USA Compression Partners, LP - Quarter Report: 2015 March (Form 10-Q)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

(MARK ONE)

 

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

 

FOR THE QUARTERLY PERIOD ENDED March 31, 2015

 

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

 

FOR THE TRANSITION PERIOD FROM               TO               .

 

Commission File No. 001-35779

 

USA Compression Partners, LP

(Exact name of registrant as specified in its charter)

 

 

(512) 473-2662

(Registrant’s telephone number, including area code)

 

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

 

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒  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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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

 

As of May 6, 2015, there were 32,124,107 common units and 14,048,588 subordinated units outstanding.

 

 

 

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TABLE OF CONTENTS

 

 

 

 

 

 

 

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PART I.  FINANCIAL INFORMATION

 

ITEM 1.Financial Statements

 

USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(in thousands, except for unit amounts)

(unaudited)

 

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(in thousands, except unit amounts)

(unaudited)

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Condensed Consolidated Statement of Changes in Partners’ Capital

Three Months Ended March 31, 2015

(in thousands)

(unaudited)

 

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

 

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

(1)  Organization and Summary of Significant Accounting Policies

 

(a)  Organization

 

USA Compression Partners, LP (the “Partnership”) is a publicly traded Delaware limited partnership formed to own and operate the business conducted by its subsidiaries. The common units representing limited partner interests in the Partnership (“common units”) are listed on the New York Stock Exchange (“NYSE”) under the symbol “USAC.” USA Compression GP, LLC, the general partner of the Partnership (the “General Partner”), is owned by USA Compression Holdings, LLC (“USA Compression Holdings”). Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of the Partnership and its consolidated subsidiaries and references to the “General Partner” refer to the General Partner. References to “Riverstone” refer to Riverstone/Carlyle Global Energy and Power Fund IV, L.P., and affiliated entities, including Riverstone Holdings LLC.  References to “Argonaut” and related parties refer to Argonaut Private Equity, L.L.C. and certain related parties.

 

The Partnership, through its wholly-owned subsidiaries (the “Operating Subsidiaries”), primarily provides natural gas compression services under term contracts with customers in the crude oil and natural gas industry, using natural gas compression packages that it designs, engineers, owns, operates and maintains. The condensed consolidated financial statements include the accounts of the Partnership and the Operating Subsidiaries and all intercompany balances and transactions have been eliminated in consolidation.

 

Our ownership is as follows:

 

 

Partnership net income (loss) is allocated to the partners, both general and limited, in proportion to their respective interest in the Partnership.

 

(b)  Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements of the Partnership have been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2014  (the “2014 Annual Report”). In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position as of March 31, 2015 and December 31, 2014, and the results of operations and statements of cash flows for the three months ended March 31, 2015 and 2014 and changes in partners’ capital for the three months ended March 31, 2015 in accordance with U.S. generally accepted accounting principles (“GAAP”). Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. All intercompany balances and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Therefore, these consolidated financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements for the year ended December 31, 2014 contained in our 2014 Annual Report filed on February 19, 2015.  

 

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(c)  Use of Estimates

 

The unaudited condensed consolidated financial statements of the Partnership have been prepared in conformity with GAAP, which includes the use of estimates and assumptions by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the unaudited condensed consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could differ from these estimates.

 

(d)  Identifiable Intangible Assets

 

As of March 31, 2015, identifiable intangible assets, net consisted of the following (in thousands):

 

 

Identifiable intangible assets are amortized on a straight-line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from 4 to 30 years.  Accumulated amortization of intangible assets was $13.7 million and $12.8 million as of March 31, 2015 and December 31, 2014, respectively.

 

The Partnership assesses identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Partnership did not record any impairment of identifiable intangible assets for the three months ended March 31, 2015 or 2014.

 

(e)  Property and Equipment

 

Property and equipment are carried at cost. Overhauls and major improvements that increase the value or extend the life of compressor equipment are capitalized and depreciated over 3 to 5 years. Ordinary maintenance and repairs are charged to cost of operations, exclusive of depreciation and amortization. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets as follows:

 

 

See more information on property and equipment in Note 3 to our unaudited condensed consolidated financial statements.

 

(f)   Impairments of Long-Lived Assets

 

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. An asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable or will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows associated with the operating fleet, an impairment loss equal to the amount of the carrying value exceeding the fair value of the asset is recognized. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows or the expected net sale proceeds compared to the other similarly configured fleet units the Partnership recently sold or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment the Partnership plans to use.    The Partnership did not record any impairment of long-lived assets in the three months ended March 31, 2015 or 2014. 

