.  

Cost of services for the nine months ended September 30, 2013 increased $62.9 million, or 230.0%, to $90.2 million from $27.3 million for the period from February 21, 2012 (inception) to September 30, 2012. The increase was a direct result of increased hydraulic fracturing activity. 

Depreciation and amortization increased $5.6 million, or 155.7%, to $9.3 million for the nine months ended September 30, 2013 from $3.6 million for the period from February 21, 2012 (inception) to September 30, 2012. The increase is primarily due to depreciation expense for three fleets beginning May 2013 compared to only two fleets for the period from February 21, 2012 to September 30, 2012.

Selling, general and administrative expenses increased $3.5 million, or 119.9%, to $6.4 million during the nine months ended September 30, 2013 from $2.9 million during the period from February 21, 2012 (inception) to September 30, 2012. The increase was primarily due to professional fees and settlement of litigation.

Interest expense for the nine months ended September 30, 2013 increased $0.3 million, or 2.6%, to $12.5 million from $12.8 million for the period from February 21, 2012 (inception) to September 30, 2012. The increase is primarily due to increased debt balance with the issuance of $12.0 million in aggregate principal amount of Notes in April 2013.

The operating activities of our predecessor for the period from January 1, 2012 to February 20, 2012, primarily consisted of start-up activities. Consequently, no revenues were earned during this period. Selling, general and administrative expenses for the period from January 1, 2012 to February 20, 2012 were $0.4 million and were primarily for salaries and wages to officers and various professional fees.

Liquidity and Capital Resources

Our primary sources of liquidity were the proceeds we received in February 2012 from the Unit Offering, the Sponsor Equity Investment, the proceeds we received in April 2013 for the offering of April 2013 Additional Notes, the Revolving Credit Facility, the proceeds we received in October 2013 for the offering of October 2013 Additional Notes and the prefunded purchase price for the Series E Units, and cash flows generated from operations.  Our primary uses of capital have been the acquisition of our five hydraulic fracturing fleets, working capital requirements, and interest payments.  We continually monitor potential sources of capital, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements.  As of September 30, 2013, we had a balance of cash and cash equivalents totaling approximately $0.4 million.  

While we continue to be 100% leveraged as of September 30, 2013, we have no scheduled debt maturities on our 14.50% Senior Secured Notes due 2017 or Redeemable Series A Units during the remainder of 2013 or 2014. Additionally, as noted, subsequent to September 30, 2013 we have secured funding for our planned capital expenditures through the end of 2014 with no scheduled maturities within the next one to three years.

Our ability to meet our future liquidity requirements for satisfying our debt service obligations, funding operations and funding future capital expenditures will depend in large part on our future performance, some of which are subject to factors beyond our control. However, we believe that our cash on hand, our available borrowing capacity from our Revolving Credit Facility, and future cash flows from operating activities related to our five hydraulic fracturing fleets, are sufficient to fund ongoing operations and to meet our debt servicing obligations. We expect future cash flows from operating activities to improve as our original contract with Antero continues, as we gain new customers, and as we improve efficiencies regarding the number of stages completed, billed and collected.  We also expect future gross margin to improve as we gain synergies from operating multiple fleets in the same region.

---

 

Contractual Obligations

The following table summarizes our future contractual cash obligations as of September 30, 2013. Certain amounts included in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

 

Capital Requirements

The energy services business is capital intensive, requiring significant investment to expand, upgrade and maintain equipment.  Our capital requirements have consisted primarily of, and we anticipate will continue to be:

Additionally, we continually monitor new advances in hydraulic fracturing equipment and down-hole technology as well as technologies that may complement our business, and opportunities to acquire additional equipment to meet our customers’ needs.  Our ability to make any significant acquisition for cash would likely require us to obtain additional equity or debt financing, which may not be available to us on favorable terms or at all.

Financial Condition and Cash Flows

The net cash provided by or used in our operating, investing and financing activities is summarized below:

 

---

 

 

Cash Provided By (Used In) Operating Activities.  Net cash provided by operating activities was $11.6 million for the nine months ended September 30, 2013 compared to operating cash outflows of $13.9 million for the period February 21, 2012 (inception) through September 30, 2012. The increase was due primarily to improved operating activity, as a result of three fleets being operational by the end of the third quarter of 2013, as compared to only two fleets in service during the period from February 21, 2012 to September 30, 2012.

Cash Flows Used in Investing Activities.  Net cash used in investing activities for the nine months ended September 30, 2013 was $36.1 million and was mainly due to the acquisition of the third hydraulic fracturing fleet. Investing cash outflows for the period from February 21, 2012 (inception) through September 30, 2012 was $65.4 million, which mainly relates to the acquisition of the initial and second fleets.  

Cash Flows Provided by Financing Activities.  Net cash provided by financing activities for the nine months ended September 30, 2013 was $13.0 million and was due primarily to proceeds from the issuance of April 2013 Additional Notes and borrowings from the Revolving Credit Facility.

