usac_Current folio_10Q

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 September 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)


Delaware		75-2771546
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

100 Congress Avenue, Suite 450
Austin, Texas		78701
(Address of principal executive offices)		(Zip Code)

(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):


Large accelerated filer ☐		Accelerated filer ☒

Non-accelerated filer ☐ (Do not check if a smaller reporting company)		Smaller reporting company ☐

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 November 3, 2015, there were 37,593,010 common units and 14,048,588 subordinated units outstanding.

PART I. FINANCIAL INFORMATION

ITEM 1.Financial Statements

USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Balance Sheets

(Dollars in thousands, except unit amounts)


	September 30,		December 31,
	2015		2014
Assets
Current assets:
Cash and cash equivalents	$	7	$	6
Accounts receivable, net:
Trade, net		28,723		25,159
Other		3,188		2,926
Inventory, net		22,273		8,923
Prepaid expenses		2,419		1,020
Total current assets		56,610		38,034
Property and equipment, net		1,302,554		1,162,637
Installment receivable		18,037		20,241
Identifiable intangible assets, net		79,669		82,357
Goodwill		208,055		208,055
Other assets		7,259		5,158
Total assets	$	1,672,184	$	1,516,482
Liabilities and Partners’ Capital
Current liabilities:
Accounts payable	$	11,646	$	44,535
Accrued liabilities		39,699		21,708
Deferred revenue		17,087		15,855
Total current liabilities		68,432		82,098
Long-term debt		712,314		594,864
Other liabilities		1,076		—
Partners’ capital:
Limited partner interest:
Common units, 37,589,602 and 31,307,116 units issued and outstanding, respectively		673,334		600,401
Subordinated units, 14,048,588 issued and outstanding each period		204,157		225,221
General partner interest		12,871		13,898
Total partners’ capital		890,362		839,520
Total liabilities and partners’ capital	$	1,672,184	$	1,516,482

See accompanying notes to unaudited condensed consolidated financial statements.

USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Operations

(Dollars in thousands, except unit amounts)


	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Revenues:
Contract operations	$	68,227	$	55,293	$	197,814	$	157,317
Parts and service		2,313		1,752		4,116		3,198
Total revenues		70,540		57,045		201,930		160,515
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization		21,919		19,430		60,209		55,145
Selling, general and administrative		10,351		10,443		30,430		29,098
Depreciation and amortization		21,360		18,261		63,598		51,525
Loss (gain) on sale of assets		920		63		702		(2,228)
Impairment of compression equipment (Note 3)		443		1,163		27,272		1,163
Total costs and expenses		54,993		49,360		182,211		134,703
Operating income		15,547		7,685		19,719		25,812
Other income (expense):
Interest expense, net		(4,665)		(2,677)		(13,074)		(9,269)
Other		6		5		16		6
Total other expense		(4,659)		(2,672)		(13,058)		(9,263)
Net income before income tax expense		10,888		5,013		6,661		16,549
Income tax expense (Note 5)		1,083		—		1,304		103
Net income	$	9,805	$	5,013	$	5,357	$	16,446
Net income allocated to:
General partner’s interest in net income	$	411	$	194	$	778	$	467
Limited partners’ interest in net income:
Common units	$	7,185	$	3,338	$	3,868	$	11,133
Subordinated units	$	2,209	$	1,481	$	711	$	4,846
Weighted average common units outstanding:
Basic		34,123,395		30,460,239		32,761,032		27,197,912
Diluted		34,233,579		30,517,689		32,868,130		27,263,124
Weighted average subordinated units outstanding:
Basic and diluted		14,048,588		14,048,588		14,048,588		14,048,588
Net income per common unit:
Basic	$	0.21	$	0.11	$	0.12	$	0.41
Diluted	$	0.21	$	0.11	$	0.12	$	0.41
Net income per subordinated unit:
Basic and diluted	$	0.16	$	0.11	$	0.05	$	0.34
Distributions declared per limited partner unit for respective periods	$	0.525	$	0.505	$	1.565	$	1.495

See accompanying notes to unaudited condensed consolidated financial statements.

USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital

Nine Months Ended September 30, 2015

(Dollars and units in thousands)


	Partners’ Capital								Total
	Common Units			Subordinated Units			General Partner		Partners’
	Units	Amount		Units	Amount		Amount		Capital
Partners’ capital, December 31, 2014	31,307	$	600,401	14,049	$	225,221	$	13,898	$	839,520
Vesting of phantom units	97		1,714	—		—		—		1,714
Distributions and DERs	—		(49,736)	—		(21,775)		(1,805)		(73,316)
Issuance of common units	6,186		116,877	—		—		—		116,877
Unit-based compensation	—		210	—		—		—		210
Net income	—		3,868	—		711		778		5,357
Partners’ capital, September 30, 2015	37,590	$	673,334	14,049	$	204,157	$	12,871	$	890,362

See accompanying notes to unaudited condensed consolidated financial statements.

USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES

Unaudited Condensed Consolidated Statements of Cash Flows

(Dollars in thousands)


	Nine months ended September 30,
	2015		2014
Cash flows from operating activities:
Net income	$	5,357	$	16,446
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		63,598		51,525
Amortization of debt issue costs		1,286		917
Unit-based compensation expense		3,068		2,956
Net loss (gain) on sale of assets		702		(2,228)
Impairment of compression equipment		27,272		1,163
Changes in assets and liabilities:
Accounts receivable		(1,622)		(1,861)
Inventory		(14,335)		1,191
Prepaids		(1,398)		1,013
Other noncurrent assets		(2)		(76)
Accounts payable		(8,875)		(6,986)
Accrued liabilities and deferred revenue		7,692		6,541
Net cash provided by operating activities		82,743		70,601
Cash flows from investing activities:
Capital expenditures		(240,634)		(275,229)
Proceeds from sale of property and equipment		503		621
Proceeds from insurance recovery		563		—
Net cash used in investing activities		(239,568)		(274,608)
Cash flows from financing activities:
Proceeds from long-term debt		392,265		390,088
Payments on long-term debt		(274,814)		(301,340)
Net proceeds from issuance of common units		75,163		137,285
Cash paid for taxes related to net settlement of unit-based awards		(189)		—
Cash distributions		(32,213)		(22,228)
General partner contribution		—		294
Financing costs and registration fees		(3,386)		(92)
Net cash provided by financing activities		156,826		204,007
Increase in cash and cash equivalents		1		—
Cash and cash equivalents, beginning of period		6		7
Cash and cash equivalents, end of period	$	7	$	7
Supplemental cash flow information:
Cash paid for interest	$	12,726	$	9,324
Cash paid for taxes	$	299	$	115
Supplemental non-cash transactions:
Non-cash distributions to certain limited partners (DRIP)	$	41,714	$	38,548
Change in capital expenditures included in accounts payable and accrued liabilities	$	11,749	$	(21,124)

See accompanying notes to unaudited condensed consolidated financial statements.

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” refer to Argonaut Private Equity, L.L.C.

The Partnership, through its Operating Subsidiaries, provides 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:


	September 30, 2015
	USA
	Compression		Argonaut and
	Holdings		Related Parties		Public		Total
General partner interest	1.5	%	—		—		1.5	%
Limited partner interest:
Common units	12.6	%	15.5	%	43.6	%	71.7	%
Subordinated units	26.8	%	—		—		26.8	%
Total	40.9	%	15.5	%	43.6	%	100.0	%

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 filed on February 19, 2015 (our “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 September 30, 2015 and December 31, 2014, and the results of operations for the three and nine months ended September 30, 2015 and 2014, changes in partners’ capital for the nine months ended September 30, 2015 and the statements of cash flows for the nine months ended September 30, 2015 and 2014 in accordance with U.S. generally accepted accounting principles (“GAAP”). Operating results for the three and nine months ended September 30, 2015 and 2014 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 U.S. 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.

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


	Customer				Non-compete
	Relationships		Trade Names		Agreement		Total
Net Balance at December 31, 2014	$	68,653	$	13,104	$	600	$	82,357
Amortization Expense		(2,051)		(468)		(169)		(2,688)
Net Balance at September 30, 2015	$	66,602	$	12,636	$	431	$	79,669

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 $15.5 million and $12.8 million as of September 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 nine months ended September 30, 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 compression 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:


Compression equipment		20 - 25 years
Furniture and fixtures		7 years
Vehicles and computer equipment		3 - 7 years
Leasehold improvements		5 years

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 to our unaudited condensed consolidated financial statements for more detailed information about impairment charges during the three and nine months ended September 30, 2015.

(3) Property and Equipment

Property and equipment consisted of the following at September 30, 2015 and December 31, 2014 (in thousands):


	September 30, 2015		December 31, 2014
Compression equipment	$	1,490,233	$	1,311,943
Furniture and fixtures		652		619
Automobiles and vehicles		19,076		17,303
Computer equipment		16,528		11,913
Leasehold improvements		1,080		858
Total		1,527,569		1,342,636
Less accumulated depreciation and amortization		(225,015)		(179,999)
Total	$	1,302,554	$	1,162,637

We recognized $20.5 million and $17.4 million of depreciation expense on property and equipment for the three months ended September 30, 2015 and 2014, respectively. We recognized $60.9 million and $48.8 million of depreciation expense on property and equipment for the nine months ended September 30, 2015 and 2014, respectively.

As of September 30, 2015 and December 31, 2014, there was $20.6 million and $32.4 million, respectively, of property and equipment purchases in accounts payable and accrued liabilities.

During the nine months ended September 30, 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 nine months ended September 30, 2015, insurance recoveries of $0.6 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 Statements of Operations.

During the three months ended September 30, 2015, the Partnership incurred equipment damage to one of its fleet units resulting in a $0.4 million impairment of long-lived assets. During the three months 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, the Partnership recorded a $27.3 million impairment of long-lived assets in the nine months ended September 30, 2015. The Partnership recorded a $1.2 million impairment of compression equipment for each of the three and nine months ended September 30, 2014.

(4) Accrued Liabilities

Other current liabilities included accrued salaries and benefits and accrued property taxes. The Partnership recognized $9.6 million and $5.5 million of accrued salaries and benefits as of September 30, 2015 and December 31, 2014, respectively. The Partnership recognized $5.9 million and $4.8 million of accrued property taxes as of September 30, 2015 and December 31, 2014, respectively.

(5) Income Tax Expense

The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Therefore, income taxes are not levied at the entity level, but rather on the individual partners of the Partnership. Accordingly, the accompanying unaudited condensed consolidated financial statements do not include a provision for federal and state income taxes.

The Partnership is subject to the Revised Texas Franchise Tax (“Texas Margin Tax”). The Texas Margin Tax is computed on modified gross margin. The Partnership does not do business in any other state where a similar tax is applied.