 

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(g)   Fair Value Measurements

 

Accounting standards on fair value measurements establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring financial and non-financial assets and liabilities that require or permit fair value measurements. Among the required disclosures is the fair value hierarchy of inputs the Partnership uses to value an asset or a liability. The three levels of the fair value hierarchy are described as follows:

 

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Partnership has the ability to access at the measurement date.

 

Level 2 inputs are those 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 inputs for the asset or liability.

 

As of March 31, 2015 and 2014, the Partnership’s financial instruments consisted primarily of cash and cash equivalents, trade accounts receivable, trade accounts payable and long-term debt. The book values of cash and cash equivalents, trade accounts receivable and trade accounts payable are representative of fair value due to their short-term maturity. The carrying amount of long-term debt approximates fair value due to the floating interest rates associated with the debt.

 

Phantom unit awards granted to employees under the USA Compression Partners, LP 2013 Long-Term Incentive Plan (the “LTIP”) are accounted for as a liability, and such liability is re-measured on a quarterly basis.  The liability is based on the publicly quoted price of the Partnership’s common units, which is considered a Level 1 input.

 

(h)   Operating Segment

 

The Partnership operates in a single business segment, the compression services business.

 

(2)  Trade Accounts Receivable

 

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts of $0.5 million and $0.4 million at March 31, 2015 and December 31, 2014, respectively, is the Partnership’s best estimate of the amount of probable credit losses included in the Partnership’s existing accounts receivable. The Partnership determines the allowance based upon historical write-off experience and the specific circumstances. The Partnership does not have any off-balance-sheet credit exposure related to its customers.

 

(3)  Property and Equipment

 

Property and equipment consisted of the following at March 31, 2015 and December 31, 2014 (in thousands):

 

 

We recognized $19.8 million and $15.3 million of depreciation expense on property and equipment for three months ended March 31, 2015 and 2014, respectively.

 

As of March 31, 2015 and December 31, 2014, there was $21.0 million and $32.4 million, respectively, of property and equipment purchases in accounts payable and accrued liabilities.

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During the three months ended March 31, 2015, non-cash transfers of inventory to and from property and equipment totaled approximately $1.0 million.  These transfers have been treated as non-cash inventory activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

 

During the three months ended March 31, 2015, insurance recoveries of $0.2 million were received on previously impaired compression equipment and are reported within the Loss (gain) on sale of assets line in the Unaudited Condensed Consolidated Statement of Operations. 

 

(4) Accrued Liabilities

 

Other current liabilities included accrued salaries and benefits and accrued property taxes.  The Partnership recognized $4.1 million and $5.5 million of accrued salaries and benefits as of March 31, 2015 and December 31, 2014, respectively.  The Partnership recognized $3.0 million and $4.8 million of accrued property taxes as of March 31, 2015 and December 31, 2014, respectively.

 

(5)  Long-Term Debt

 

The long-term debt of the Partnership, of which there is no current portion, consisted of the following as of March 31, 2015 and December 31, 2014 (in thousands):

 

 

Description of Revolving Credit Facility

 

On January 6, 2015, the Partnership entered into the second amendment to the Fifth Amended and Restated Credit Agreement (the “revolving credit facility”), whereby, the aggregate commitment under the revolving credit facility increased from $850.0 million to $1.1 billion (subject to availability under our borrowing base), with a further potential increase of $200 million, and the maturity date of the revolving credit facility was extended to January 6, 2020.  In addition, this amendment provided additional flexibility under the financial covenants of the revolving credit facility.  The Partnership paid various loan fees and incurred costs in respect of the revolving credit facility in the amount of $3.4 million during January 2015.

 

The revolving credit facility permits the Partnership to make distributions of available cash to unitholders so long as (a) no default under the facility has occurred, is continuing or would result from the distribution, (b) immediately prior to and after giving effect to such distribution, the Partnership is in compliance with the facility’s financial covenants and (c) immediately after giving effect to such distribution, the Partnership has availability under the revolving credit facility of at least $20 million. In addition, the revolving credit facility contains various covenants that may limit, among other things, the Partnership’s ability to (subject to certain exceptions): 

 

 

 

 

 

 

 

 

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The revolving credit facility contains various financial covenants, including covenants requiring the Partnership to maintain:

 

 

 

If a default exists under the revolving credit facility, the lenders will be able to accelerate the maturity on the amount then outstanding and exercise other rights and remedies.

 

As of March 31, 2015 the Partnership was in compliance with all of its covenants under the revolving credit facility.

