UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2013
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-33631
Crestwood Midstream Partners LP
(Exact name of registrant as specified in its charter)
| | |
Delaware | | 56-2639586 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| |
700 Louisiana Street, Suite 2060, Houston, Texas | | 77002 |
(Address of principal executive offices) | | (Zip Code) |
(832) 519-2200
(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 x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| | | | | | |
Large accelerated filer | | ¨ | | Accelerated filer | | x |
| | | |
Non-accelerated filer | | ¨ (Do not check if 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 x
Indicate the number of shares outstanding of the issuer’s common units and Class C units, as of the latest practicable date:
| | |
Title of Class | | Outstanding as of April 29, 2013 |
Common Units | | 53,764,924 |
CRESTWOOD MIDSTREAM PARTNERS LP
TABLE OF CONTENTS
2
FORWARD-LOOKING INFORMATION
In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “CMLP,” or the “Partnership” are intended to mean the business and operations of Crestwood Midstream Partners LP and its consolidated subsidiaries.
Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (SEC), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “plan,” “aim,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.
Important factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include, but are not limited to, the following risks and uncertainties:
| • | | changes in general economic conditions; |
| • | | fluctuations in oil, natural gas and natural gas liquid (NGL) prices; |
| • | | the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within areas of acreage dedicated on and within the proximity of our assets; |
| • | | failure or delays by our customers in achieving expected production in their natural gas projects; |
| • | | competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering and processing assets or systems; |
| • | | actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers; |
| • | | our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition; |
| • | | changes in the availability and cost of capital; |
| • | | operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control; |
| • | | timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and right-of-way and other factors that may impact our ability to complete projects within budget and on schedule; |
| • | | the effects of existing and future laws and governmental regulations, including environmental and climate change requirements; |
| • | | the effects of future litigation; |
| • | | risks related to our substantial indebtedness; and |
| • | | certain factors discussed elsewhere in this report. |
These factors do not necessarily include all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to, or effect on, us or our business or operations. Also note that we provided additional cautionary discussion of risks and uncertainties under “Risk Factors” in our 2012 Annual Report on Form 10-K, in our other public filings and press releases. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future periodic reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except for per unit data)
(Unaudited)
| | | | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2013 | | | 2012 | |
Operating revenues | | | | | | | | |
Gathering revenues | | $ | 23,996 | | | $ | 11,837 | |
Gathering revenues—related party | | | 19,907 | | | | 23,846 | |
Processing revenues | | | 4,048 | | | | 1,196 | |
Processing revenues—related party | | | 5,682 | | | | 6,771 | |
Compression revenues | | | 3,926 | | | | — | |
Product sales | | | 14,857 | | | | 10,083 | |
| | | | | | | | |
Total operating revenues | | | 72,416 | | | | 53,733 | |
| | | | | | | | |
Operating expenses | | | | | | | | |
Product purchases | | | 6,748 | | | | 8,973 | |
Product purchases – related party | | | 6,757 | | | | — | |
Operations and maintenance | | | 13,016 | | | | 9,711 | |
General and administrative | | | 7,789 | | | | 6,738 | |
Depreciation, amortization and accretion | | | 17,360 | | | | 10,646 | |
| | | | | | | | |
Total operating expenses | | | 51,670 | | | | 36,068 | |
| | | | | | | | |
Operating income | | | 20,746 | | | | 17,665 | |
| | |
Interest and debt expense | | | (11,450 | ) | | | (7,557 | ) |
| | | | | | | | |
| | |
Income before income taxes | | | 9,296 | | | | 10,108 | |
| | |
Income tax expense | | | 338 | | | | 303 | |
| | | | | | | | |
Net income | | $ | 8,958 | | | $ | 9,805 | |
| | | | | | | | |
General partner’s interest in net income | | $ | 5,201 | | | $ | 3,368 | |
| | |
Limited partners’ interest in net income | | $ | 3,757 | | | $ | 6,437 | |
| | |
Basic income per unit: | | | | | | | | |
Net income per limited partner unit | | $ | 0.07 | | | $ | 0.15 | |
| | |
Diluted income per unit: | | | | | | | | |
Net income per limited partner unit | | $ | 0.07 | | | $ | 0.15 | |
See accompanying notes.
4
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
(Unaudited)
| | | | | | | | |
| | March 31, | | | December 31, | |
| | 2013 | | | 2012 | |
ASSETS | | | | | | | | |
Current assets | | | | | | | | |
Cash and cash equivalents | | $ | 35 | | | $ | 111 | |
Accounts receivable | | | 24,317 | | | | 21,636 | |
Accounts receivable—related party | | | 23,556 | | | | 23,755 | |
Insurance receivable | | | 3,014 | | | | 2,920 | |
Prepaid expenses and other | | | 1,257 | | | | 1,941 | |
| | | | | | | | |
Total current assets | | | 52,179 | | | | 50,363 | |
Property, plant and equipment, net of accumulated depreciation of $141,517 in 2013 and $130,030 in 2012 | | | 950,889 | | | | 939,846 | |
Intangible assets, net of accumulated amortization of $18,334 in 2013 and $12,814 in 2012 | | | 495,860 | | | | 501,380 | |
Goodwill | | | 95,031 | | | | 95,031 | |
Deferred financing costs, net | | | 21,473 | | | | 22,528 | |
Other assets | | | 1,375 | | | | 1,321 | |
| | | | | | | | |
Total assets | | $ | 1,616,807 | | | $ | 1,610,469 | |
| | | | | | | | |
LIABILITIES AND PARTNERS’ CAPITAL | | | | | | | | |
Current liabilities | | | | | | | | |
Accrued additions to property, plant and equipment | | $ | 7,626 | | | $ | 9,213 | |
Capital leases | | | 3,776 | | | | 3,862 | |
Deferred revenue | | | 2,426 | | | | 2,634 | |
Accounts payable—related party | | | 3,639 | | | | 3,088 | |
Accounts payable, accrued expenses and other liabilities | | | 37,687 | | | | 29,717 | |
| | | | | | | | |
Total current liabilities | | | 55,154 | | | | 48,514 | |
Long-term debt | | | 727,602 | | | | 685,161 | |
Long-term capital leases | | | 2,314 | | | | 3,161 | |
Asset retirement obligations | | | 14,222 | | | | 14,024 | |
Commitments and contingent liabilities (Note 7) | | | | | | | | |
| | |
Partners’ capital | | | | | | | | |
Common unitholders (45,740,110 and 41,164,737 units issued and outstanding at March 31, 2013 and December 31, 2012) | | | 527,293 | | | | 442,348 | |
Class C unitholders (7,349,814 and 7,165,819 units issued and outstanding at March 31, 2013 and December 31, 2012) | | | 160,374 | | | | 159,908 | |
Class D unitholder (6,190,469 units issued and outstanding at March 31, 2013) | | | 126,678 | | | | — | |
General partner (1,112,674 and 979,614 units issued and outstanding at March 31, 2013 and December 31, 2012) | | | 3,170 | | | | 257,353 | |
| | | | | | | | |
Total partners’ capital | | | 817,515 | | | | 859,609 | |
| | | | | | | | |
Total liabilities and partners’ capital | | $ | 1,616,807 | | | $ | 1,610,469 | |
| | | | | | | | |
See accompanying notes.
5
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
| | | | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2013 | | | 2012 | |
Cash flows from operating activities | | | | | | | | |
Net income | | $ | 8,958 | | | $ | 9,805 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Depreciation, amortization and accretion | | | 17,360 | | | | 10,646 | |
Equity-based compensation | | | 597 | | | | 493 | |
Other non-cash income items | | | 1,142 | | | | 1,302 | |
Changes in assets and liabilities: | | | | | | | | |
Accounts receivable | | | (2,681 | ) | | | (2,111 | ) |
Accounts receivable—related party | | | 199 | | | | 4,092 | |
Insurance receivable | | | (94 | ) | | | — | |
Prepaid expenses and other assets | | | 630 | | | | 715 | |
Accounts payable—related party | | | 551 | | | | 456 | |
Accounts payable, accrued expenses and other liabilities | | | 7,372 | | | | (3,245 | ) |
| | | | | | | | |
Net cash provided by operating activities | | | 34,034 | | | | 22,153 | |
| | | | | | | | |
Cash flows from investing activities | | | | | | | | |
Capital expenditures | | | (24,273 | ) | | | (12,889 | ) |
Acquisitions, net of cash acquired | | | — | | | | (376,805 | ) |
| | | | | | | | |
Net cash used in investing activities | | | (24,273 | ) | | | (389,694 | ) |
| | | | | | | | |
Cash flows from financing activities | | | | | | | | |
Proceeds from credit facilities | | | 199,500 | | | | 192,000 | |
Repayments of credit facilities | | | (157,000 | ) | | | (141,250 | ) |
Payments on capital leases | | | (1,005 | ) | | | (666 | ) |
Deferred financing costs paid | | | (82 | ) | | | (6,314 | ) |
Proceeds from issuance of common units, net | | | 103,500 | | | | 103,050 | |
Contributions from partners | | | — | | | | 243,750 | |
Distribution to General Partner for additional interest in CMM | | | (129,000 | ) | | | — | |
Distributions to partners | | | (25,096 | ) | | | (20,729 | ) |
Taxes paid for equity-based compensation vesting | | | (654 | ) | | | (402 | ) |
| | | | | | | | |
Net cash provided by (used in) financing activities | | | (9,837 | ) | | | 369,439 | |
| | | | | | | | |
Change in cash and cash equivalents | | | (76 | ) | | | 1,898 | |
Cash and cash equivalents at beginning of period | | | 111 | | | | 797 | |
| | | | | | | | |
Cash and cash equivalents at end of period | | $ | 35 | | | $ | 2,695 | |
| | | | | | | | |
See accompanying notes.