Components of income tax expense are as follows (in thousands):


	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Current tax expense:
State income tax	$	7	$	—	$	228	$	103
Total current tax expense		7		—		228		103

Deferred tax expense:
State income tax	$	1,076	$	—	$	1,076	$	—
Total deferred tax expense		1,076		—		1,076		—

Total income tax expense	$	1,083	$	—	$	1,304	$	103

Deferred income tax balances are the direct effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities at the enacted tax rates expected to be in effect when the taxes are actually paid or recovered. The tax effects of temporary differences that give rise to deferred tax liabilities are as follows (in thousands):


	September 30, 2015		December 31, 2014
Deferred tax liabilities
Property and equipment	$	1,076	$	—
Total deferred tax liabilities		1,076		—
Net deferred tax liabilities	$	1,076	$	—

The Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification Topic 740-10 (“ASC 740-10”) provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. As of September 30, 2015, the Partnership had no material unrecognized tax benefits (as defined in ASC 740-10). We do not expect to incur interest charges or penalties related to our tax positions, but if such charges or penalties are incurred, our policy is to account for interest charges as Interest expense, net and penalties as Income tax expense in the Unaudited Condensed Consolidated Statements of Operations.

(6) Long-Term Debt

The long-term debt of the Partnership, of which there is no current portion, consisted of the following as of September 30, 2015 and December 31, 2014 (in thousands):


	September 30,		December 31,
	2015		2014
Revolving Credit Facility	$	712,314	$	594,864

Revolving Credit Facility

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

As of September 30, 2015, the Partnership had outstanding borrowings under its revolving credit facility of $712.3 million, $151.3 million of available borrowing capacity and borrowing base availability of $387.7 million. The Partnership’s interest rate in effect for all borrowings under its revolving credit facility as of September 30, 2015 and December 31, 2014 was 2.26% and 2.16%, respectively, with a weighted average interest rate of 2.25% and 2.29% during the three months ended September 30, 2015 and 2014, respectively, and 2.23% and 2.24% during the nine months ended September 30, 2015 and 2014, respectively. There were no letters of credit issued as of September 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 will be 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 the indenture governing such debt and any debt securities issued under such indenture, except a discharge or release by or as a result of payment under such guarantees. Capitalized terms used but not defined 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.

(7) Partners’ Capital

As of November 3, 2015, USA Compression Holdings held 6,581,328 common units and 14,048,588 subordinated units and controlled the General Partner which held an approximate 1.5% 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. The Partnership’s 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):


	Distribution per		Amount Paid to		Amount Paid to		Amount Paid to
	Limited Partner		Common		Subordinated		General		Total
Payment Date	Unit		Unitholders		Unitholder		Partner		Distribution
August 14, 2014		0.500		15.1		7.0		0.5		22.6
November 14, 2014		0.505		15.5		7.1		0.5		23.1
February 13, 2015		0.510		16.0		7.2		0.5		23.7
May 15, 2015		0.515		16.6		7.2		0.6		24.4
August 14, 2015		0.525		17.2		7.4		0.7		25.3

Announced Quarterly Distribution

On October 22, 2015, the Partnership announced a cash distribution of $0.525 per unit on its common and subordinated units. The distribution will be paid on November 13, 2015 to unitholders of record as of the close of business on November 3, 2015. USA Compression Holdings, the owner of approximately 40% 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, each have elected to reinvest all of this distribution with respect to its units pursuant to the Partnership’s distribution reinvestment plan (the “DRIP”).

Dividend Reinvestment Program

During the nine months ended September 30, 2015 and 2014, distributions of $41.7 million and $38.5 million, respectively, were reinvested under the DRIP resulting in the issuance of 2.2 million and 1.5 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 September 30, 2015, the Partnership has the capacity to issue an additional 3.0 million common units under the DRIP.

Equity Offering

On September 15, 2015, the Partnership closed a public offering of 4,000,000 common units at a price to the public of $19.33. The Partnership used the net proceeds of $74.4 million (net of underwriting discounts and commission and offering expenses) to reduce the indebtedness outstanding under its revolving credit facility.

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 FASB’s Accounting Standards Codification 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 the common and subordinated units, respectively, after deducting the amount allocated to the General Partner (including distributions to the General Partner on the General Partner Interest and 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 Interest (including its IDRs) 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 the Partnership’s 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.


		Marginal Percentage Interest
	Total Quarterly	in Distributions
	Distribution Per Unit	Unitholders		General Partner
Minimum Quarterly Distribution	$0.425	98.5	%	1.5	%
First Target Distribution	up to $0.4888	98.5	%	1.5	%
Second Target Distribution	above $0.4888 up to $0.5313	85.5	%	14.5	%
Third Target Distribution	above $0.5313 up to $0.6375	75.5	%	24.5	%
Thereafter	above $0.6375	50.5	%	49.5	%

(8) Transactions with Related Parties

William Shea, Jr., who has served as a director of the General Partner 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 the General Partner since October 2013, has served as a director of CONE Midstream GP, LLC (“CONE”) since October 2014. During the three and nine months ended September 30, 2015, the Partnership recognized $2.3 million and $6.3 million, respectively, in revenue on compression services and $0.9 million in accounts receivable from CONE on the Unaudited Condensed Consolidated Balance Sheet as of September 30, 2015.

(9) Commitments and Contingencies

(a) Major Customers

The Partnership had revenue from one customer representing 10.2% and 11.3% of total revenue for the three months ended September 30, 2015 and 2014, respectively. The Partnership had revenue from the same customer representing 10.4% and 11.7% of total revenue for the nine months ended September 30, 2015 and 2014, respectively. No other customer represented greater than 10% of revenue for the three or nine months ended September 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.

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 September 30, 2015 were $38.8 million, all of which are expected to be settled within the next twelve months.