 

As of March 31, 2015,  the Partnership had outstanding borrowings of $711.7 million and $176.3 million of available capacity considering the financial covenants.   The Partnership’s borrowing base availability was $388.3 million as of March 31, 2015.  Compression units that are eligible to be considered in calculating the borrowing base consist of equipment packages that are leased, rented or under service contracts to customers and carried in the financial statements as fixed assets.  The Partnership’s interest rate in effect for all borrowings under its revolving credit facility as of March 31, 2015 and December 31, 2014 was 2.19% and 2.16%, respectively, with an average interest rate of 2.19% and 2.16% during the three months ended March 31, 2015 and 2014, respectively.  There were no letters of credit issued as of March 31, 2015 and 2014.

 

In the event that any of the Operating Subsidiaries guarantees any series of the debt securities as described in the Partnership’s registration statement filed on Form S-3 (Reg. No. 333-193724), such guarantees will be full and unconditional and made on a joint and several basis for the benefit of each holder and the Trustee. However, such guarantees are subject to release, subject to certain limitations, as follows (i) upon the sale, exchange or transfer, whether by way of a merger or otherwise, to any Person that is not an Affiliate of the Partnership, of all the Partnership’s direct or indirect limited partnership or other equity interest in such Subsidiary Guarantor; or (ii) upon the Partnership’s or USA Compression Finance Corp.’s (together, the “Issuers”) delivery of a written notice to the Trustee of the release or discharge of all guarantees by such Subsidiary Guarantor of any Debt of the Issuers other than obligations arising under this Indenture and any Debt Securities issued hereunder, except a discharge or release by or as a result of payment under such guarantees.   Capitalized terms in this paragraph are defined in the Form of Indenture filed as exhibit 4.1 to such registration statement.

 

The revolving credit facility matures in January 2020 and the Partnership expects to maintain this facility for the term. The facility is a “revolving credit facility” that includes a “springing” lock box arrangement, whereby remittances from customers are forwarded to a bank account controlled by the Partnership, and the Partnership is not required to use such remittances to reduce borrowings under the facility, unless there is a default or excess availability under the facility is reduced below $20 million. As the remittances do not automatically reduce the debt outstanding absent the occurrence of a default or a reduction in excess availability below $20 million, the debt has been classified as long-term as of March 31, 2015 and December 31, 2014. 

 

(6)  Partners’ Capital

 

As of May 6, 2015, USA Compression Holdings held 5,541,573 common units and 14,048,588 subordinated units and controlled USA Compression GP, LLC, which held an approximate 1.7% general partner interest (the “General Partner’s Interest”) and the incentive distribution rights (“IDRs”). See the Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital.

 

Subordinated Units

 

All of the subordinated units are held by USA Compression Holdings. Our limited partnership agreement (the “Partnership Agreement”) provides that, during the subordination period, the common units have the right to receive distributions of Available Cash from Operating Surplus (each as defined in the Partnership Agreement) each quarter in

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an amount equal to $0.425 per common unit (the “Minimum Quarterly Distribution”), plus any arrearages in the payment of the Minimum Quarterly Distribution from Operating Surplus on the common units from prior quarters, before any distributions of Available Cash from Operating Surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from Operating Surplus until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash from Operating Surplus to be distributed on the common units. The subordination period will end on the first business day after the Partnership has earned and paid at least (i) $1.70 (the Minimum Quarterly Distribution on an annualized basis) on each outstanding unit and the corresponding distribution on the General Partner’s Interest, for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015 or (ii) $2.55  (150.0% of the annualized Minimum Quarterly Distribution) on each outstanding unit and the corresponding distributions on the General Partner’s Interest and the related distribution on the IDRs for the four-quarter period immediately preceding that date. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

 

Cash Distributions

 

The Partnership has declared quarterly distributions per unit to limited partner unitholders of record, including holders of common and subordinated units, and distributions paid to the General Partner, including the General Partner’s Interest and IDRs, as follows (in millions, except distribution per unit): 

 

 

The Partnership  Agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its Available Cash (as defined in the Partnership Agreement) to the partners of record on the applicable record date. Pursuant to the Partnership’s registration statement on Form S-1 (Reg. No. 333-202492), the Partnership may issue up to an additional 2,000,000 of its common units in connection with the Partnership’s Distribution Reinvestment Plan (the “DRIP”). The DRIP provides the Partnership’s common and subordinated unitholders a means by which they can increase the number of common units they own by reinvesting their quarterly cash distributions, which they would otherwise receive in cash, into the purchase of additional common units.  Such distributions, which are treated as non-cash transactions in the accompanying Unaudited Condensed Statements of Cash Flows, totaled $13.6 million and $12.6 million for the three months ended March 31, 2015 and 2014, respectively.