6
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(In thousands)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | |
| | Limited Partners | | | | | | | |
| | Common | | | Class C Unitholders | | | Class D Unitholder | | | General Partner | | | Total | |
Partners’ capital as of December 31, 2012 | | $ | 442,348 | | | $ | 159,908 | | | $ | — | | | $ | 257,353 | | | $ | 859,609 | |
Issuance of units, net of offering costs | | | 103,101 | | | | — | | | | — | | | | — | | | | 103,101 | |
Issuance of units | | | — | | | | — | | | | 126,286 | | | | (126,286 | ) | | | — | |
Net income | | | 2,899 | | | | 466 | | | | 392 | | | | 5,201 | | | | 8,958 | |
Equity-based compensation | | | 597 | | | | — | | | | — | | | | — | | | | 597 | |
Taxes paid for equity-based compensation vesting | | | (654 | ) | | | — | | | | — | | | | — | | | | (654 | ) |
Distributions to partners | | | (20,998 | ) | | | — | | | | — | | | | (4,098 | ) | | | (25,096 | ) |
Distribution to General Partner for additional interest in CMM | | | — | | | | — | | | | — | | | | (129,000 | ) | | | (129,000 | ) |
| | | | | | | | | | | | | | | | | | | | |
Partners’ capital as of March 31, 2013 | | $ | 527,293 | | | $ | 160,374 | | | $ | 126,678 | | | $ | 3,170 | | | $ | 817,515 | |
| | | | | | | | | | | | | | | | | | | | |
| | | |
| | Limited Partners | | | | | | | |
| | Common | | | Class C Unitholders | | | Class D Unitholder | | | General Partner | | | Total | |
Partners’ capital as of December 31, 2011 | | $ | 286,945 | | | $ | 157,386 | | | $ | — | | | $ | 11,292 | | | $ | 455,623 | |
Issuance of units, net of offering costs | | | 103,050 | | | | — | | | | — | | | | — | | | | 103,050 | |
Contributions from partners | | | — | | | | — | | | | — | | | | 243,750 | | | | 243,750 | |
Net income | | | 5,437 | | | | 1,000 | | | | | | | | 3,368 | | | | 9,805 | |
Equity-based compensation | | | 493 | | | | — | | | | — | | | | — | | | | 493 | |
Taxes paid for equity-based compensation vesting | | | (402 | ) | | | — | | | | — | | | | — | | | | (402 | ) |
Distributions to partners | | | (17,903 | ) | | | — | | | | — | | | | (2,826 | ) | | | (20,729 | ) |
| | | | | | | | | | | | | | | | | | | | |
Partners’ capital as of March 31, 2012 | | $ | 377,620 | | | $ | 158,386 | | | $ | — | | | $ | 255,584 | | | $ | 791,590 | |
| | | | | | | | | | | | | | | | | | | | |
See accompanying notes.
7
CRESTWOOD MIDSTREAM PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Organization
Crestwood Midstream Partners LP (CMLP) is a publicly traded Delaware limited partnership formed for the purpose of acquiring and operating midstream assets. Crestwood Gas Services GP LLC, our general partner (General Partner), is owned by Crestwood Holdings Partners LLC and its affiliates (Crestwood Holdings). Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “CMLP.”
Organizational Structure
The following chart depicts our ownership structure as of March 31, 2013:
8
Our general partner and limited partner ownership interests as of March 31, 2013 is as follows:
| | | | | | | | | | | | |
| | Crestwood | | | | | | | |
| | Holdings | | | Public | | | Total | |
General partner interest | | | 1.8 | % | | | — | | | | 1.8 | % |
Limited partner interests: | | | | | | | | | | | | |
Common unitholders | | | 32.4 | % | | | 43.4 | % | | | 75.8 | % |
Class C unitholders | | | 0.2 | % | | | 12.0 | % | | | 12.2 | % |
Class D unitholder | | | 10.2 | % | | | — | | | | 10.2 | % |
| | | | | | | | | | | | |
Total | | | 44.6 | % | | | 55.4 | % | | | 100.0 | % |
| | | | | | | | | | | | |
See Note 4.Net Income Per Limited Partner Unit and Distributionsfor additional information concerning ownership interests.
Description of Business
We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing producers in the Marcellus Shale in northern West Virginia, the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Avalon Shale/Bone Spring in southeastern New Mexico and the Haynesville/Bossier Shale in western Louisiana.
2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the SEC and in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim consolidated financial statements. Accordingly, they do not include all of the disclosures required by GAAP.
On March 26, 2012, Crestwood Holdings contributed approximately $244 million for a 65% membership interest in Crestwood Marcellus Midstream LLC (CMM) and we contributed approximately $131 million for a 35% membership interest in CMM. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM and as a result, we now own 100% of CMM and have the ability to control the operating and financial decisions of CMM. We accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions require us to retroactively adjust our historical results. Accordingly, the consolidated balance sheets reflect the historical carrying value of CMM’s assets and liabilities. Earnings related to the recast of our historical results due to the acquisition of the 65% membership interest in CMM were allocated to the General Partner. As a result, there was no impact to our basic or diluted earnings per limited partner unit. We funded the purchase price for the 65% membership interest in CMM of approximately $258 million through $129 million of borrowings under our CMLP credit facility, the issuance of 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings, and the issuance of 133,060 general partner units to our General Partner. For accounting purposes, because of the consolidation of CMM, we reflected the $129 million cash paid to acquire the 65% interest in CMM and the issuance of Class D units as a reduction of our General Partner’s capital.
You should read this Quarterly Report on Form 10-Q along with our 2012 Annual Report on Form 10-K filed with the SEC on February 27, 2013, and our 8-K filed with the SEC on March 18, 2013. The financial statements as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 are unaudited. The consolidated balance sheet as of December 31, 2012, was derived from the audited balance sheet filed in our Form 8-K filed with the SEC on March 18, 2013. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. Information for interim periods may not be indicative of our operating results for the entire year. Our disclosures in this Form 10-Q are an update to those provided in our 2012 Annual Report on Form 10-K and our 8-K filed with the SEC on March 18, 2013.
9
Significant Accounting Policies
There were no changes in the significant accounting policies described in our 2012 Annual Report on Form 10-K filed with the SEC on February 27, 2013, except as noted below.
Revenues
Our revenues are generated from the gathering, compression and processing of natural gas from producers predominately under fee-based contracts. Our gathering revenues relate to contracts pursuant to which we both transport and compress natural gas based on the volumes that flow through our systems and are not directly dependent on commodity prices. Compression revenues relate to contracts under which we solely provide compression services or contracts under which we charge a compression services fee that is separate from other services provided under the contracts. For the three months ended March 31, 2013, our compression revenues were entirely comprised of services provided under contracts obtained in the E. Marcellus Asset Company, LLC (EMAC) acquisition (See Note 3). Under our processing contracts, raw natural gas is gathered, processed and sold at published index prices. Producers are paid based on an agreed percentage of the residue gas and NGLs multiplied by index prices or the actual sale prices.
3. ACQUISITIONS
2012 Acquisitions
Antero Acquisition
On February 27, 2012, we announced the execution, through CMM, of an Asset Purchase Agreement related to the acquisition of gathering assets owned by Antero Resources Appalachian Corporation (Antero) in the Marcellus Shale located in Harrison and Doddridge Counties, West Virginia (Antero Acquisition), and, at closing, the planned execution of a 20 year, fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero. On March 26, 2012, CMM completed the Antero Acquisition for approximately $380 million. The assets acquired by CMM consisted of a 33 mile low pressure gathering system at the time of acquisition. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion, Equitrans and Mark West Energy Partners’ Sherwood Gas Processing Plant.