(10) 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. This ASU is effective for annual and interim periods in fiscal years beginning after

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:

changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industry specifically;

competitive conditions in our industry;

changes in the long-term supply of and demand for crude oil and natural gas;

our ability to realize the anticipated benefits of acquisitions and to integrate the acquired assets with our existing fleet;

actions taken by our customers, competitors and third-party operators;

changes in the availability and cost of capital;

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

the effects of existing and future laws and governmental regulations; and

the effects of future litigation.

All forward-looking statements included in this report are based on information available to us on the date of this report and speak only as of 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 overall natural gas production and transportation volumes from domestic shale 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 gas lift applications on crude oil wells targeted by horizontal drilling techniques.

General Trends and Outlook

Since late 2014, commodity prices, and in particular crude oil prices, have declined significantly and have remained depressed. While our business does not have direct exposure to commodity prices, the current price environment has resulted in a slowdown in activity in many operating regions, particularly in those plays where producers target oil or other liquids. We believe this decreased level of operating activity could lead to less, or more delayed, incremental demand for compression services than in the recent past, although existing production will continue to require compression, and we expect our customers will continue to seek our infrastructure-oriented compression services.

A significant amount of our assets are utilized in natural gas infrastructure applications, primarily in centralized 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 service rates and higher sustained utilization rates relative to other businesses more tied to drilling activity and wellhead economics. A small portion of our fleet is used in connection with crude oil production using horizontal drilling techniques. Given the more pronounced crude oil price reduction, we have experienced a limited amount of pressure on service rates in gas lift applications, and expect that this trend could continue as prices remain depressed and activity levels remain low. To the extent we have seen pressure on those service rates, we have typically been able to secure some combination of future order commitments, exclusive service provider status or competitor equipment replacement agreements from our customers to help offset the decrease in pricing.

We believe that demand for our compression services will continue for the remainder of 2015 and throughout 2016, although management cannot predict any possible changes in such demand with reasonable certainty. We continue to monitor developments in our customer base, and 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. Through the nine months ended September 30, 2015, we increased our fleet size while maintaining high utilization and economically attractive service rates. Revenue generating horsepower increased by 12.4% from September 30, 2014 to September 30, 2015. Average revenue generating horsepower increased by 16.2% from the three months ended September 30, 2014 to the three months ended September 30, 2015. Average revenue per revenue generating horsepower per month increased approximately 3% in the nine months ended September 30, 2015 from the nine months ended September 30, 2014 and increased approximately 2% in the three months ended September 30, 2015 from the three months ended September 30, 2014. Average utilization decreased approximately 4% in the three and nine months ended September 30, 2015 from the three and nine months ended September 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. For the year ending December 31, 2015, we have ordered approximately 220,000 horsepower of new compression unit equipment, of which we have taken delivery of approximately 195,000 horsepower through September 30, 2015.

The EIA has projected that natural gas production growth will continue in the coming years due to increases in drilling efficiencies as well as a backlog of drilled but uncompleted wells in major supply areas, such as the Marcellus Shale. Additionally, according to the EIA, domestic exports, both to Mexico and through the start-up of various liquefied natural gas (“LNG”) projects in late 2015 and beyond, will increase. The EIA projects that approximately 70% of the increase in natural gas production through 2040 will come from shale plays, which typically require greater compression horsepower than conventional production.

Operating Highlights

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Fleet horsepower (at period end)(1)		1,686,300			1,452,833			1,686,300			1,452,833
Total available horsepower (at period end)(2)		1,690,440			1,534,018			1,690,440			1,534,018
Revenue generating horsepower (at period end)(3)		1,415,355			1,259,387			1,415,355			1,259,387
Average revenue generating horsepower(4)		1,423,749			1,224,938			1,404,899			1,159,473
Average revenue per revenue generating horsepower per month	$	15.94		$	15.67		$	15.87		$	15.48
Revenue generating compression units (at period end)		2,765			2,488			2,765			2,488
Average horsepower per revenue generating compression unit(5)		514			505			517			504
Horsepower utilization(6):
At period end		90.4	%		93.5	%		90.4	%		93.5	%
Average for the period(7)		90.2	%		94.0	%		90.9	%		94.3	%

(1)

Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of September 30, 2015, approximately 195,000 horsepower had been delivered during the first three quarters of 2015. Approximately 25,000 horsepower is expected to be delivered during the last quarter of 2015, totaling 220,000 horsepower expected to be delivered during 2015.

(2)

Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract.

(3)

Revenue generating horsepower is horsepower under contract for which we are billing a customer.

(4)

Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.

(5)

Calculated as the average of the month-end revenue generating horsepower per revenue generating compression unit for each month in the period.

(6)

Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is under contract but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at September 30, 2015 and September 30, 2014 was 83.9% and 86.7%, respectively.

(7)

Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue generating horsepower and fleet horsepower for the three months ended September 30, 2015 and September 30, 2014 was 85.3% and 87.5%, respectively. Average horsepower utilization based on revenue generating horsepower and fleet horsepower for the nine months ended September 30, 2015 and September 30, 2014 was 85.6% and 87.5%, respectively.