 

On April 23, 2015, the Partnership announced a cash distribution of $0.515 per unit on its common and subordinated units. The distribution will be paid on May 15, 2015 to unitholders of record as of the close of business on May 5, 2015. USA Compression Holdings, the owner of approximately 42% of the Partnership’s outstanding limited partner interests, and Argonaut and certain of its related parties, the owners of approximately 16% of the Partnership’s outstanding limited partner interests, have elected to reinvest all of this distribution with respect to their units pursuant to the DRIP. 

 

As of March 31, 2015, a total of 3,882,146 common units had been issued pursuant to the DRIP under the Partnership’s previous registration statements filed with the SEC.  

 

Earnings Per Common and Subordinated Unit

 

The computations of earnings per common unit and subordinated unit are based on the weighted average number of common units and subordinated units, respectively, outstanding during the applicable period. The Partnership’s subordinated units and the General Partner’s Interest (including its IDRs) meet the definition of participating securities as defined by the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 260 Earnings Per Share; therefore, the Partnership is required to use the two-class method in the computation of earnings per unit. Basic earnings per common and subordinated unit are determined by dividing net income allocated to

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the common and subordinated units, respectively, after deducting the amount allocated to the General Partner (including distributions to the General Partner on its IDRs), by the weighted average number of outstanding common and subordinated units, respectively, during the period. Net income is allocated to the common units, subordinated units and the General Partner based on their respective shares of the distributed and undistributed earnings for the period. To the extent cash distributions exceed net income for the period, the excess distributions are allocated to all participating units outstanding based on their respective ownership percentages. Diluted earnings per unit are computed using the treasury stock method, which considers the potential issuance of limited partner units associated with the LTIP.  Unvested phantom units are not included in basic earnings per unit, as they are not considered to be participating securities, but are included in the calculation of diluted earnings per unit.

 

Incentive Distribution Rights

 

The General Partner holds all of the IDRs. The following table illustrates the percentage allocations of Available Cash from Operating Surplus between the unitholders and the General Partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the General Partner and the unitholders in any Available Cash from Operating Surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit.” The percentage interests shown for our unitholders and the General Partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for the General Partner include its General Partner’s Interest, and assume the General Partner has contributed any additional capital necessary to maintain its General Partner’s Interest, the General Partner has not transferred the IDRs and there are no arrearages on common units.

 

 

 

 

(7)  Transactions with Related Parties

 

William Shea, Jr., who has served as a director of USA Compression GP, LLC since June 2011, served as Chief Executive Officer of the general partner of PVR Partners, L.P. (“PVR”) from March 2010 to March 2014. In March 2014, PVR merged with and into Regency Energy Partners LP, a Delaware limited partnership (“Regency”), with Regency as the surviving limited partnership (the “Merger”). As a result of the Merger, the separate limited partnership existence of PVR ceased, and Regency continued its existence as the surviving limited partnership. For the three months ended March 31, 2014,  the Partnership recognized approximately $0.6 million in revenue on compression services from subsidiaries of PVR. 

 

John Chandler, who has served as a director of USA Compression GP, LLC since October 2013, has served as a director of CONE Midstream GP, LLC (“CONE”) since October 2014. During the three months ended March 31, 2015, the Partnership recognized $1.8 million in revenue on compression services and $1.3 million in accounts receivable from CONE on the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2015.

 

(8)  Commitments and Contingencies

 

(a)  Major Customers

 

The Partnership had revenue from one customer representing 10.6% and 12.4% of total revenue for the three months ended March 31, 2015 and 2014, respectively.

 

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(b)  Litigation

 

From time to time, the Partnership and its subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on the Partnership’s consolidated financial position, results of operations or cash flows.

 

(c)  Equipment Purchase Commitments

 

The Partnership’s future capital commitments are comprised of binding commitments under purchase orders for new compression units ordered but not received. The commitments as of March 31, 2015 were $124.3 million, all of which are expected to be settled within the next twelve months.