The GGA with Antero provided for an area of dedication at the time of acquisition of approximately 127,000 gross acres, or 104,000 net acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. As part of the GGA, Antero committed to deliver minimum annual throughput volumes to us for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 million cubic feet per day (MMcf/d) in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s potential ability to recover this amount if Antero’s 2013 throughput volumes exceed the minimum annual throughput volumes included in the GGA for 2013.
The final purchase price allocation is as follows (In thousands):
| | | | |
Purchase price: | | | | |
| |
Cash | | $ | 381,718 | |
| | | | |
Total purchase price | | $ | 381,718 | |
| | | | |
Purchase price allocation: | | | | |
| |
Property, plant and equipment | | $ | 90,562 | |
Intangible assets | | | 291,218 | |
| | | | |
Total assets | | $ | 381,780 | |
| | | | |
Asset retirement obligation | | $ | 62 | |
| | | | |
Total liabilities | | $ | 62 | |
| | | | |
Total | | $ | 381,718 | |
| | | | |
Our intangible assets recorded as a result of the Antero Acquisition relate to the GGA with Antero. These intangible assets will be amortized over the life of the contract. For the period from the acquisition date (March 26, 2012) to March 31, 2012, we did not record operating income related to the operations of the assets acquired from Antero.
10
Devon Acquisition
On August 24, 2012, we completed the acquisition of certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon Energy Corporation (Devon) for approximately $87 million (Devon Acquisition). The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed.
The preliminary purchase price allocation is as follows (In thousands):
| | | | |
Purchase price: | | | | |
| |
Cash | | $ | 87,247 | |
| | | | |
Total purchase price | | $ | 87,247 | |
| | | | |
Preliminary purchase price allocation: | | | | |
| |
Property, plant and equipment | | $ | 41,555 | |
Intangible assets | | | 46,959 | |
| | | | |
Total assets | | $ | 88,514 | |
| | | | |
Asset retirement obligation | | $ | 540 | |
Property tax liability | | | 527 | |
Environmental liability | | | 200 | |
| | | | |
Total liabilities | | $ | 1,267 | |
| | | | |
Total | | $ | 87,247 | |
| | | | |
Our intangible assets recorded as a result of the Devon Acquisition relate to the 20 year fixed-fee gathering, processing and compression agreement with Devon. These intangible assets will be amortized over the life of the contract.
We believe that it is impracticable to present financial information for the acquired assets prior to the acquisition date due to the lack of availability of historical financial information related to the acquired assets, and because the 20 year fixed-fee gathering, processing and compression agreement with Devon has significantly different terms than the historical intercompany relationships between the acquired assets and Devon.
EMAC Acquisition
On December 28, 2012, CMM acquired all of the membership interest of EMAC from Enerven Compression, LLC (Enerven) for approximately $95 million. We financed this acquisition through our CMM credit facility. EMAC’s assets consist of four compression and dehydration stations located on our gathering systems in Harrison County, West Virginia. These assets will provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. The preliminary purchase price allocation is as follows (In thousands):
| | | | |
Purchase price: | | | | |
| |
Cash | | $ | 95,000 | |
| | | | |
Total purchase price | | $ | 95,000 | |
| | | | |
Preliminary purchase price allocation: | | | | |
| |
Property, plant and equipment | | $ | 45,938 | |
Intangible assets | | | 49,817 | |
| | | | |
Total assets | | $ | 95,755 | |
| | | | |
Asset retirement obligation | | $ | 755 | |
| | | | |
Total liabilities | | $ | 755 | |
| | | | |
Total | | $ | 95,000 | |
| | | | |
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Our intangible assets recorded as a result of the EMAC acquisition relate to the compression services agreements with Antero. These intangible assets will be amortized over the life of the contract. Pro forma information has not been provided for the acquisition of the EMAC assets as the impact is immaterial to our financial statements.
4. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS
Earnings Per Limited Partner Unit. Our net income is allocated to the General Partner and the limited partners, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the General Partner. To the extent cash distributions exceed net income, the excess distributions are allocated proportionately to all participating units outstanding based on their respective ownership percentages. Basic earnings per unit are computed by dividing net income attributable to limited partner unitholders by the weighted-average number of limited partner units outstanding during each period. Diluted earnings per unit are computed using the treasury stock method, which considers the impact to net income and limited partner units from the potential issuance of limited partner units.
The tables below show the (i) allocation of net income attributable to limited partners and the (ii) net income per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three months ended March 31, 2013 and 2012.
Allocation of Net Income to General Partner and Limited Partners
| | | | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2013 | | | 2012 | |
Net income | | $ | 8,958 | | | $ | 9,805 | |
General Partner’s incentive distributions | | | (5,036 | ) | | | (3,255 | ) |
| | | | | | | | |
Net income after incentive distributions | | | 3,922 | | | | 6,550 | |
General Partner’s interest in net income after incentive distributions | | | (165 | ) | | | (113 | ) |
| | | | | | | | |
Limited Partners’ interest in net income after distributions | | $ | 3,757 | | | $ | 6,437 | |
| | | | | | | | |
Net Income Per Limited Partner Unit
| | | | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2013 | | | 2012 | |
Limited partners’ interest in net income | | $ | 3,757 | | | $ | 6,437 | |
| | |
Weighted-average limited partner units—basic(1) | | | 54,766 | | | | 42,694 | |
| | |
Effect of unvested phantom units | | | 276 | | | | 183 | |
| | | | | | | | |
Weighted-average limited partner units—diluted(1) | | | 55,042 | | | | 42,877 | |
| | | | | | | | |
Basic earnings per unit: | | | | | | | | |
Net income per limited partner | | $ | 0.07 | | | $ | 0.15 | |
Diluted earnings per unit: | | | | | | | | |
Net income per limited partner | | $ | 0.07 | | | $ | 0.15 | |
(1) | Includes 12,902,110 Class C and Class D units for the three months ended March 31, 2013 and 6,716,730 Class C units for the three months ended March 31, 2012. |
There were no units excluded from our diluted earnings per unit as we do not have any anti-dilutive units for the three months ended March 31, 2013 and 2012.
Distributions. Our Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended (Partnership Agreement), requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (as defined therein) to unitholders of record on the applicable record date, as determined by our General Partner.
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The following table presents distributions for 2013 and 2012 (In millions, except per unit data):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Distribution Paid | | | | | | | |
| | | | | | | Limited Partner | | | General Partner | | | | | | | |
Payment Date | | Attributable to the Quarter Ended | | Per Unit Distribution | | | Cash paid to common | | | Paid-In-Kind Value to Class C unitholders | | | Paid-In-Kind Value to Class D unitholder | | | Cash paid to General Partner and IDR | | | Paid-In-Kind Value to Class C unitholder | | | Paid-In-Kind Value to Class D unitholder | | | Total Cash | | | Total Distribution | |
2013 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
May 10, 2013 | | March 31, 2013 | | $ | 0.51 | | | $ | 27.4 | | | $ | — | | | $ | 3.2 | | | $ | 5.2 | | | $ | — | | | $ | 0.5 | | | $ | 32.6 | | | $ | 36.3 | |
February 12, 2013 | | December 31, 2012 | | $ | 0.51 | | | $ | 21.0 | | | $ | 3.7 | | | | — | | | $ | 4.1 | | | $ | 0.6 | | | | — | | | $ | 25.1 | | | $ | 29.4 | |
2012 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
November 9, 2012 | | September 30, 2012 | | $ | 0.51 | | | $ | 21.0 | | | $ | 3.5 | | | | — | | | $ | 4.1 | | | $ | 0.6 | | | | — | | | $ | 25.1 | | | $ | 29.2 | |
August 10, 2012 | | June 30, 2012 | | $ | 0.50 | | | $ | 20.6 | | | $ | 3.4 | | | | — | | | $ | 3.7 | | | $ | 0.5 | | | | — | | | $ | 24.3 | | | $ | 28.2 | |
May 11, 2012 | | March 31, 2012 | | $ | 0.50 | | | $ | 18.2 | | | $ | 3.4 | | | | — | | | $ | 3.3 | | | $ | 0.5 | | | | — | | | $ | 21.5 | | | $ | 25.4 | |
February 10, 2012 | | December 31, 2011 | | $ | 0.49 | | | $ | 17.9 | | | $ | 3.2 | | | | — | | | $ | 2.8 | | | $ | 0.5 | | | | — | | | $ | 20.7 | | | $ | 24.4 | |
Our Class C and Class D units are substantially similar in all respects to our existing common units, representing limited partner interests, except that we have the option to pay distributions to our Class C and Class D unitholders with cash or by issuing additional Paid-In-Kind Class C or Class D units, respectively, based upon the volume weighted-average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. We issued 136,128 additional Class C units in lieu of paying cash quarterly distributions on our Class C units attributable to the quarter ended March 31, 2012. On April 1, 2013, our outstanding Class C units converted to common units on a one-for-one basis. The unitholders of the converted units will receive a quarterly cash distribution for the period ended March 31, 2013 although the Class C units were not converted until April 1, 2013.
