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 June 30, 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 August 3, 2015, there were 32,768,844 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

Unaudited Condensed Consolidated Balance Sheets

(Dollars in thousands, except for unit amounts)

 

 

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(Dollars in thousands, except unit amounts)

 

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital

Six Months Ended June 30, 2015

(Dollars and units in thousands)

 

 

 

 

See accompanying notes to unaudited condensed consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(Dollars in thousands)

 

 

 

 

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 wholly owned, consolidated subsidiaries (the “Operating Subsidiaries”).  References to “Argonaut” and related parties refer to Argonaut Private Equity, L.L.C. and certain related parties.

 

The Partnership, through its 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 unaudited 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.

 

The Partnership’s 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 June 30, 2015 and December 31, 2014, and the results of operations for the three months and six months ended June 30, 2015 and 2014, changes in partners’ capital for the six months ended June 30, 2015 and the statements of cash flows for the six months ended June 30, 2015 and 2014 in accordance with U.S. generally accepted accounting principles (“GAAP”). Operating results for the three months and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. 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.

 

(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,

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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 June 30, 2015, identifiable intangible assets, net consisted of the following (in thousands):

 

 

Identifiable intangible assets are amortized using the straight-line method 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 $14.6 million and $12.8 million as of June 30, 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 and six months ended June 30, 2015 or the three and six months ended June 30, 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, 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.   

 

Refer to Note 3 for more detailed information about impairment charges during the three and six months ended June 30, 2015.

 

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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 June 30, 2015 and December 31, 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. As of June 30, 2015 and December 31, 2014, unit-based compensation liability was $1.2 million and $1.3 million, respectively.

 

(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 $0.9 million and $0.4 million at June 30, 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 specific customer 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 June 30, 2015 and December 31, 2014 (in thousands):

 

 

We recognized $20.6 million and $16.1 million of depreciation expense on property and equipment for the three months ended June 30, 2015 and 2014, respectively.  We recognized $40.4 million and $31.5 million of depreciation expense on property and equipment for the six months ended June 30, 2015 and 2014, respectively.

 

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As of June 30, 2015 and December 31, 2014, there was $18.6 million and $32.4 million, respectively, of property and equipment purchases in accounts payable and accrued liabilities.

 

During the six months ended June 30, 2015, non-cash transfers of inventory to and from property and equipment totaled approximately $0.7 million.  These transfers have been treated as non-cash inventory activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

 

During the six months ended June 30, 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. 

 

During the quarter ended June 30, 2015, the Partnership evaluated the future deployment of its idle fleet under current market conditions and determined to retire and either sell or re-utilize the key components of 166 compressor units, or approximately 58,000 horsepower, that were previously used to provide services in the Partnership’s business.  This compression equipment was written down to its respective estimated salvage value, measured using quoted market prices, or the estimated component value of the equipment the Partnership plans to use.  As a result of the Partnership’s decision to retire, sell or re-utilize these compressor units, management performed an impairment review and based on that review, recorded  a $26.8 million impairment of long-lived assets in the three and six months ended June 30, 2015. The Partnership did not record impairment of long-lived assets in the three and six months ended June 30, 2014.

 

(4) Accrued Liabilities

 

Other current liabilities included accrued salaries and benefits and accrued property taxes.  The Partnership recognized $5.7 million and $5.5 million of accrued salaries and benefits as of June 30, 2015 and December 31, 2014, respectively.  The Partnership recognized $4.6 million and $4.8 million of accrued property taxes as of June 30, 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 June 30, 2015 and December 31, 2014 (in thousands):

 

 

Revolving Credit Facility

 

As of June 30, 2015, the Partnership was in compliance with all of its covenants under its revolving credit facility.

 

As of June 30, 2015, the Partnership had outstanding borrowings of $753.0 million, $156.2 million of available borrowing capacity and borrowing base availability of $347.0 million. The Partnership’s interest rate in effect for all borrowings under its revolving credit facility as of June 30, 2015 and December 31, 2014 was 2.19% and 2.16%, respectively, with an average interest rate of 2.19% and 2.28% during the three months ended June 30, 2015 and 2014, respectively, and 2.19% and 2.22% during the six months ended June 30, 2015 and 2014, respectively.  There were no letters of credit issued as of June 30, 2015 or 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.