 

(9)  Recent Accounting Pronouncement

 

In April 2015, the FASB issued an Accounting Standards Update (“ASU”) that clarified when fees paid in a cloud computing arrangement pertain to the acquisition of a software license and/or services.  When a cloud computing arrangement includes a license of software, the fee attributable to the software license portion of the arrangement will be capitalized when the criteria for capitalization of internal-use software are met.  When a cloud computing arrangement does not include a license of software, the arrangement will be treated as a service contract and the cost will be expensed as the services are received.  The ASU is effective for annual and interim periods in fiscal years beginning after December 15, 2015. Early adoption is permitted and entities may elect to adopt the ASU either prospectively for all arrangements entered into or materially modified after the effective date, or retrospectively. The Partnership is currently evaluating the impact, if any, of this standard on the consolidated financial statements. 

 

Also in April 2015, the FASB issued an ASU that simplified the presentation of debt issuance costs.  The standard states:

 

 

The ASU is effective for annual and interim periods in fiscal years beginning after December 15, 2015. Early adoption is permitted. The Partnership is currently evaluating the impact, if any, of this standard on the consolidated financial statements.

 

 

 

 

 

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ITEM 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-looking statements, including, without limitation, statements regarding our plans, strategies, prospects and expectations concerning our business, results of operations and financial condition. You can identify many of these statements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “continue” or similar words or the negative thereof.

 

Known material factors that could cause our actual results to differ from those in these forward-looking statements are described in Part II, Item 1A (“Risk Factors”) and elsewhere in this report. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:

 

 

 

 

 

 

 

 

 

 

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing cautionary statements.

 

Overview

 

We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville and Fayetteville shales. The demand for our services is driven by the domestic production of natural gas and crude oil; as such, we have focused our activities in areas of attractive production growth, which are generally found in these shale and unconventional resource plays.  According to recent studies promulgated by the Energy Information Agency (“EIA”), the production and transportation volumes in these plays are expected to increase over time due to the comparably attractive economic returns versus returns achieved in many conventional basins. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins. We believe the flexibility of our compression units positions us well to meet these changing operating conditions. While our business focuses largely on compression services serving infrastructure installations, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays, we also provide compression services in more mature conventional basins, including crude oil wells targeted by horizontal drilling techniques. The recent advent of horizontal drilling has allowed producers to produce incremental volumes of crude oil on economic terms that tend to remain attractive even in periods of low commodity prices.

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General Trends and Outlook

 

A significant amount of our assets are utilized in infrastructure applications, primarily in centralized natural gas gathering systems and processing facilities. Given the project nature of these applications and long-term investment horizon of our customers, we have generally experienced stability in rates since 2011 and expect to see continued stability over the medium-to-long term.  A small portion of our fleet is used in connection with crude oil production using horizontal drilling techniques.  The recent advent of horizontal drilling has allowed producers to produce incremental volumes of crude oil on economic terms that tend to remain attractive even in periods of low commodity prices.  In recent months, commodity prices have declined significantly.  As a result, we have experienced and expect to continue to experience some pressure on service rates until such time as commodity prices return to higher levels. We are closely monitoring developments in our customer base, but believe that there will continue to be demand for our services given the necessity of compression services in allowing for the transportation and processing of natural gas as well as the production of crude oil. We intend to prudently grow the number of compression units in our fleet in order to be positioned to take advantage of attractive market opportunities, primarily through the purchase of larger horsepower units that tend to generate higher margins and command longer contract terms.

 

Our ability to increase our revenues is dependent in large part on our ability to add new revenue generating compression units to our fleet while maintaining our utilization and contract rates. For the year ending December 31, 2015, we expect to purchase approximately 240,000 horsepower of new compression unit equipment, all of which has already been ordered. Revenue generating horsepower increased by 26.2% from March 31, 2014 to March 31, 2015.  As of March 31, 2015, we continued to have a utilization rate in excess of 90%. Average revenue generating horsepower increased by 26.6% from the three months ended March 31, 2014 to the three months ended March 31, 2015.  

 

The EIA has projected that continued natural gas production growth will be supported in the coming years by increases in drilling efficiencies as well as a backlog of drilled but uncompleted wells in major supply areas, such as the Marcellus Shale. Additionally, domestic exports, both to Mexico and through the start-up of various liquefied natural gas (“LNG”) projects in late 2015 and beyond, are expected to increase. The EIA projects that over 70% of the increased natural gas production through 2040 will come from shale resources.  

 

Due to the more pronounced volatility in the price of crude oil, we expect to experience a general slowdown in the demand for our compression services for gas lift applications, and as a result some customers have sought service rate relief until commodity prices recover. However, we remain confident that through prudent management of our fleet we will be able to maintain strong utilization throughout 2015.