On March 22, 2013, we completed a public offering of 4,500,000 common units, representing limited partner interests in us, at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. We granted the underwriters a 30-day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013 providing net proceeds of approximately $15.5 million. The unitholders of these common units will receive a quarterly distribution for the period ended March 31, 2013.
See our 2012 Annual Report on Form 10-K for additional information regarding our distributions.
5. FINANCIAL INSTRUMENTS
Fair Values
We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and would be reflected at the end of the period in which the change occurs. At March 31, 2013 and December 31, 2012, there have been no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified.
Cash and Cash Equivalents, Accounts Receivable and Accounts Payable. As of March 31, 2013 and December 31, 2012, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments.
Credit Facilities. The fair value of our credit facilities approximates their carrying amounts as of March 31, 2013 and December 31, 2012 due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.
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Senior Notes. We estimated the fair value of our 7.75% Senior Notes due April 2019 (Senior Notes) (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances. The following table reflects the carrying value and fair value of our Senior Notes (In millions):
| | | | | | | | | | | | | | | | |
| | March 31, 2013 | | | December 31, 2012 | |
| | Carrying Amount | | | Fair Value | | | Carrying Amount | | | Fair Value | |
Senior Notes | | $ | 351 | | | $ | 362 | | | $ | 351 | | | $ | 365 | |
Debt
Our long-term debt consists of the following (In thousands):
| | | | | | | | |
| | March 31, 2013 | | | December 31, 2012 | |
CMM Credit Facility, due March 2017 | | $ | 83,000 | | | $ | 127,000 | |
CMLP Credit Facility, due November 2017 | | | 293,200 | | | | 206,700 | |
Senior Notes, due April 2019 | | | 350,000 | | | | 350,000 | |
| | | | | | | | |
| | | 726,200 | | | | 683,700 | |
Plus: Unamortized premium on Senior Notes | | | 1,402 | | | | 1,461 | |
| | | | | | | | |
Total long-term debt | | $ | 727,602 | | | $ | 685,161 | |
| | | | | | | | |
Credit Facilities
CMM Credit Facility. The CMM credit agreement, dated March 26, 2012 (CMM Credit Facility) allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million. The CMM Credit Facility is secured by substantially all of CMM’s assets.
Borrowings under the CMM Credit Facility bear interest the London Interbank Offered Rate (LIBOR) plus an applicable margin or base rate as defined in the CMM Credit Facility. Under the terms of the CMM Credit Facility, the applicable margin under LIBOR was 2.3% and 2.5% at March 31, 2013 and December 31, 2012. The weighted-average interest rate as of March 31, 2013 and December 31, 2012 was 2.8%. Based on our results through March 31, 2013, our remaining available capacity under the CMM Credit Facility was $113 million. For the three months ended March 31, 2013, our average and maximum outstanding borrowings were approximately $123 million and $130 million.
The CMM Credit Facility requires CMM to maintain:
| • | | a ratio of trailing 12-month EBITDA (as defined in the CMM Credit Facility) to net interest expense of not less than 2.0 to 1.0; and |
| • | | a ratio of total indebtedness to trailing 12-month EBITDA (as defined in the CMM Credit Facility) of not more than 4.5 to 1.0, or not more than 5.0 to 1.0 for up to nine months following certain acquisitions. |
CMLP Credit Facility. Our amended and restated senior secured credit agreement, dated November 16, 2012 (CMLP Credit Facility), allows for revolving loans, letters of credit and swingline loans in an aggregate amount of up to $550 million. The CMLP Credit Facility is secured by substantially all of CMLP’s assets and those of certain of its subsidiaries. As of March 31, 2013, the CMLP Credit Facility is guaranteed by our 100% owned subsidiaries except for CMM and its consolidated subsidiaries.
Borrowings under the CMLP Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the CMLP Credit Facility. Under the terms of the CMLP Credit Facility, the applicable margin under LIBOR borrowings was 2.5% at March 31, 2013 and December 31, 2012. The weighted-average interest rate as of March 31, 2013 and December 31, 2012 was 2.8%. Based on our results through March 31, 2013, our remaining available capacity under the CMLP Credit Facility was $179 million. For the three months ended March 31, 2013, our average and maximum outstanding borrowings were $336 million and $373 million.
Our CMLP Credit Facility requires us to maintain:
| • | | a ratio of our consolidated trailing 12-month EBITDA (as defined in the CMLP Credit Facility) to our net interest expense of not less than 2.5 to 1.0; and |
| • | | a ratio of total indebtedness to consolidated trailing 12-month EBITDA (as defined in the CMLP Credit Facility) of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to nine months following certain acquisitions. |
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As of March 31, 2013, we were in compliance with the financial covenants under each of the CMM and CMLP Credit Facilities.
Our credit facilities contain restrictive covenants that prohibit the declaration or payment of distributions by us if a default then exists or would result therefrom, and otherwise limits the amount of distributions that we can make. An event of default may result in the acceleration of our repayment of outstanding borrowings under our credit facilities, the termination of our credit facilities and foreclosure on collateral.
Senior Notes
In November 2012, we issued an additional $150 million aggregate principal amount of 7.75% Senior Notes in a private placement offering. These notes were issued as additional notes under the indenture dated April 1, 2011 among us, Crestwood Midstream Finance Corporation, the guarantors names therein, and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which we previously issued our $200 million aggregate principal amount of 7.75% Senior Notes in April 2011. On March 28, 2013, we filed a registration statement on Form S-4 with the SEC related to these notes. Our Senior Notes require us to maintain a ratio of our consolidated trailing 12-month EBITDA (as defined in the indenture governing the Senior Notes) to fixed charges of at least 1.75 to 1.0. As of March 31, 2013, we were in compliance with this covenant. For additional information regarding our Senior Notes, see our 2012 Annual Report on Form 10-K.
6. ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITES
Accounts payable, accrued expenses and other liabilities consist of the following (In thousands):
| | | | | | | | |
| | March 31, 2013 | | | December 31, 2012 | |
Accrued expenses | | $ | 5,952 | | | $ | 9,608 | |
Accrued property taxes | | | 2,789 | | | | 5,638 | |
Accrued product purchases payable | | | 2,405 | | | | 2,450 | |
Tax payable | | | 2,480 | | | | 2,159 | |
Interest payable | | | 14,336 | | | | 7,505 | |
Accounts payable | | | 9,715 | | | | 2,278 | |
Other | | | 10 | | | | 79 | |
| | | | | | | | |
Total accounts payable, accrued expenses and other liabilities | | $ | 37,687 | | | $ | 29,717 | |
| | | | | | | | |
7. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Proceedings
From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. There are currently no such pending proceedings to which we are a party that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods. As of March 31, 2013, we had no amounts accrued for our legal proceedings. At December 31, 2012, we had less than $0.1 million accrued for our legal proceedings.
Regulatory Compliance
In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition.
Environmental Compliance
Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. We are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities
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must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At March 31, 2013 and December 31, 2012, we had accrued approximately $0.2 million for environmental matters, which is based on our undiscounted estimate of amounts we will spend on environmental compliance and remediation. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures could range from approximately $0.2 million to $0.3 million.
8. INCOME TAXES
No provision for federal or state income taxes is included in our results of operations as such income is taxable directly to the partners. Accordingly, each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
We are subject to Texas Margin tax and our current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. See our 2012 Annual Report on Form 10-K for more information about our income taxes.