Net cash provided by financing activities was $85.2 million for the period February 21, 2012 (inception) through September 30, 2012 and was due primarily to the net proceeds received from the Unit Offering and the Sponsor Equity Investment, partially offset by the principal repayment as part of the Second Contract Repurchase.  

Off-Balance Sheet Arrangements

As of September 30, 2013, we had no off-balance sheet arrangements other than the operating leases discussed in Note 11 - Commitments and Contingencies in the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

Critical Accounting Policies and Estimates

The discussion of Critical Accounting Policies and Estimates is incorporated herein by reference from the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012. There have been no significant changes in the critical accounting policies and estimates since year-end.

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks including credit risk, interest rate risk and commodity price risk. The principal market risk to which we are exposed is the risk related to increases in the prices of fuel and raw materials consumed in performing our services. We do not engage in commodity price hedging activities. To a lesser extent, we are also exposed to risks related to interest rate fluctuations.

Credit Risk. We monitor our exposure to counterparties on service contracts and the collectability of our accounts receivable, primarily by reviewing our counterparties' credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty's creditworthiness.  Antero is our primary customer to date. Our current customers are, and our future customers will be, engaged in the oil and natural gas industry. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that our current customers and any future customers may be similarly affected by changes in economic and industry conditions.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to our long-term debt obligations. We may be exposed to changes in interest rates as a result of any future indebtedness. We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure. The Original Notes issued as part of the Unit Offering, the Additional Notes, and Fixed Rate LIBOR Loans on our Revolving Credit Facility, like all fixed rate securities, will be subject to interest rate risk and will likely fall in value if market interest rates increase.

Commodity Price Risk. Our fuel and material purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as fracturing sand, fracturing chemicals and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various tractors and other motorized equipment. The prices for fuel and the materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages.

 

---

 

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, management performed, with the participation of our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports 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. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on this evaluation, management concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the third quarter of 2013 that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

---

 

PART II - OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

None.

 

ITEM 1A. RISK FACTORS

We are subject to certain risks and hazards due to the nature of the business activities we conduct.  For a discussion of these risks, see “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 and June 30, 2013, and in our Registration Statement on Form S-4 (SEC Registration No. 333-189916).  Except as set forth below, there have been no material changes to the risk factors disclosed in the 2012 Annual Report on Form 10-K, in the Form 10-Q for the quarterly period ended March 31, 2013 and June 30, 2013, and in the Registration Statement on Form S-4 (SEC Registration No. 333-189916) during the quarter ended September 30, 2013.

 

We are deploying new and unproven technologies, which make evaluation of our business and prospects difficult, and our agreement with Antero may be terminated if we do not develop commercially successful products.

 

The services we are to provide under the Antero Contract are to be performed by a hydraulic fracturing fleet  (the “Clean Fleet”) to be powered by electricity generated from natural gas. The Clean Fleet will be constructed for us under the terms of a contract with Stewart & Stevenson. The technology involved in the construction of and the services to be performed from our Clean Fleet of hydraulic fracturing equipment is at an early stage of commercialization and has not been field proven. In order to successfully commercialize our Clean Fleet equipment, we will have to make significant investments, including investments in research and development and testing, to demonstrate its technical benefits and cost-effectiveness. Problems frequently encountered in connection with the commercialization of products using new and unproven technologies might limit our ability to develop and commercialize services provided by our Clean Fleet equipment. For example, our products may be found to be ineffective, unreliable or otherwise unsatisfactory to current and potential customers. We may experience unforeseen technical complications in the processes we use to develop, customize and receive orders for services performed by our Clean Fleet. These complications could materially delay or limit the use of Clean Fleet equipment that we attempt to commercialize, substantially increase the anticipated cost of our Clean Fleet or prevent us from implementing our processes at appropriate quality and scale levels, thereby causing our business to suffer.

 

In particular, the Antero Contract requires that we deliver services from Clean Fleet products by June 12, 2014, and our failure to do so would permit Antero to terminate the agreement or grant an extension to the commencement date of the agreement, at Antero’s discretion. In addition, we have an agreement in principle that we have yet to execute with Stewart & Stevenson for the construction and delivery of Clean Fleet fracturing pumps and related heavy equipment, and the resulting executed agreement is unlikely to provide for termination in the event that the Clean Fleet fracturing pumps and associated heavy equipment is not delivered by Stewart & Stevenson by June 12, 2014.

 

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITITES AND USE OF PROCEEDS

The Indenture governing the 14.50% Senior Secured Notes Due 2017 limits the payment of dividends by us.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

ITEM 5. OTHER INFORMATION

None.  

 

---

 

ITEM 6. EXHIBITS

 

* Filed herewith.

# Confidential treatment has been requested for portions of this exhibit. Omissions are designated with brackets containing asterisks. As part of our confidential treatment request, a complete version of this exhibit has been filed separately with the Securities and Exchange Commission.

 

---

 

 

SIGNATURES

 

U.S. Well Services, LLC, has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

 

---