The 16.1% increase in fleet horsepower as of September 30, 2015 over the fleet horsepower as of September 30, 2014 was attributable to the compression units added to our fleet to meet the incremental demand by new and current customers for our compression services. The 16.2% increase in revenue generating horsepower as of September 30, 2015 over September 30, 2014 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):


	Three Months Ended September 30,						Percent		Nine Months Ended September 30,						Percent
Other Financial Data: (1)	2015			2014			Change		2015			2014			Change
Gross operating margin	$	48,621		$	37,615		29.3	%	$	141,721		$	105,370		34.5	%
Gross operating margin percentage(2)		68.9	%		65.9	%	4.5	%		70.2	%		65.6	%	6.9	%
Adjusted EBITDA	$	39,481		$	29,327		34.6	%	$	115,617		$	81,386		42.1	%
Adjusted EBITDA percentage(2)		56.0	%		51.4	%	8.9	%		57.3	%		50.7	%	12.9	%
Adjusted Distributable Cash Flow	$	32,269		$	22,955		40.6	%	$	92,809		$	59,653		55.6	%
Adjusted Distributable Cash Flow Coverage Ratio(3)		1.25	x		0.99	x	25.7	%		1.23	x		0.94	x	31.2	%
Cash Coverage Ratio(4)		3.12	x		2.37	x	31.6	%		3.07	x		2.53	x	21.1	%

(1)

Gross operating margin, Adjusted EBITDA, Adjusted Distributable Cash Flow (“Adjusted DCF”), Adjusted DCF Coverage Ratio and Cash Coverage Ratio are all non-GAAP financial measures. Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found under the caption “Non-GAAP Financial Measures.”

(2)

Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

(3)

For the three and nine months ended September 30, 2015, the Adjusted Distributable Cash Flow Coverage Ratio based on units outstanding at the respective record dates is 1.16x and 1.20x, respectively. For the nine months ended September 30, 2014, the Adjusted Distributable Cash Flow Coverage Ratio based on units outstanding at the respective record dates is 0.92x.

(4)

For the three and nine months ended September 30, 2015, the Cash Coverage Ratio based on units outstanding at the respective record dates is 2.65x and 2.89x, respectively. For the nine months ended September 30, 2014, the Cash Coverage Ratio based on units outstanding at the respective record dates is 2.38x.

Adjusted EBITDA. The increase in Adjusted EBITDA during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was primarily attributable to a $11.0 million increase in Gross operating margin. The increase in Gross operating margin is primarily attributable to increased revenue resulting from a 16.2% increase in average revenue generating horsepower due to increased demand for our compression services, partially offset by higher operating expenses.

The increase in Adjusted EBITDA during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 was primarily attributable to a $36.4 million increase in Gross operating margin, offset by a $1.3 million increase in selling, general and administrative expenses. The increase in Gross operating margin is primarily attributable to increased revenue resulting from a 21.2% increase in average revenue generating horsepower due to increased demand for our compression services, partially offset by higher operating expenses.

Adjusted DCF. The increase in Adjusted DCF during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 was primarily attributable to a $11.0 million increase in Gross operating margin and lower maintenance capital expenditures, partially offset by higher cash interest expense, net. The increase in Gross operating margin is primarily attributable to increased revenue resulting from a 16.2% increase in average revenue generating horsepower due to increased demand for our compression services, partially offset by higher operating expenses.

The increase in Adjusted DCF during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 was primarily attributable to a $36.4 million increase in Gross operating margin and lower maintenance capital expenditures, offset by higher cash interest expense, net. The increase in Gross operating margin is primarily attributable to increased revenue resulting from a 21.2% increase in average revenue generating horsepower due to increased demand for our compression services, partially offset by higher operating expenses.

Financial Results of Operations

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

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


	Three Months Ended September 30,				Percent
	2015		2014		Change
Revenues:
Contract operations	$	68,227	$	55,293	23.4	%
Parts and service		2,313		1,752	32.0	%
Total revenues		70,540		57,045	23.7	%
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization		21,919		19,430	12.8	%
Gross Operating Margin		48,621		37,615	29.3	%
Other operating and administrative costs and expenses:
Selling, general and administrative		10,351		10,443	(0.9)	%
Depreciation and amortization		21,360		18,261	17.0	%
Loss on sale of assets		920		63	1,360.3	%
Impairment of compression equipment		443		1,163	(61.9)	%
Total other operating and administrative costs and expenses		33,074		29,930	10.5	%
Operating income		15,547		7,685	102.3	%
Other income (expense):
Interest expense, net		(4,665)		(2,677)	74.3	%
Other		6		5	20.0	%
Total other expense		(4,659)		(2,672)	74.4	%
Income before income tax expense		10,888		5,013	117.2	%
Income tax expense		1,083		—	—	%
Net income	$	9,805	$	5,013	95.6	%

Contract operations revenue. During the three months ended September 30, 2015, we experienced an increase in demand for our compression services driven by an increase in overall natural gas production in the U.S., resulting in a 16.2% increase in average revenue generating horsepower and a $12.9 million increase in our contract operations revenue. Average revenue per revenue generating horsepower per month increased from $15.67 for the three months ended September 30, 2014 to $15.94 for the three months ended September 30, 2015, an increase of 1.7%, 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. 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.

Parts and service revenue. Parts and service revenue was earned primarily on freight and crane charges that are directly reimbursable by our customers, for which we earn little to no margin, and maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities, for which we earn lower margins than our contract operations. 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 $2.5 million increase in cost of operations was primarily attributable to the increase in our fleet size due to organic growth. Certain cost increases consisted of (1) a $1.4 million increase in labor expenses, and (2) a $1.3 million increase in direct expenses such as parts and fluids for the fleet and parts and service expenses, which have a corresponding increase in parts and service revenue.