9. EQUITY PLAN
Awards of phantom and restricted units have been granted under our Fourth Amended and Restated 2007 Equity Plan (2007 Equity Plan). The following table summarizes information regarding phantom and restricted unit activity during the three months ended March 31, 2013:
| | | | | | | | | | | | | | | | |
| | Payable In Cash | | | Payable In Units | |
| | Units | | | Weighted- Average Grant Date Fair Value | | | Units | | | Weighted- Average Grant Date Fair Value | |
Unvested—January 1, 2013 | | | 8,312 | | | $ | 26.45 | | | | 221,992 | | | $ | 28.35 | |
Vested—phantom units | | | — | | | | — | | | | (70,229 | ) | | $ | 28.74 | |
Vested—restricted units | | | — | | | | — | | | | (4,681 | ) | | $ | 29.20 | |
Granted—phantom units | | | — | | | | — | | | | 161,807 | | | $ | 24.33 | |
Granted—restricted units | | | — | | | | — | | | | 25,900 | | | $ | 24.80 | |
Canceled—phantom units | | | (156 | ) | | $ | 24.14 | | | | (4,897 | ) | | $ | 30.16 | |
| | | | | | | | | | | | | | | | |
Unvested—March 31, 2013 | | | 8,156 | | | $ | 26.49 | | | | 329,892 | | | $ | 25.98 | |
| | | | | | | | | | | | | | | | |
As of March 31, 2013 and December 31, 2012, we had total unamortized compensation expense of approximately $6 million and $3 million related to phantom and restricted units, which we expect will be amortized over three years (the original vesting period of these instruments), except for grants to non-employee directors of our General Partner which vest over one year. We recognized compensation expense of approximately $0.6 million and $0.5 million during the three months ended March 31, 2013 and 2012, included in operating expenses on our consolidated statements of income. We granted phantom and restricted units with a grant date fair value of approximately $5 million during the three months ended March 31, 2013. As of March 31, 2013, we had 343,737 units available for issuance under the 2007 Equity Plan.
Under the 2007 Equity Plan, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the 2007 Equity Plan on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the three months ended March 31, 2013 and 2012, we withheld 1,529 common units and 414 common units to satisfy employee tax withholding obligations. The withholding of common units by us could be deemed a purchase of the common units.
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10. TRANSACTIONS WITH RELATED PARTIES
We enter into transactions with our affiliates within the ordinary course of business. For a further discussion of our affiliated transactions, see our 2012 Annual Report on Form 10-K. The following table shows revenues and expenses from our affiliates for the three months ended March 31, 2013 and 2012. Reimbursements from our affiliates were less than $1 million for the three months ended March 31, 2013 and 2012.
| | | | | | | | |
| | 2013 | | | 2012 | |
| | (In millions) | |
Operating revenues | | $ | 26 | | | $ | 31 | |
Operating expenses | | | 13 | | | | 5 | |
11. PARTNERS’ CAPITAL
On March 22, 2013, we completed a public offering of 4,500,000 common units, representing limited partner interests in us at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. We granted the underwriters a 30 day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013, providing net proceeds of approximately $15.5 million. The net proceeds from these transactions were used to reduce indebtedness under each of the CMM and CMLP Credit Facilities. In connection with the issuance of the common units, our General Partner did not make an additional capital contribution to us resulting in a reduction in their general partner interest in us to approximately 1.8% at March 31, 2013.
12. SEGMENT INFORMATION
We conduct our operations in the midstream sector with eight operating segments, four of which are reportable segments. These operating segments reflect the way we internally report the financial information used to make decisions and allocate resources in connection with our operations. We evaluate the performance of our operating segments based on EBITDA, which represents operating income plus depreciation, amortization and accretion expense and income tax expense.
Our reportable segments reflect the primary geographic areas in which we operate and consist of Marcellus, Barnett, Fayetteville and Granite Wash, all of which are located within the United States. Our reportable segments are engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs. Our Other operating segment consists of those operating segments or reporting units that did not meet quantitative reporting thresholds.
For the three months ended March 31, 2013 and 2012, one of our customers in the Barnett segment, which is a related party, accounted for approximately 35% and 57% of our total revenues in the Barnett segment. In our Marcellus segment, one customer accounted for approximately 20% of our revenues for the three months ended March 31, 2013. In addition, in our Fayetteville segment, one customer accounted for approximately 10% of our total revenues for the three months ended March 31, 2012.
The following table is a reconciliation of net income to EBITDA (In thousands):
| | | | | | | | |
| | Three Months Ended March, | |
| | 2013 | | | 2012 | |
Net income | | $ | 8,958 | | | $ | 9,805 | |
Add: | | | | | | | | |
Interest and debt expense | | | 11,450 | | | | 7,557 | |
Income tax expense | | | 338 | | | | 303 | |
Depreciation, amortization and accretion expense | | | 17,360 | | | | 10,646 | |
| | | | | | | | |
EBITDA | | $ | 38,106 | | | $ | 28,311 | |
| | | | | | | | |
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The following tables summarize the reportable segment data for the three months ended March 31, 2013 and 2012 (In thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2013 | |
| | Marcellus | | | Barnett | | | Fayetteville | | | Granite Wash | | | Other | | | Corporate | | | Total | |
Operating revenues | | $ | 14,274 | | | $ | 9,396 | | | $ | 7,253 | | | $ | 13,414 | | | $ | 2,490 | | | $ | — | | | $ | 46,827 | |
Operating revenues—related party | | | — | | | | 25,154 | | | | — | | | | 435 | | | | — | | | | — | | | | 25,589 | |
Product purchases | | | — | | | | 255 | | | | 293 | | | | 5,450 | | | | 750 | | | | — | | | | 6,748 | |
Product purchases—related party | | | — | | | | — | | | | — | | | | 6,757 | | | | — | | | | — | | | | 6,757 | |
Operations and maintenance expense | | | 2,397 | | | | 7,255 | | | | 2,134 | | | | 608 | | | | 622 | | | | — | | | | 13,016 | |
General and administrative expense | | | — | | | | — | | | | — | | | | — | | | | — | | | | 7,789 | | | | 7,789 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA | | $ | 11,877 | | | $ | 27,040 | | | $ | 4,826 | | | $ | 1,034 | | | $ | 1,118 | | | $ | (7,789 | ) | | $ | 38,106 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Goodwill | | $ | — | | | $ | — | | | $ | 76,767 | | | $ | 14,211 | | | $ | 4,053 | | | $ | — | | | $ | 95,031 | |
Total assets | | $ | 513,787 | | | $ | 614,290 | | | $ | 299,784 | | | $ | 80,880 | | | $ | 84,572 | | | $ | 23,494 | | | $ | 1,616,807 | |
Capital expenditures | | $ | 12,025 | | | $ | 5,559 | | | $ | 956 | | | $ | 919 | | | $ | 4,473 | | | $ | 341 | | | $ | 24,273 | |
| |
| | Three Months Ended March 31, 2012 | |
| | Marcellus | | | Barnett | | | Fayetteville | | | Granite Wash | | | Other | | | Corporate | | | Total | |
Operating revenues | | $ | — | | | $ | 3,327 | | | $ | 6,864 | | | $ | 9,597 | | | $ | 3,328 | | | $ | — | | | $ | 23,116 | |
Operating revenues—related party | | | — | | | | 30,617 | | | | — | | | | — | | | | — | | | | — | | | | 30,617 | |
Product purchases | | | — | | | | — | | | | 83 | | | | 8,300 | | | | 590 | | | | — | | | | 8,973 | |
Operations and maintenance expense | | | — | | | | 6,131 | | | | 2,313 | | | | 517 | | | | 750 | | | | — | | | | 9,711 | |
General and administrative expense | | | — | | | | — | | | | — | | | | — | | | | — | | | | 6,738 | | | | 6,738 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA | | $ | — | | | $ | 27,813 | | | $ | 4,468 | | | $ | 780 | | | $ | 1,988 | | | $ | (6,738 | ) | | $ | 28,311 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Goodwill | | $ | — | | | $ | — | | | $ | 76,767 | | | $ | 16,861 | | | $ | — | | | $ | — | | | $ | 93,628 | |
Total assets | | $ | 415,774 | | | $ | 539,073 | | | $ | 307,765 | | | $ | 77,960 | | | $ | 83,009 | | | $ | 17,282 | | | $ | 1,440,863 | |
Capital expenditures | | $ | — | | | $ | 1,866 | | | $ | 8,146 | | | $ | 1,288 | | | $ | 1,447 | | | $ | 142 | | | $ | 12,889 | |
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13. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The CMLP Credit Facility and our Senior Notes are fully and unconditionally guaranteed, jointly and severally, by CMLP’s present and future direct and indirect 100% owned subsidiaries (the Guarantor Subsidiaries), except for CMM and its consolidated subsidiaries (the Non-Guarantor Subsidiaries). CMLP (Issuer) issued the Senior Notes together with Crestwood Midstream Finance Corporation (Co-Issuer). The Co-Issuer is our 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of our Senior Notes. Accordingly, it has no ability to service obligations on our debt securities.