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(6)  Partners’ Capital

 

As of August 3, 2015, USA Compression Holdings held 5,997,651 common units and 14,048,588 subordinated units and controlled the General Partner which held an approximate 1.6% 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 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 (dollars in millions, except distribution per unit):

 

 

Dividend Reinvestment Program

 

During the six months ended June 30, 2015 and June 30, 2014, distributions of $27.0 million and $25.8 million, respectively, were reinvested under the distribution reinvestment plan (the “DRIP”) resulting in the issuance of 1.3 million and 0.9 million common units, respectively.  Such distributions are treated as non-cash transactions in the accompanying Unaudited Condensed Consolidated Statements of Cash Flows.  After taking into account the number of common units issued under the DRIP through June 30, 2015, we have the capacity to issue an additional 3.8 million common units under the DRIP.

 

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Issuance of Equity in Private Placement

 

On May 21, 2015, we issued 34,921 common units in a private placement to Argonaut for $0.7 million in a transaction that was exempt from registration under Section 4(a)(2) of the Securities Act. We used the proceeds from the private placement for general partnership purposes.  There were no other unregistered sales of securities during the three and six months ended June 30, 2015.

 

Announced Quarterly Distribution

 

On July 23, 2015, the Partnership announced a cash distribution of $0.525 per unit on its common and subordinated units. The distribution will be paid on August 14, 2015 to unitholders of record as of the close of business on August 4, 2015. USA Compression Holdings, the owner of approximately 43% of the Partnership’s outstanding limited partner interests, and Argonaut and certain of its related parties, the owners of approximately 17% of the Partnership’s outstanding limited partner interests, each have elected to reinvest all of this distribution with respect to their units pursuant to the DRIP (other than the 34,921 units recently acquired by Argonaut). 

 

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 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 (loss) allocated to 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 (loss) 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 (loss) 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.  For the three and six months ended June 30, 2015, approximately 74,000 and 106,000 incremental phantom units, respectively, were excluded from the calculation of diluted units because the impact was anti-dilutive.

 

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

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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”) and PVR ceasing existence as a separate 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 and six months ended June 30, 2015, the Partnership recognized $2.2 million and $4.0 million, respectively, in revenue on compression services and $1.0 million in accounts receivable from CONE on the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2015.

 

(8)  Commitments and Contingencies

 

(a)  Major Customers

 

The Partnership had revenue from one customer representing 10.3% and 11.7% of total revenue for the three months ended June 30, 2015 and 2014, respectively. The Partnership had revenue from the same customer representing 10.5% and 12.0% of total revenue for the six months ended June 30, 2015 and 2014, respectively.  No other customer represented greater than 10% of revenue for the three months ended June 30, 2015 or 2014 or the six months ended June 30, 2015 or 2014.

 

(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 June 30, 2015 were $76.2 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

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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.  This 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 this 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 ASU on its 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.  At the June 18, 2015 meeting of the FASB’s Emerging Issues Task Force, the SEC staff announced that it would not object to an entity’s deferral and presentation of such costs incurred in connection with revolving-debt arrangements as an asset.  As all of the Partnership’s debt issuance costs are associated with the revolving credit facility, this ASU currently has no impact on the Partnership’s consolidated financial statements.

 

In July 2015, the FASB agreed to defer by one year the mandatory effective date of its revenue recognition standard to annual and interim periods in fiscal years beginning after December 15, 2017, but will also provide entities the option to adopt it as of the original effective date. The option to use either a retrospective or cumulative-effect transition method will not change.  The Partnership is currently evaluating the impact, if any, of this ASU on its consolidated financial statements.

 

Also in July 2015, the FASB issued an ASU that changes the measurement principle for inventory from the lower of cost or market to the lower of cost and net realizable value.  The ASU requires prospective adoptions for inventory measurements for annual and interim periods in fiscal years beginning after December 15, 2016. Early adoptions is permitted. The Partnership is currently evaluating the impact, if any, of this ASU on its 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, Delaware 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 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 in recent years 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.  In the past few quarters, commodity prices have declined significantly.  As a result, we have experienced a limited amount of pressure on service rates until such time as commodity prices return to higher levels. However, we believe that through prudent management of our fleet we will be able to maintain strong utilization throughout 2015.    We are closely monitoring developments in our customer base, but we 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, primarily through the purchase of larger horsepower units that tend to generate higher margins and command longer contract terms, in order to be positioned to take advantage of attractive market opportunities.