Gross operating margin. The $11.0 million increase in gross operating margin was due to higher revenues partially offset by higher operating expenses during the three months ended September 30, 2015. The 3.0% increase in gross operating margin percentage from 65.9% for the three months ended September 30, 2014 to 68.9% for the three months

Nine months ended September 30, 2015 compared to the nine months ended September 30, 2014

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


	Nine Months Ended September 30,				Percent
	2015		2014		Change
Revenues:
Contract operations	$	197,814	$	157,317	25.7	%
Parts and service		4,116		3,198	28.7	%
Total revenues		201,930		160,515	25.8	%
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization		60,209		55,145	9.2	%
Gross Operating Margin		141,721		105,370	34.5	%
Other operating and administrative costs and expenses:
Selling, general and administrative		30,430		29,098	4.6	%
Depreciation and amortization		63,598		51,525	23.4	%
Loss (gain) on sale of assets		702		(2,228)	(131.5)	%
Impairment of compression equipment		27,272		1,163	2,245.0	%
Total other operating and administrative costs and expenses		122,002		79,558	53.3	%
Operating income		19,719		25,812	(23.6)	%
Other income (expense):
Interest expense, net		(13,074)		(9,269)	41.1	%
Other		16		6	166.7	%
Total other expense		(13,058)		(9,263)	41.0	%
Income before income tax expense		6,661		16,549	(59.7)	%
Income tax expense		1,304		103	1,166.0	%
Net income	$	5,357	$	16,446	(67.4)	%

Contract operations revenue. During the nine months ended September 30, 2015, we experienced an increase in demand for our compression services driven by an increase in overall natural gas production in the U.S., resulting in a 21.2% increase in average revenue generating horsepower and a $40.5 million increase in our contract operations revenue. Average revenue per revenue generating horsepower per month increased from $15.48 for the nine months ended September 30, 2014 to $15.87 for the nine months ended September 30, 2015, an increase of 2.5%, 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. 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.

Cost of operations, exclusive of depreciation and amortization. The $5.1 million increase in cost of operations was primarily attributable to the increase in our fleet size due to organic growth. Certain cost increases consisted primarily of (1) a $3.7 million increase in labor expenses, (2) a $1.5 million increase in direct expenses such as parts and service expenses, which have a corresponding increase in parts and service revenue, and (3) a $1.0 million increase in indirect expenses, the majority of which being higher property and other taxes.

Gross operating margin. The $36.4 million increase in gross operating margin was due to higher revenues partially offset by higher operating expenses during the nine months ended September 30, 2015. The 4.6% increase in gross operating margin percentage from 65.6% for the nine months ended September 30, 2014 to 70.2% for the nine months ended September 30, 2015 was attributable to (1) certain cost savings initiatives, (2) timing of certain preventative maintenance activities and (3) lower fuel costs.

Selling, general and administrative expense. The $1.3 million increase in selling, general and administrative expense for the nine months ended September 30, 2015 was primarily attributable to a $3.6 million increase in salaries and benefits expenses and a $0.8 million increase in bad debt expense offset by a $2.2 million decrease in professional fees and a $0.4 million decrease in certain information technology costs.

Depreciation and amortization expense. The $12.1 million increase in depreciation expense was related to an increase in gross property and equipment balances as of September 30, 2015 compared to balances as of September 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 $0.7 million loss on sale of assets during the nine months ended September 30, 2015 was primarily attributable to $1.3 million of losses incurred in the disposal of various unit and non-unit assets, offset by the $0.2 million and $0.4 million cash insurance recoveries on previously impaired compression equipment received during the first and third quarters of 2015. The majority of the gain on sale during the nine months ended September 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. A majority of the $27.3 million impairment charge during the nine months ended September 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 during the second quarter of 2015, or approximately 58,000 horsepower, that were previously used to provide services in our business.

Interest expense, net. The $3.8 million increase in interest expense, net was primarily attributable to the impact of an approximate $246.4 million increase in average outstanding borrowings under our revolving credit facility, where average borrowings were $722.0 million for the nine months ended September 30, 2015 compared to $475.6 million for the nine months ended September 30, 2014. Our revolving credit facility had an interest rate of 2.26% and 2.15% at September 30, 2015 and 2014, respectively, and an average interest rate of 2.23% and 2.24% for the nine months ended September 30, 2015 and 2014, respectively.

Income tax expense. Income tax expense is associated with the Texas Margin Tax. The increase in income tax expense was primarily associated with the establishment of a deferred tax liability for the basis difference in our property and equipment. We currently calculate our Texas Margin Tax using our gross margin.

Liquidity and Capital Resources

Overview

We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of compression units and make other capital expenditures, service our debt, fund working capital and pay distributions. Our principal sources of liquidity include cash generated by operating activities, borrowings under our revolving credit facility and issuances of debt and equity securities, including under the DRIP.

We believe cash generated by operating activities and, where necessary, borrowings under our revolving credit facility will be sufficient to service our debt, fund working capital and fund our maintenance capital expenditures. Because we distribute all of our available cash, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under our revolving credit facility and issuances of debt and equity securities, including under the DRIP.

Cash Flows

The following table summarizes our sources and uses of cash for the nine months ended September 30, 2015 and 2014 as of the end of the periods presented (in thousands):


	Nine Months Ended September 30,
	2015		2014
Net cash provided by operating activities	$	82,743	$	70,601
Net cash used in investing activities		(239,568)		(274,608)
Net cash provided by financing activities		156,826		204,007

Net cash provided by operating activities. The $12.1 million increase in net cash provided by operating activities for the nine months ended September 30, 2015 relates primarily to a $36.4 million increase in gross operating margin, offset by a $9.0 million increase in inventory purchases, a $3.8 million increase in prepaid insurance payments, a $3.8 million increase in cash interest paid, a $2.9 million increase in bonus payments, a $1.2 million increase in selling, general and administrative expenses, excluding unit-based compensation expense, and a $1.0 million increase in property tax payments.