The following reflects condensed consolidating financial information of the Issuer, Co-Issuer, Guarantor Subsidiaries, Non-Guarantor Subsidiaries, eliminating entries to combine the entities and our consolidated results as of March 31, 2013 and December 31, 2012 and for the three months ended March 31, 2013 and 2012.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, 2013 | |
| | Issuer | | | Co-Issuer | | | Guarantor Subsidiaries | | | Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
Operating revenues | | $ | — | | | $ | — | | | $ | 58,142 | | | $ | 14,274 | | | $ | — | | | $ | 72,416 | |
Operating expenses | | | 192 | | | | — | | | | 43,106 | | | | 8,372 | | | | — | | | | 51,670 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Operating income (loss) | | | (192 | ) | | | — | | | | 15,036 | | | | 5,902 | | | | — | | | | 20,746 | |
Interest and debt expense | | | (10,105 | ) | | | — | | | | (72 | ) | | | (1,273 | ) | | | — | | | | (11,450 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income (loss) before income tax | | | (10,297 | ) | | | — | | | | 14,964 | | | | 4,629 | | | | — | | | | 9,296 | |
Income tax expense | | | — | | | | — | | | | 338 | | | | — | | | | — | | | | 338 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income (loss) before earnings from consolidated subsidiaries | | | (10,297 | ) | | | — | | | | 14,626 | | | | 4,629 | | | | — | | | | 8,958 | |
Earnings (loss) from consolidated subsidiaries | | | 19,255 | | | | — | | | | — | | | | — | | | | (19,255 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net income (loss) | | | 8,958 | | | | — | | | | 14,626 | | | | 4,629 | | | | (19,255 | ) | | | 8,958 | |
General partner’s interest in net income | | | 5,201 | | | | — | | | | — | | | | — | | | | — | | | | 5,201 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Limited partner’s interest in net income (loss) | | $ | 3,757 | | | $ | — | | | $ | 14,626 | | | $ | 4,629 | | | $ | (19,255 | ) | | $ | 3,757 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | For the Three Months Ended March 31, 2012 | |
| | Issuer | | | Co-Issuer | | | Guarantor Subsidiaries | | | Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
Operating revenues | | $ | — | | | $ | — | | | $ | 53,733 | | | $ | — | | | $ | — | | | $ | 53,733 | |
Operating expenses | | | 39 | | | | — | | | | 36,029 | | | | — | | | | — | | | | 36,068 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Operating income (loss) | | | (39 | ) | | | — | | | | 17,704 | | | | — | | | | — | | | | 17,665 | |
Interest and debt expense | | | (7,507 | ) | | | — | | | | (50 | ) | | | — | | | | — | | | | (7,557 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income (loss) before income tax | | | (7,546 | ) | | | — | | | | 17,654 | | | | — | | | | — | | | | 10,108 | |
Income tax expense | | | — | | | | — | | | | 303 | | | | — | | | | — | | | | 303 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income (loss) before earnings from consolidated subsidiaries | | | (7,546 | ) | | | — | | | | 17,351 | | | | — | | | | — | | | | 9,805 | |
Earnings (loss) from consolidated subsidiaries | | | 17,351 | | | | — | | | | — | | | | — | | | | (17,351 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net income (loss) | | | 9,805 | | | | — | | | | 17,351 | | | | — | | | | (17,351 | ) | | | 9,805 | |
General partner’s interest in net income | | | 3,368 | | | | — | | | | — | | | | — | | | | — | | | | 3,368 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Limited partner’s interest in net income (loss) | | $ | 6,437 | | | $ | — | | | $ | 17,351 | | | $ | — | | | | (17,351 | ) | | $ | 6,437 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
19
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | As of March 31, 2013 | |
| | Issuer | | | Co-Issuer | | | Guarantor Subsidiaries | | | Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | | | | | | | | | | |
Current assets | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 9 | | | $ | — | | | $ | — | | | $ | 26 | | | $ | — | | | $ | 35 | |
Accounts receivable | | | 577 | | | | — | | | | 17,169 | | | | 6,571 | | | | — | | | | 24,317 | |
Accounts receivable—related party | | | 434,336 | | | | 1 | | | | 21,001 | | | | — | | | | (431,782 | ) | | | 23,556 | |
Insurance receivable | | | — | | | | — | | | | 3,014 | | | | — | | | | — | | | | 3,014 | |
Prepaid expenses and other | | | 430 | | | | — | | | | 823 | | | | 4 | | | | — | | | | 1,257 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total current assets | | | 435,352 | | | | 1 | | | | 42,007 | | | | 6,601 | | | | (431,782 | ) | | | 52,179 | |
Investment in consolidated affiliates | | | 1,029,572 | | | | — | | | | — | | | | — | | | | (1,029,572 | ) | | | — | |
Property, plant and equipment – net | | | 3,292 | | | | — | | | | 781,358 | | | | 166,239 | | | | — | | | | 950,889 | |
Intangible assets – net | | | — | | | | — | | | | 159,975 | | | | 335,885 | | | | — | | | | 495,860 | |
Goodwill | | | — | | | | — | | | | 95,031 | | | | — | | | | — | | | | 95,031 | |
Deferred financing costs, net | | | 16,411 | | | | — | | | | — | | | | 5,062 | | | | — | | | | 21,473 | |
Other assets | | | 220 | | | | — | | | | 1,155 | | | | — | | | | — | | | | 1,375 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 1,484,847 | | | $ | 1 | | | $ | 1,079,526 | | | $ | 513,787 | | | $ | (1,461,354 | ) | | $ | 1,616,807 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY | | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Accrued additions to property, plant and equipment | | $ | 8 | | | $ | — | | | $ | 2,007 | | | $ | 5,611 | | | $ | — | | | $ | 7,626 | |
Capital leases | | | 415 | | | | — | | | | 3,361 | | | | — | | | | — | | | | 3,776 | |
Deferred revenue | | | — | | | | — | | | | — | | | | 2,426 | | | | — | | | | 2,426 | |
Accounts payable—related party | | | 1,344 | | | | — | | | | 433,963 | | | | 114 | | | | (431,782 | ) | | | 3,639 | |
Accounts payable, accrued expenses and other liabilities | | | 20,097 | | | | — | | | | 8,251 | | | | 9,339 | | | | — | | | | 37,687 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | 21,864 | | | | — | | | | 447,582 | | | | 17,490 | | | | (431,782 | ) | | | 55,154 | |
Long-term debt | | | 644,602 | | | | — | | | | — | | | | 83,000 | | | | — | | | | 727,602 | |
Long-term capital leases | | | 866 | | | | — | | | | 1,448 | | | | — | | | | — | | | | 2,314 | |
Asset retirement obligations | | | — | | | | — | | | | 13,374 | | | | 848 | | | | — | | | | 14,222 | |
Partners’/members’ equity | | | 817,515 | | | | 1 | | | | 617,122 | | | | 412,449 | | | | (1,029,572 | ) | | | 817,515 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total liabilities and partners’ capital/members’ equity | | $ | 1,484,847 | | | $ | 1 | | | $ | 1,079,526 | | | $ | 513,787 | | | $ | (1,461,354 | ) | | $ | 1,616,807 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
20
| | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | As of December 31, 2012 | |
| | Issuer | | | Co-Issuer | | | Guarantor Subsidiaries | | | Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | | | | | | | | | | |
Current assets | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 21 | | | $ | — | | | $ | — | | | $ | 90 | | | $ | — | | | $ | 111 | |
Accounts receivable | | | 608 | | | | — | | | | 14,515 | | | | 6,513 | | | | — | | | | 21,636 | |
Accounts receivable—related party | | | 366,405 | | | | 1 | | | | 22,587 | | | | — | | | | (365,238 | ) | | | 23,755 | |
Insurance receivable | | | — | | | | — | | | | 2,920 | | | | — | | | | — | | | | 2,920 | |
Prepaid expenses and other | | | 584 | | | | — | | | | 1,357 | | | | — | | | | — | | | | 1,941 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total current assets | | | 367,618 | | | | 1 | | | | 41,379 | | | | 6,603 | | | | (365,238 | ) | | | 50,363 | |
Investment in consolidated affiliates | | | 1,041,936 | | | | — | | | | — | | | | — | | | | (1,041,936 | ) | | | — | |
Property, plant and equipment – net | | | 8,519 | | | | — | | | | 775,852 | | | | 155,475 | | | | — | | | | 939,846 | |
Intangible assets – net | | | — | | | | — | | | | 163,021 | | | | 338,359 | | | | — | | | | 501,380 | |
Goodwill | | | — | | | | — | | | | 95,031 | | | | — | | | | — | | | | 95,031 | |
Deferred financing costs, net | | | 17,149 | | | | — | | | | — | | | | 5,379 | | | | — | | | | 22,528 | |