 

Historically, crude oil and natural gas prices in the U.S. have been volatile. Global crude oil prices have fallen recently compared to levels seen over the past 18 months. West Texas Intermediate crude oil spot prices as of March 31, 2015 were 53% lower than prices at March 31, 2014.  During periods of lower crude oil and natural gas prices, crude oil and natural gas production growth could moderate or decline in the U.S. A 1% decrease in average revenue generating horsepower of our active fleet during the quarter ended March 31, 2015 would have resulted in a decrease of approximately $2.6 million and $1.9 million in our revenue and gross operating margin, respectively. Gross operating margin is a non-GAAP financial measure. For a reconciliation of gross operating margin to net income, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures” below.

 

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Operating Highlights

 

The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented.

 

 

 

 

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The 28.9% increase in fleet horsepower as of March 31, 2015 over the fleet horsepower as of March 31, 2014 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers for our compression services.  The 26.2% increase in revenue generating horsepower was primarily due to organic growth in our large horsepower fleet.  

 

The following table summarizes other financial data for the periods presented (dollars in thousands):

 

 

 

 

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Adjusted EBITDA.   The increase in Adjusted EBITDA during the three months ended March 31, 2015 was primarily attributable to a $13.3 million increase in Gross operating margin.  The increase in Gross operating margin is primarily attributed to the 26.2% increase in revenue generating horsepower as a result of increased demand for our compression services.

 

Adjusted DCF.  The increase in Adjusted DCF during the three months ended March 31, 2015 was primarily attributable to a $13.3 million increase in Gross operating margin.  The increase in Gross operating margin is primarily attributed to the 26.2% increase in revenue generating horsepower as a result of increased demand for our compression services along with lower maintenance capital expenditures during the comparable period, offset by higher cash interest expense, net.  

 

 

 

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Financial Results of Operations

 

Three months ended March 31, 2015 compared to the three months ended March 31, 2014

 

The following table summarizes our results of operations for the periods presented (in thousands):

 

 

 

Contract operations revenue.  During the three months ended March 31, 2015, we saw an increase in overall natural gas production in the U.S. and experienced an increase in demand for our compression services.  Because the demand for our services is driven primarily by production of natural gas, we focus our activities in areas of attractive growth, which are generally found in certain shale and unconventional resource plays.  The 26.6% increase in average revenue generating horsepower was primarily due to organic growth.  Average revenue per revenue generating horsepower per month increased from $15.30 for the three months ended March 31, 2014 to $15.85 for the three months ended March 31, 2015, an increase of 3.6%, attributable, in part, to growth in the small horsepower fleet, which earns higher revenue per horsepower, in addition to improved pricing in the large horsepower fleet.  

 

Parts and service revenue.  Parts and service revenue was comprised of pass-through revenue and retail service revenue.  Pass-through revenue was earned primarily on freight and crane charges that are directly reimbursable by our customers, for which we earn no margin.  Retail service revenue consisted of maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities.  We offered these services as a courtesy to our customers and the demand fluctuates from period to period based on the varying needs of our customers.

 

Cost of operations, exclusive of depreciation and amortization. The increase in cost of operations is primarily attributable to the increase in our fleet size. Certain cost increases consisted of (1) a $0.8 million increase in indirect expenses, the majority of which is higher property and other taxes, (2) a $0.6 million increase in direct expenses such as parts and fluids for the fleet and (3) a  $0.5 million increase in labor expenses. These fluctuations are primarily attributable to the increase in our fleet size due to organic growth.

 

Gross operating margin. The $13.3 million increase in gross operating margin was due to higher revenues partially offset by higher operating expenses during the three months ended March 31, 2015. The 5.7% increase in gross operating margin percentage from 64.7% for the three months ended March 31, 2014 to 70.4% for the three months ended March

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31, 2015 was attributable to (1) certain cost savings initiatives, (2) timing of certain maintenance activities and (3) lower fuel costs.

 

Selling, general and administrative expense.  The increase in selling, general and administrative expense was primarily related to a $1.4 million rise in salaries and benefits related to an increase in employee headcount. The selling, general and administrative employee headcount was 110 as of March 31, 2015, a 14.6% increase from March 31, 2014. The selling, general and administrative employee headcount increased to support the continued growth of the business.

 

Depreciation and amortization expense.  The $4.5 million increase in depreciation expense was related to an increase in gross property and equipment balances during the three months ended March 31, 2015 compared to the three months ended March 31, 2014.  There is no variance in amortization expense between the same periods, as intangible assets are amortized on a straight-line basis and there has been no change in gross identifiable intangible assets between the periods.