Net cash used in investing activities. Net cash used in investing activities for the nine months ended September 30, 2015 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 nine months ended September 30, 2015, we borrowed $192.6 million, on a net basis, including the use of proceeds from an equity offering to reduce indebtedness outstanding under our revolving credit facility, primarily to support our purchases of new compression units, as described above. Additionally, we 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 $32.2 million. During the nine months ended September 30, 2014, we borrowed $226.0 million, on a net basis, including the use of proceeds from an equity offering to reduce indebtedness outstanding under our revolving credit facility, primarily to support purchases of new compression units and make cash distributions to our unitholders of $22.2 million.

Equity Offering

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:

maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets, to maintain the operating capacity of our assets and extend their useful lives, or other capital expenditures that are incurred in maintaining our existing business and related cash flow; and

expansion capital expenditures, which are capital expenditures made to expand the operating capacity or revenue generating capacity of existing or new assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity.

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 nine months ended September 30, 2015 and 2014 were $10.1 million and $12.4 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 natural gas activity described above under the heading “—Overview —General Trends and Outlook,” we anticipate that we will continue to make expansion capital expenditures. Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently expect to spend approximately $245 million in expansion capital expenditures during 2015. Our expansion capital expenditures for the nine months ended September 30, 2015 and 2014 were $232.1 million and $262.8 million, respectively. As of September 30, 2015, we had binding commitments to purchase $38.8 million of additional units, which we expect to be delivered in the remainder of 2015 and during 2016.

Revolving Credit Facility

As of September 30, 2015, we were in compliance with all of our covenants under our revolving credit facility. As of September 30, 2015, we had outstanding borrowings under our revolving credit facility of $712.3 million, $151.3 million of available borrowing capacity and borrowing base availability was $387.7 million.

As of November 3, 2015, we had outstanding borrowings under our revolving credit facility of $722.5 million.

For a more detailed description of our revolving credit facility, please see Note 6 to our unaudited condensed consolidated financial statements under Part I, Item 1 of this report and Note 7 to the audited consolidated financial statements included in our 2014 Annual Report.

Distribution Reinvestment Plan

During the nine months ended September 30, 2015, distributions of $41.7 million were reinvested under the DRIP resulting in the issuance of 2.2 million common units. Such distributions are treated as non-cash transactions in the accompanying Unaudited Condensed Statements of Cash Flows included under Part I, Item 1 of this report. After taking into account the number of common units issued under the DRIP through September 30, 2015, we have the capacity to issue an additional 3.0 million common units under the DRIP.

For a more detailed description of the DRIP, please see Note 7 to our unaudited condensed consolidated financial statements under Part I, Item 1 of this report and Note 8 to the audited consolidated financial statements included in our 2014 Annual Report.

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 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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Revenues:
Contract operations	$	68,227	$	55,293	$	197,814	$	157,317
Parts and service		2,313		1,752		4,116		3,198
Total revenues		70,540		57,045		201,930		160,515
Cost of operations, exclusive of depreciation and amortization		21,919		19,430		60,209		55,145
Gross operating margin		48,621		37,615		141,721		105,370
Other operating and administrative costs and expenses:
Selling, general and administrative		10,351		10,443		30,430		29,098
Depreciation and amortization		21,360		18,261		63,598		51,525
Loss (gain) on sale of assets		920		63		702		(2,228)
Impairment of compression equipment		443		1,163		27,272		1,163
Total other operating and administrative costs and expenses		33,074		29,930		122,002		79,558
Operating income	$	15,547	$	7,685	$	19,719	$	25,812

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, loss (gain) 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:

the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;

the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;

the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and

our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

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, 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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Net income	$	9,805	$	5,013	$	5,357	$	16,446
Interest expense, net		4,665		2,677		13,074		9,269
Depreciation and amortization		21,360		18,261		63,598		51,525
Income taxes		1,083		—		1,304		103
EBITDA	$	36,913	$	25,951	$	83,333	$	77,343
Impairment of compression equipment		443		1,163		27,272		1,163
Interest income on capital lease		401		433		1,242		835
Unit-based compensation expense(1)		804		855		3,068		2,957
Transaction expenses for acquisitions(2)		—		862		—		1,282
Loss (gain) on sale of assets and other		920		63		702		(2,194)
Adjusted EBITDA	$	39,481	$	29,327	$	115,617	$	81,386
Interest expense, net		(4,665)		(2,677)		(13,074)		(9,269)
Income tax expense		(1,083)		—		(1,304)		(103)
Interest income on capital lease		(401)		(433)		(1,242)		(835)
Transaction expenses for acquisitions		—		(862)		—		(1,282)
Other		416		43		1,286		882
Changes in operating assets and liabilities		445		13,534		(18,540)		(178)
Net cash provided by operating activities	$	34,193	$	38,932	$	82,743	$	70,601

(1)

For the three and nine months ended September 30, 2015, unit-based compensation expense included $0.2 million and $0.6 million, respectively, of cash payments related to quarterly payments of distribution equivalent rights on phantom unit awards and, for the nine months ended September 30, 2015, $0.2 million related to the cash portion of any settlement of phantom unit awards upon vesting. For the three and nine months ended September 30, 2014, unit-based compensation expense included $0.2 million and $0.3 million, respectively, of cash payments related to quarterly payments of distribution equivalent rights on phantom unit awards and, for the nine months ended September 30, 2014, $0.3 million related to the cash portion of any settlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense for both periods was related to non-cash adjustments to the unit-based compensation liability.