Other assets | | | 20 | | | | — | | | | 1,301 | | | | — | | | | — | | | | 1,321 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 1,435,242 | | | $ | 1 | | | $ | 1,076,584 | | | $ | 505,816 | | | $ | (1,407,174 | ) | | $ | 1,610,469 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY | | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Accrued additions to property, plant and equipment | | $ | — | | | $ | — | | | $ | 3,829 | | | $ | 5,384 | | | $ | — | | | $ | 9,213 | |
Capital leases | | | 429 | | | | — | | | | 3,433 | | | | — | | | | — | | | | 3,862 | |
Deferred revenue | | | — | | | | — | | | | — | | | | 2,634 | | | | — | | | | 2,634 | |
Accounts payable—related party | | | 536 | | | | — | | | | 367,682 | | | | 108 | | | | (365,238 | ) | | | 3,088 | |
Accounts payable, accrued expenses and other liabilities | | | 15,547 | | | | — | | | | 11,876 | | | | 2,294 | | | | — | | | | 29,717 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | 16,512 | | | | — | | | | 386,820 | | | | 10,420 | | | | (365,238 | ) | | | 48,514 | |
Long-term debt | | | 558,161 | | | | — | | | | — | | | | 127,000 | | | | — | | | | 685,161 | |
Long-term capital leases | | | 960 | | | | — | | | | 2,201 | | | | — | | | | — | | | | 3,161 | |
Asset retirement obligations | | | — | | | | — | | | | 13,188 | | | | 836 | | | | — | | | | 14,024 | |
Partners’/members’ equity | | | 859,609 | | | | 1 | | | | 674,375 | | | | 367,560 | | | | (1,041,936 | ) | | | 859,609 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total liabilities and partners’ capital/members’ equity | | $ | 1,435,242 | | | $ | 1 | | | $ | 1,076,584 | | | $ | 505,816 | | | $ | (1,407,174 | ) | | $ | 1,610,469 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
21
| | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, 2013 | |
| | Issuer | | | Co-Issuer | | | Guarantor Subsidiaries | | | Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
Net cash provided by (used in) operating activities | | $ | (5,784 | ) | | $ | — | | | $ | 33,857 | | | $ | 15,701 | | | $ | (9,740 | ) | | $ | 34,034 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Investing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Capital expenditures | | | (341 | ) | | | — | | | | (11,907 | ) | | | (12,025 | ) | | | — | | | | (24,273 | ) |
Capital contribution to consolidated affiliate | | | (50,000 | ) | | | — | | | | — | | | | — | | | | 50,000 | | | | — | |
Change in advances to affiliates, net | | | 20,398 | | | | — | | | | — | | | | — | | | | (20,398 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used in) investing activities | | | (29,943 | ) | | | — | | | | (11,907 | ) | | | (12,025 | ) | | | 29,602 | | | | (24,273 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Financing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Proceeds from credit facilities | | | 183,500 | | | | — | | | | — | | | | 16,000 | | | | — | | | | 199,500 | |
Repayments of credit facilities | | | (97,000 | ) | | | — | | | | — | | | | (60,000 | ) | | | — | | | | (157,000 | ) |
Payments on capital leases | | | (107 | ) | | | — | | | | (898 | ) | | | — | | | | — | | | | (1,005 | ) |
Deferred financing costs paid | | | (82 | ) | | | — | | | | — | | | | — | | | | — | | | | (82 | ) |
Proceeds from issuance of common units, net | | | 103,500 | | | | — | | | | — | | | | — | | | | — | | | | 103,500 | |
Contributions received | | | — | | | | — | | | | — | | | | 50,000 | | | | (50,000 | ) | | | — | |
Distributions to General Partner for additional interest in CMM | | | (129,000 | ) | | | — | | | | — | | | | — | | | | — | | | | (129,000 | ) |
Distributions paid | | | (25,096 | ) | | | | | | | | | | | (9,740 | ) | | | 9,740 | | | | (25,096 | ) |
Change in advances from affiliates, net | | | — | | | | — | | | | (20,398 | ) | | | — | | | | 20,398 | | | | — | |
Taxes paid for equity-based compensation vesting | | | — | | | | — | | | | (654 | ) | | | — | | | | — | | | | (654 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used in) financing activities | | | 35,715 | | | | — | | | | (21,950 | ) | | | (3,740 | ) | | | (19,862 | ) | | | (9,837 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in cash and cash equivalents | | | (12 | ) | | | — | | | | — | | | | (64 | ) | | | — | | | | (76 | ) |
Cash and cash equivalents at beginning of period | | | 21 | | | | — | | | | — | | | | 90 | | | | — | | | | 111 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 9 | | | $ | — | | | $ | — | | | $ | 26 | | | $ | — | | | $ | 35 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
22
| | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, 2012 | |
| | Issuer | | | Co-Issuer | | | Guarantor Subsidiaries | | | Non-Guarantor Subsidiaries | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
Net cash provided by (used in) operating activities | | $ | (4,434 | ) | | $ | — | | | $ | 26,587 | | | $ | — | | | $ | — | | | $ | 22,153 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Investing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Acquisitions, net of cash acquired | | | — | | | | — | | | | — | | | | (376,805 | ) | | | — | | | | (376,805 | ) |
Capital expenditures | | | (142 | ) | | | — | | | | (12,747 | ) | | | — | | | | — | | | | (12,889 | ) |
Acquisition of interests in CMM | | | (131,250 | ) | | | — | | | | — | | | | — | | | | 131,250 | | | | — | |
Change in advances to affiliates, net | | | 12,772 | | | | — | | | | — | | | | — | | | | (12,772 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used in) investing activities | | | (118,620 | ) | | | — | | | | (12,747 | ) | | | (376,805 | ) | | | 118,478 | | | | (389,694 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Financing activities: | | | | | | | | | | | | | | | | | | | | | | | | |
Proceeds from credit facilities | | | 182,000 | | | | — | | | | — | | | | 10,000 | | | | — | | | | 192,000 | |
Repayments of credit facilities | | | (141,250 | ) | | | — | | | | — | | | | — | | | | — | | | | (141,250 | ) |
Payments on capital leases | | | — | | | | — | | | | (666 | ) | | | — | | | | — | | | | (666 | ) |
Deferred financing costs paid | | | — | | | | — | | | | — | | | | (6,314 | ) | | | — | | | | (6,314 | ) |
Proceeds from issuance of common units, net | | | 103,050 | | | | — | | | | — | | | | — | | | | — | | | | 103,050 | |
Contributions received | | | — | | | | — | | | | — | | | | 375,000 | | | | (131,250 | ) | | | 243,750 | |
Distributions paid | | | (20,729 | ) | | | — | | | | — | | | | — | | | | — | | | | (20,729 | ) |
Change in advances from affiliate, net | | | — | | | | — | | | | (12,772 | ) | | | — | | | | 12,772 | | | | — | |
Taxes paid for equity-based compensation vesting | | | — | | | | — | | | | (402 | ) | | | — | | | | — | | | | (402 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used in) financing activities | | | 123,071 | | | | — | | | | (13,840 | ) | | | 378,686 | | | | (118,478 | ) | | | 369,439 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in cash and cash equivalents | | | 17 | | | | — | | | | — | | | | 1,881 | | | | — | | | | 1,898 | |
Cash and cash equivalents at beginning of period | | | 797 | | | | — | | | | — | | | | — | | | | — | | | | 797 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 814 | | | $ | — | | | $ | — | | | $ | 1,881 | | | $ | — | | | $ | 2,695 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
14. SUBSEQUENT EVENT
On May 5, 2013, Crestwood Holdings signed definitive agreements under which it will acquire the general partner of Inergy, L.P. (NRGY) and will then contribute its ownership of our general partner and incentive distribution rights to NRGY in exchange for NRGY common units. Separately, we entered into a definitive merger agreement under which we would be merged with a subsidiary of Inergy Midstream, L.P. (NRGM) in a merger in which our unitholders would receive 1.07 units of NRGM for each unit of CMLP they own. Additionally, under the merger agreement, our unitholders (other than Crestwood Holdings) would receive a one-time approximately $35 million cash payment at closing of the merger transaction, or $1.03 per unit, $25 million of which would be payable by NRGM and approximately $10 million of which would be payable by Crestwood Holdings. The merger of NRGM and CMLP is conditioned upon the closing of Crestwood Holdings’ acquisition of NRGY’s general partner interest, the closing of the contribution of the CMLP general partner and incentive distribution rights to NRGY, the approval of the holders of a majority of the limited partner interests of CMLP and other customary closing conditions.