 

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. During 2015 we have been able to increase both our fleet size and our contract rates as a result of increasing demand for our services.  Revenue generating horsepower increased by 17.5% from June 30, 2014 to June 30, 2015. Average revenue generating horsepower increased by 21.2% from the three months ended June 30, 2014 to the three months ended June 30, 2015. Average revenue per revenue generating horsepower per month increased approximately 3% in the six months ended June 30, 2015 from the six months ended June 30, 2014 and increased approximately 2% in the three months ended June 30, 2015 from the three months ended June 30, 2014. Average utilization decreased approximately 3% in the six months ended June 30, 2015 from the six months ended June 30, 2014 and decreased approximately 5% in the three months ended June 30, 2015 from the three months ended June 30, 2014.  The decrease in utilization is primarily attributable to an increase in the amount of time contracting new compression units.  We believe this is the result of a delay in planned projects of certain of our customers.  As a result, during the second quarter of 2015, we moved the delivery of approximately 30,000 large horsepower from the second half of 2015 to the first half of 2016.  Concurrently, we have seen an increase in demand for services using small horsepower and have added to our order approximately 10,000 small horsepower for delivery during the second half of 2015.  For the year ending December 31, 2015, we expect to purchase approximately 215,000 horsepower of new compression unit equipment, all of which has already been ordered.

 

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 plays, which typically require greater compression services in production.  

 

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 June 30, 2015 were 44% lower than prices at June 30, 2014.  During periods of lower crude oil and natural gas prices, domestic crude oil and natural gas production growth could moderate or decline. A 1% decrease in average revenue generating horsepower of our active fleet during the six months ended June 30, 2015 would have resulted in a decrease of approximately $2.7 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 (loss), 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 21.3% increase in fleet horsepower as of June 30, 2015 over the fleet horsepower as of June 30, 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 17.5% 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 June 30, 2015 was primarily attributable to a $12.0 million increase in Gross operating margin.  The increase in Gross operating margin is primarily attributed to the 21.2% increase in average revenue generating horsepower as a result of increased demand for our compression services.

 

The increase in Adjusted EBITDA during the six months ended June 30, 2015 was primarily attributable to a $25.3 million increase in Gross operating margin, offset by a $1.4 million increase in selling, general and administrative expenses.  The increase in Gross operating margin is primarily attributed to the 23.9% increase in average 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 June 30, 2015 was primarily attributable to a $12.0 million increase in Gross operating margin along with lower maintenance capital expenditures during the comparable period, offset by higher cash interest expense, net.  The increase in Gross operating margin is primarily attributed to the 21.2% increase in average revenue generating horsepower as a result of increased demand for our compression services.  

 

The increase in Adjusted DCF during the six months ended June 30, 2015 was primarily attributable to a $25.3 million increase in Gross operating margin along with lower maintenance capital expenditures during the comparable period, offset by higher cash interest expense, net.  The increase in Gross operating margin is primarily attributed to the 23.9% increase in average revenue generating horsepower as a result of increased demand for our compression services.  

 

 

 

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Financial Results of Operations

 

Three months ended June 30, 2015 compared to the three months ended June 30, 2014

 

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

 

 

 

Contract operations revenue.  During the three months ended June 30, 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 21.2% increase in average revenue generating horsepower was primarily due to organic growth.  Average revenue per revenue generating horsepower per month increased from $15.48 for the three months ended June 30, 2014 to $15.83 for the three months ended June 30, 2015, an increase of 2.3%, 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 due to organic growth. Certain cost increases consisted of (1) a $1.1 million increase in labor expenses, (2) a $0.3 million increase in indirect expenses, the majority of which is higher property and other taxes and (3) a $0.3 million increase in direct expenses such as parts and fluids for the fleet.  

 

Gross operating margin. The $12.0 million increase in gross operating margin was due to higher revenues partially offset by higher operating expenses during the three months ended June 30, 2015. The 5.1% increase in gross operating margin percentage from 66.2% for the three months ended June 30, 2014 to 71.3% for the three months ended June 30, 2015 was attributable to (1) certain cost savings initiatives, (2) timing of certain maintenance activities and (3) lower fuel costs.