(2)

Represents certain transaction expenses related to potential acquisitions and other items. The Partnership believes it is useful to investors to exclude these fees.

Adjusted Distributable Cash Flow

We define distributable cash flow as net income plus non-cash interest expense, non-cash income tax 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 loss (gain) 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, 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, loss (gain) 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):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Net income	$	9,805	$	5,013	$	5,357	$	16,446
Plus: Non-cash interest expense		416		43		1,286		917
Plus: Non-cash income tax expense		1,076		—		1,076		—
Plus: Depreciation and amortization		21,360		18,261		63,598		51,525
Plus: Unit-based compensation expense(1)		804		855		3,068		2,957
Plus: Impairment of compression equipment		443		1,163		27,272		1,163
Less: Maintenance capital expenditures(2)		(2,959)		(3,305)		(10,113)		(12,443)
Distributable cash flow	$	30,945	$	22,030	$	91,544	$	60,565
Transaction expenses for acquisitions(3)		—		862		—		1,282
Loss (gain) on sale of assets and other		1,324		63		1,265		(2,194)
Adjusted distributable cash flow	$	32,269	$	22,955	$	92,809	$	59,653
Plus: Maintenance capital expenditures		2,959		3,305		10,113		12,443
Plus: Changes in operating assets and liabilities		445		13,534		(18,540)		(178)
Less: Transaction expenses for acquisitions		—		(862)		—		(1,282)
Less: Other		(1,480)		—		(1,639)		(35)
Net cash provided by operating activities	$	34,193	$	38,932	$	82,743	$	70,601

(1)

(2)

Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the operating capacity of our assets and extend their useful lives, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.

(3)

Represents certain transaction expenses related to potential acquisitions and other items. We believe it is useful to investors to view its results excluding these fees.

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.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Adjusted distributable cash flow	$	32,269	$	22,955	$	92,809	$	59,653
Cash distributions to GP and IDRs		697		506		1,956		1,401
Adjusted distributable cash flow attributable to LP interest	$	31,572	$	22,449	$	90,853	$	58,252

Distributions for Coverage Ratio(1)	$	25,290	$	22,606	$	73,648	$	61,967

Distributions reinvested in the DRIP(2)	$	15,179	$	13,148	$	44,021	$	38,956

Distributions for Cash Coverage Ratio(3)	$	10,111	$	9,458	$	29,627	$	23,011

Adjusted Distributable Cash Flow Coverage Ratio(4)		1.25		0.99		1.23		0.94

Cash Coverage Ratio(5)		3.12		2.37		3.07		2.53

(1)

Represents distribution to the holders of the Partnership’s units, after giving effect to the weighted average of units outstanding for each period due to our May 2014 and September 2015 public equity offerings, for the three and nine months ended September 30, 2015 and nine months ended September 30, 2014. Represents distribution to units outstanding at the record date for the three months ended September 30, 2014.

(2)

Represents distributions to holders enrolled in the DRIP as of the record date for each period. Amount for the three and nine months ended September 30, 2015 is based on an estimate as of the record date.

(3)

Represents cash distributions declared for common units not participating in the DRIP, after giving effect to the weighted average of units outstanding for each period due to our May 2014 and September 2015 public equity offerings, for the three and nine months ended September 30, 2015 and nine months ended September 30, 2014. Represents cash distributions declared for common units not participating in the DRIP at the record date for the three months ended September 30, 2014.

(4)

(5)

Off-Balance Sheet Arrangements

We have no off-balance sheet financing activities.

Recent Accounting Pronouncement

For discussion on specific recent accounting pronouncements affecting us, please see Note 10 to our unaudited condensed consolidated financial statements under Part I, Item 1 of this report.

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. A 1% decrease in average revenue generating horsepower of our active fleet during the nine months ended September 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, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read “Item 2—Non-GAAP Financial Measures” of this report.

Interest Rate Risk

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

As of September 30, 2015, we had approximately $712.3 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 2.23%. A 1% increase or decrease in the effective interest rate on our variable-rate outstanding debt at September 30, 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 6 to our unaudited condensed consolidated financial statements under Part I, Item 1 of this report. 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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


November 5, 2015	USA Compression Partners, LP

	By:	USA Compression GP, LLC
		its General Partner


	By:	/s/ Eric D. Long
		President and Chief Executive Officer
		(Principal Executive Officer)


	By:	/s/ Matthew C. Liuzzi
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)


	By:	/s/ Michael D. Lenox
		Vice President- Finance and Chief Accounting Officer
		(Principal Accounting Officer)


Exhibit No.		Description
3.1		Certificate of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1 to Amendment No. 3 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on December 21, 2011)
3.2		First Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 18, 2013)
31.1	*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2	*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1	#	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	#	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.1	*	Interactive data files pursuant to Rule 405 of Regulation S-T


		Page
PART I. FINANCIAL INFORMATION		1
ITEM 1. Financial Statements		1
Unaudited Condensed Consolidated Balance Sheets		1
Unaudited Condensed Consolidated Statements of Operations		2
Unaudited Condensed Consolidated Statement of Changes in Partners’ Capital		3
Unaudited Condensed Consolidated Statements of Cash Flows		4
Notes to Unaudited Condensed Consolidated Financial Statements		5
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		28
ITEM 4. Controls and Procedures		28
PART II. OTHER INFORMATION		30
ITEM 1. Legal Proceedings		30
ITEM 1A. Risk Factors		30
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds		30
ITEM 3. Defaults Upon Senior Securities		30
ITEM 4. Mine Safety Disclosures		30
ITEM 5. Other Information		30
ITEM 6. Exhibits		30
SIGNATURES		31