 

(Gain) loss on sale of assets.  The $0.2 million gain on sale of assets during the three months ended March 31, 2015 was primarily attributable to a cash insurance recovery on previously impaired compression equipment. 

 

Interest expense, net.  The increase in interest expense was primarily attributable to the impact of an approximate $190.4 million increase in average outstanding borrowings, offset by a $0.1 million decrease in amortization of deferred loan costs and $0.4 million of interest income related to a capital lease which commenced during the second quarter of 2014. Average borrowings outstanding under our revolving credit facility were $658.9 million for the three months ended March 31, 2015 compared to $468.5 million for the three months ended March 31, 2014.  Our revolving credit facility had an interest rate of 2.19% and 2.16% at March 31, 2015 and 2014, respectively, and an average interest rate of 2.19% and 2.16%  for the three months ended March 31, 2015 and 2014, respectively.

 

Income tax expense.  Income tax expense is associated with the Texas franchise tax.

 

Liquidity and Capital Resources

 

Cash Flows

 

The following table summarizes our sources and uses of cash for the three months ended March 31, 2015 and 2014 as of the end of the periods presented (in thousands):

 

 

 

Net cash provided by operating activities.  The increase in net cash provided by operating activities for the three months ended March 31, 2015 relates primarily to a $13.3 million increase in gross operating margin offset by a $5.0 million increase in inventory purchases, a $3.1 million increase in property tax payments and a $2.2 million increase in bonus payments.

 

Net cash used in investing activities. Net cash used in investing activities for the three months ended March 31, 2015 and 2014 related primarily to purchases of new compression units and related equipment in response to increasing demand for our services.

 

Net cash provided by financing activities.  During the three months ended March 31, 2015, we borrowed, on a net basis, $116.8 million primarily to support our purchases of new compression units, as described above. During January 2015, we paid various loan fees and incurred costs in respect of our revolving credit facility in the amount of $3.4 million.    During the first quarter of 2015, we also made cash distributions to our unitholders of $10.2 million.  During the three months ended March 31, 2014, we borrowed, on a net basis, $82.6 million primarily to support purchases of new compression units and make cash distributions to our unitholders of $6.2 million. 

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Capital Expenditures

 

The compression business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily of, the following:

 

 

 

We classify capital expenditures as maintenance or expansion on an individual asset basis. We expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the three months ended March 31, 2015 and 2014 were $4.1 million and $5.3 million, respectively. We currently plan to spend approximately $20 million in maintenance capital expenditures during 2015.

 

Given our growth objective and anticipated demand from our customers primarily as a result of the increasing natural gas activity described above under the heading “—General Trends and Outlook,” we anticipate that we will continue to make significant expansion capital expenditures. Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently expect to spend between $250 million and $270 million in expansion capital expenditures during 2015. Our expansion capital expenditures for the three months ended March 31, 2015 and 2014 were $114.6 million and $81.5 million, respectively.

 

Description of Revolving Credit Facility

 

As of March 31, 2015,  we were in compliance with all of our debt covenants related to our revolving credit facility and had outstanding borrowings of $711.7 million. We had $176.3 million of available capacity at March 31, 2015 considering our financial covenants.  Our borrowing base availability was $388.3 million as of March 31, 2015.  Financial covenants permitted a maximum leverage ratio of 5.95 to 1.0 as of March 31, 2015.  As of May 6, 2015, we had outstanding borrowings of $735.7 million.

 

For a detailed description of our revolving credit facility including the covenants and restrictions contained therein, please see Note 5 to our unaudited condensed consolidated financial statements.

 

Distribution Reinvestment Plan

 

On March 4, 2015, we filed a registration statement on Form S-1 (Reg. No. 333-202492) with the SEC to register the issuance of up to an additional 2,000,000 of our common units in connection with the DRIP, which was declared effective on March 18, 2015. The DRIP provides our common and subordinated unitholders a means by which they can increase the number of common units they own by reinvesting their quarterly cash distributions, which they would otherwise receive in cash, into the purchase of additional common units.  As of May 6, 2015, a total of 3,882,146 common units had been issued pursuant to our DRIP under our previous registration statements we have filed with the SEC.

 

Non-GAAP Financial Measures

 

Gross Operating Margin

 

Gross operating margin is a non-GAAP financial measure. We define gross operating margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that gross operating margin is useful as a

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supplemental measure of our operating profitability. Gross operating margin is impacted primarily by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume and per unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units and property tax rates on compression units.  Gross operating margin should not be considered an alternative to, or more meaningful than, operating income or any other measure of financial performance presented in accordance with GAAP. Moreover, gross operating margin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of gross operating margin as a measure of our performance, we believe that it is important to consider operating income determined under GAAP, as well as gross operating margin, to evaluate our operating profitability.