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Selling, general and administrative expense.  Selling, general and administrative expense for the three months ended June 30, 2015 was consistent with the comparable period in prior year.

 

Depreciation and amortization expense.  The $4.5 million increase in depreciation expense was related to an increase in property and equipment balances during the three months ended June 30, 2015 compared to the three months ended June 30, 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.

 

Loss (gain) on sale of assets.  The gain on sale during the three months ended June 30, 2014 was a result of the completion of a purchase option agreement with a customer which was a one-time event.  There was no such event during the three months ended June 30, 2015.

 

Impairment on compression equipment.    The $26.8 million impairment charge during the three months ended June 30, 2015 resulted from our evaluation of the future deployment of our current idle fleet under the current market conditions, and we determined to retire and either sell or re-utilize the key components of 166 compressor units, or approximately 58,000 horsepower, that were previously used to provide services in the Partnership’s business. 

 

Interest expense, net. The increase in interest expense, net was primarily attributable to the impact of an approximate $259.0 million increase in average outstanding borrowings. Average borrowings outstanding under our revolving credit facility were $741.3 million for the three months ended June 30, 2015 compared to $482.3 million for the three months ended June 30, 2014.  Our revolving credit facility had an interest rate of 2.19% and 2.40% at June 30, 2015 and 2014, respectively, and an average interest rate of 2.19% and 2.28% for the three months ended June 30, 2015 and 2014, respectively.

 

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

 

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Six months ended June 30, 2015 compared to the six months ended June 30, 2014

 

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

 

 

Contract operations revenue.  During the six months ended June 30, 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 23.9% increase in average revenue generating horsepower was primarily due to organic growth.  Average revenue per revenue generating horsepower per month increased from $15.39 for the six months ended June 30, 2014 to $15.84 for the six months ended June 30, 2015, an increase of 2.9%, 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 due to organic growth. Certain cost increases consisted primarily of (1) a  $2.3 million increase in labor expenses and (2) a $1.1 million increase in indirect expenses, the majority of which is higher property and other taxes.  

 

Gross operating margin. The $25.3 million increase in gross operating margin was due to higher revenues partially offset by higher operating expenses during the six months ended June 30, 2015. The 5.4% increase in gross operating margin percentage from 65.5% for the six months ended June 30, 2014 to 70.9% for the six months ended June 30, 2015 was attributable to (1) certain cost savings initiatives, (2) timing of certain maintenance activities and (3) lower fuel costs.

 

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Selling, general and administrative expense.  The increase in selling, general and administrative expense was primarily related to a $2.6 million rise in salaries and benefits related to an increase in employee headcount. The selling, general and administrative employee headcount was 115 as of June 30, 2015, a 7.5% increase from June 30, 2014. The selling, general and administrative employee headcount increased to support the continued growth of the business.  This was offset by a $1.2 million decrease in professional fees.

 

Depreciation and amortization expense.  The $9.0 million increase in depreciation expense was related to an increase in gross property and equipment balances during the six months ended June 30, 2015 compared to the six months ended June 30, 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.

 

Loss (gain) on sale of assets.  The $0.2 million gain on sale of assets during the six months ended June 30, 2015 was primarily attributable to a cash insurance recovery on previously impaired compression equipment received during the first quarter of 2015.  The majority of the gain on sale during the six months ended June 30, 2014 was a result of the completion of a purchase option agreement with a customer which was a one-time event.

 

Impairment on compression equipment.    The $26.8 million impairment charge during the three months ended June 30, 2015 resulted from our evaluation of the future deployment of our current idle fleet under the current market conditions, and we determined to retire and either sell or re-utilize the key components of 166 compressor units, or approximately 58,000 horsepower, that were previously used to provide services in the Partnership’s business.    