 

The following table reconciles gross operating margin to operating income, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands):

 

 

 

Adjusted EBITDA

 

We define EBITDA as net income before net interest expense, depreciation and amortization expense, and income taxes. We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, interest income, unit based compensation expense, restructuring charges, management fees, (gain) loss on sale of assets, and transaction expenses. We view Adjusted EBITDA as one of our primary management tools, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year and to budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

 

 

 

 

 

We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.

 

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Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

 

Because we use capital assets, depreciation, impairment and the interest cost of acquiring compression equipment are also necessary elements of our costs. Expense related to unit-based compensation expense related to equity awards to employees is also a  necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management’s decision making processes.

 

The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):

 

 

 

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Adjusted Distributable Cash Flow

 

We define distributable cash flow as net income plus non-cash interest expense, depreciation and amortization expense, unit based compensation expense and impairment of compression equipment, less maintenance capital expenditures. We define Adjusted DCF as distributable cash flow plus certain transaction fees and (gain) loss on sale of equipment. We believe distributable cash flow and Adjusted DCF are important measures of operating performance

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because they allow management, investors and others to compare basic cash flows we generate (prior to the establishment of any retained cash reserves by our general partner and the effect of the DRIP) to the cash distributions we expect to pay our unitholders. Using distributable cash flow and Adjusted DCF, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

 

Distributable cash flow and Adjusted DCF should not be considered as an alternative to, or more meaningful than, net income,  operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity.  Moreover, our distributable cash flow and Adjusted DCF as presented may not be comparable to similarly titled measures of other companies.

 

Because we use capital assets, depreciation and impairment of compression equipment, (gain) loss on sale of assets, and maintenance capital expenditures are necessary elements of our costs. Expense related to unit-based compensation expense related to equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted DCF, to evaluate our financial performance and our liquidity. Our Adjusted DCF excludes some, but not all, items that affect net income and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted DCF as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management’s decision making processes.

 

The following table reconciles Adjusted DCF to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):

 

 

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Coverage Ratios 

 

We define Adjusted DCF Coverage Ratio as Adjusted DCF less cash distributions to the General Partner and IDRs divided by distributions declared to limited partner unitholders for the period. We define Cash Coverage Ratio as Adjusted DCF less cash distributions to our general partner and IDRs divided by cash distributions paid to limited partner unitholders, after consideration of the DRIP.  We believe Adjusted DCF coverage ratio and Cash coverage ratio are important measures of operating performance because they allow management, investors and others to gauge our ability to pay cash distributions to limited partner unitholders using the cash flows we generate.  

 

Our Adjusted DCF coverage ratio and Cash coverage ratio as presented may not be comparable to similarly titled measures of other companies.

 

The following table summarizes certain coverage ratios for the periods presented. 

 

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Off-Balance Sheet Arrangements

 

We have no off-balance sheet financing activities.

 

Recent Accounting Pronouncement

 

We qualify as an emerging growth company under Section 109 of the Jumpstart Our Business Startups, (“JOBS”) Act. An emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we have chosen to “opt out” of such extended transition period, and as a result, are compliant with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 108 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

 

For more discussion on specific recent accounting pronouncements affecting us, please see Note 9 to our condensed consolidated financial statements.

 

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ITEM 3.Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk

 

Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or crude oil in connection with our services and, accordingly, have no direct exposure to fluctuating commodity prices. However, the demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Lower natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, which could result in reduced demand for our compression services. We do not intend to hedge our indirect exposure to fluctuating commodity prices.

 

Interest Rate Risk

 

We are exposed to market risk due to variable interest rates under our financing arrangements.

 

As of March 31, 2015 we had approximately $711.7 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 2.2%. A 1% increase or decrease in the effective interest rate on our variable-rate outstanding debt at March 31, 2015 would have resulted in an annual increase or decrease in our interest expense of approximately $7.1 million.

 

For further information regarding our exposure to interest rate fluctuations on our debt obligations see Note 5 to our unaudited condensed consolidated financial statements.  Although we do not currently hedge our variable rate debt, we may, in the future, hedge all or a portion of such debt.

 

Credit Risk

 

Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the amount it owes us, it could have a material adverse effect on our business, financial condition, results of operations or cash flows.

 

ITEM 4.Controls and Procedures

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (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 report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.  Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2015 at the reasonable assurance level.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.