 

Interest expense, net. The increase in interest expense, net was primarily attributable to the impact of an approximate $224.7 million increase in average outstanding borrowings, offset by $0.4 million additional interest income related to a capital lease which commenced during the second quarter of 2014. Average borrowings outstanding under our revolving credit facility were $700.1 million for the six months ended June 30, 2015 compared to $475.4 million for the six months ended June 30, 2014.  Our revolving credit facility had an interest rate of 2.19% and 2.40% at June 30, 2015 and 2014, respectively, and an average interest rate of 2.19% and 2.22% for the six months ended June 30, 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 six months ended June 30, 2015 and 2014 as of the end of the periods presented (in thousands):

 

 

 

Net cash provided by operating activities. The $16.9 million increase in net cash provided by operating activities for the six months ended June 30, 2015 relates primarily to a $25.3 million increase in gross operating margin and approximately $5.0 million higher cash collections as a result of an improving Days Sales Outstanding ratio, offset by a $11.5 million increase in inventory purchases, a $2.6 million increase in property tax payments, and a $2.9 million increase in bonus payments.

 

Net cash used in investing activities. Net cash used in investing activities for the six months ended June 30, 2015 related primarily to purchases of new compression units and related equipment in response to increasing demand for our services.

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Net cash provided by financing activities. During the six months ended June 30, 2015, we borrowed, on a net basis, $158.9 million primarily to support our purchases of new compression units, as described above, paid various loan fees and incurred costs in respect of our revolving credit facility in the amount of $3.4 million and made cash distributions to our unitholders of $21.5 million.  During the six months ended June 30, 2014, we borrowed, on a net basis, $168.3 million, including the use of proceeds from an equity offering to pay down our revolving credit facility, primarily to support purchases of new compression units and make cash distributions to our unitholders of $12.1 million. 

 

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 six months ended June 30, 2015 and 2014 were $7.2 million and $9.1 million, respectively. We currently plan to spend approximately $17 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 $225 million and $245 million in expansion capital expenditures during 2015. Our expansion capital expenditures for the six months ended June 30, 2015 and 2014 were $176.8 million and $179.4 million, respectively.

 

Revolving Credit Facility

 

As of June 30, 2015, we were in compliance with all of our debt covenants under our revolving credit facility.  As of June 30, 2015, we had outstanding borrowings of $753.0 million, $156.2 million of available borrowing capacity and borrowing base availability was $347.0 million. One of the financial covenants under our revolving credit facility permits a maximum leverage ratio of (a) 5.95 to 1.0 as of June 30, 2015, (b) 5.5 to 1.0 through the end of the fiscal quarter ending June 30, 2016 and (c) 5.00 to 1.0 thereafter, in each case subject to a provision for increases in such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.  As a result of our need to comply with such financial covenant, we expect borrowings under our revolving credit facility, cash generated from operations and issuance of debt securities may not be sufficient to fund all of our short-term liquidity needs and that we will potentially need to issue equity securities in the next twelve months.  We expect, however, to be able to remain in compliance with such financial covenant by one or more of the following actions: delay a discretionary portion of our capital expenditures; issue equity in conjunction with the acquisition of another business; issue equity in a public or private offering; or request an equity infusion pursuant to the terms of our revolving credit facility.

 

As of August 3, 2015, we had outstanding borrowings under our revolving credit facility of $774.9 million.

 

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Distribution Reinvestment Plan

 

During the six months ended June 30, 2015, distributions of $27.0 million were reinvested under the DRIP resulting in the issuance of 1.3 million common units.  Such distributions are treated as non-cash transactions in the accompanying Unaudited Condensed Statements of Cash Flows.  After taking into account the number of common units issued under the DRIP through June 30, 2015, we have the capacity to issue an additional 3.8 million common units under the DRIP.

 

For a more detailed description of the DRIP, please see Note 6 to our unaudited condensed consolidated financial statements.

 

 

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 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 (loss) 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 (loss) determined under GAAP, as well as gross operating margin, to evaluate our operating profitability.

 

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

 

 

 

Adjusted EBITDA

 

We define EBITDA as net income (loss) 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

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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.

 

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), 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 (loss) 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 (loss) 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.

 

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The following table reconciles Adjusted EBITDA to net income (loss) 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 (loss) 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 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 (loss), operating income (loss), 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.

 

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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 (loss) 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 (loss) 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 (loss) 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 unaudited 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 June 30, 2015 we had approximately $753.0 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 June 30, 2015 would have resulted in an annual increase or decrease in our interest expense of approximately $7.5 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 June 30, 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.