23
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
On May 5, 2013, Crestwood Holdings signed definitive agreements under which it will acquire the general partner of Inergy, L.P. (NRGY) and will then contribute its ownership of our general partner and incentive distribution rights to NRGY in exchange for NRGY common units. Separately, we entered into a definitive merger agreement under which we would be merged with a subsidiary of Inergy Midstream, L.P. (NRGM) in a merger in which our unitholders would receive 1.07 units of NRGM for each unit of CMLP they own. Additionally, under the merger agreement, our unitholders (other than Crestwood Holdings) would receive a one-time approximately $35 million cash payment at closing of the merger transaction, or $1.03 per unit, $25 million of which would be payable by NRGM and approximately $10 million of which would be payable by Crestwood Holdings. The merger of NRGM and CMLP is conditioned upon the closing of Crestwood Holdings’ acquisition of NRGY’s general partner interest, the closing of the contribution of the CMLP general partner and incentive distribution rights to NRGY, the approval of the holders of a majority of the limited partner interests of CMLP and other customary closing conditions.
Overview and Performance Metrics
We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing producers in the Marcellus Shale in northern West Virginia, the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Avalon Shale/Bone Spring in southeastern New Mexico and the Haynesville/Bossier Shale in western Louisiana. We provide midstream services to various producers that focus on developing unconventional resources across the United States. Our largest producer is Quicksilver Resources Inc. (Quicksilver). For the three months ended March 31, 2013 and 2012, services provided to Quicksilver accounted for approximately 35% and 57% of our total revenues.
We conduct all of our operations in the midstream sector in eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Marcellus, Barnett, Fayetteville and Granite Wash. Our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States.
The results of our operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. Under our fixed-fee contracts, we do not take title to the natural gas or associated NGLs. For the three months ended March 31, 2013, approximately 98% of our gross margin, which we define as total revenue less product purchases, is derived from fixed-fee service contracts, which minimizes our commodity price exposure and provides us with less volatile operating performance and cash flows. Under our percent-of-proceeds contracts, we take title to the residue gas, NGLs and condensate and remit a portion of the sale proceeds to the producer based on prevailing commodity prices. For the three months ended March 31, 2013, the net revenues from percent-of-proceeds contracts accounted for approximately 2% of our gross margin.
Although we do not have significant direct commodity price exposure, lower natural gas prices could have a potential negative impact on the pace of drilling in dry gas areas – such as areas in the Barnett Shale (gathered by the Alliance and Lake Arlington Systems), the Fayetteville Systems and the Sabine System (part of the Haynesville/Bossier Shale). We operate five systems located in basins that include NGL rich gas shale plays: (i) the Cowtown System in the Barnett Shale; (ii) the Granite Wash System; (iii) the Las Animas Systems in the Avalon Shale; and (iv) two systems in the Marcellus segment. For the three months ended March 31, 2013, our systems located in NGL rich gas basins contributed approximately 70% of our total revenues and 63% of our total gathering volumes. A prolonged decrease in the commodity price environment could result in our customers reducing their production volumes which would result in a decrease in our revenues.
Our management uses a variety of financial and operational measures to analyze our performance. We view these measures as important factors affecting our profitability and unitholder value and therefore we review them monthly for consistency and to identify trends in our operations. These performance measures are outlined below.
Volume— We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. We routinely monitor producer activity in the areas we serve to identify new supply opportunities. Our ability to achieve these objectives is impacted by:
| • | | the level of successful drilling and production activity in areas where our systems are located; |
| • | | our ability to compete with other midstream companies for production volumes; and |
| • | | our pursuit of new acquisition opportunities. |
Operations and Maintenance Expenses — We consider operations and maintenance expenses in evaluating the performance of our operations. These expenses are comprised primarily of labor, parts and materials, insurance, taxes other than income taxes, repair and maintenance costs, utilities and contract services. Our ability to manage operations and maintenance expenses has a significant impact on our profitability and ability to pay distributions.
EBITDA and Adjusted EBITDA — We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA and Adjusted EBITDA are not measures calculated in accordance with accounting principles generally accepted in the United States of America (GAAP), as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. In addition, Adjusted EBITDA considers the impact of certain significant items, such as third party costs incurred related to potential and completed acquisitions and other transactions
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identified in a specific reporting period. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.
See our reconciliation of Net Income to EBITDA and Adjusted EBITDA inResults of Operations below.
Current Year Highlights
Below is a discussion of events that highlight our core business and financing activities.
Operational and Industry Highlights
Shale gas production in the United States has grown rapidly in recent years as the natural gas industry has improved drilling and extraction methods while increasing exploration efforts. The United States has a wide distribution of shale formations containing vast resources of natural gas, NGLs and oil. Led by the rapid development of the Barnett Shale in Texas, shale gas activity has expanded into other areas such as the Marcellus, Fayetteville and Haynesville/Bossier shale plays.
Growth through Diversification —Our operating results reflect our ability to diversify our shale play portfolio and increase volumes not only through our base business located in the Barnett Shale, but also through strategic acquisitions in a number of attractive shale plays in the United States. We believe that our experience and market position will allow us to realize significant ongoing growth opportunities by developing new greenfield projects in NGL and oil plays in areas with limited or constrained infrastructure which offer attractive returns on investment and seeking bolt-on acquisitions that provide operating synergies and allow for the development of our business in rich gas infrastructure plays similar to our acquisitions during 2012. Our acquisition strategy includes diversifying and extending our geographic, customer and business profile and developing organic growth opportunities along the midstream value chain.
In December 2012, Crestwood Marcellus Midstream LLC (CMM) completed the acquisition of natural gas compression and dehydration assets from Enerven Compression, LLC (Enerven) for approximately $95 million expanding the value chain and range of services we provide in the high growth Marcellus Shale. The acquisition included four compression stations connected to CMM’s low pressure gathering systems and a five-year minimum term compression services agreement with Antero Resources Appalachian Corporation (Antero) which expires in 2018. In addition, CMM provides compression services to Antero under a 20-year Gas Gathering and Compression Agreement (GGA), which became effective in January 2012. We believe the Enerven assets will provide an excellent opportunity for organic growth as gathering infrastructure in the Marcellus rich gas region continues to be built at a rapid pace.
Our systems gathered 975 MMcf/d during the three months ended March 31, 2013, which is an increase of 59% from 611 MMcf/d gathered during the same period in 2012. During the three months ended March 31, 2013, our Marcellus systems’ compression volumes were 270 MMcf/d. Additionally, our processed volumes were 224 MMcf/d for the three months ended March 31, 2013, an increase of 52% compared to the same period in 2012. The increase in volumes resulted in a 35% increase in our overall revenues for the three months ended March 31, 2013 compared to the same period in 2012.
Distribution Growth — For the three months ended March 31, 2013, we declared a distribution of $0.51 per limited partner unit compared to $0.50 per limited partner unit during the same period in 2012.
Antero Agreements
In March 2013, CMM entered into a seven year agreement with Antero to provide natural gas compression services on developing rich gas acreage in Doddridge County, West Virginia (Compression Services Agreement). The Compression Services Agreement provides for the construction and operation of compressor stations on Antero’s Western Area acreage (Western Area) which is not dedicated to us under our existing GGA which covers the Eastern Area of Dedication (Eastern AOD). We will provide fixed-fee compression services to Antero under the Compression Services Agreement, which provides for minimum fees based on the capacity of the compressor stations constructed under the agreement. The Compression Services Agreement does not impact our seven year right of first offer to acquire midstream infrastructure from Antero in the Western Area and is in addition to the previously announced construction of two compressor stations we are constructing in the Eastern AOD during 2013.
The initial compressor station to be constructed under the Compression Services Agreement will be a two phase project adding approximately 120 MMcf/d of flow capacity at an estimated cost of $35 million. Phase I will add 55 MMcf/d of capacity and is expected to be in service during the third quarter of 2013. Phase II will add 65 MMcf/d and is expected to be in service by the end of 2013. The Compression Services Agreement also provides for the construction of additional compression facilities if agreed to by Antero and CMM in the future. During the first quarter of 2013, Antero and CMM entered into a reimbursement agreement to perform preliminary work on the construction of a second potential compressor station under the Compression Services Agreement.
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Business Development Activities
On April 25, 2013, we entered into an amended binding letter of intent with RKI Exploration and Production, LLC (RKI), an affiliate of our General Partner, to purchase RKI’s 50% interest in a gathering system located in the Powder River Basin Niobrara play. This transaction is subject to the completion of definitive agreements and the approval by our General Partner’s Board of Directors and Conflicts Committee. We expect to close this transaction during the second quarter of 2013. During the three months ended March 31, 2013, we have incurred less than $1 million of costs related to this transaction.
Financing Activities
Equity Offering
On March 22, 2013, we completed a public offering of 4,500,000 common units, representing limited partner interests in us at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. We granted the underwriters a 30 day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013, providing net proceeds of approximately $15.5 million. The net proceeds from these transactions were used to reduce indebtedness under each of the CMM and CMLP Credit Facilities. In connection with the issuance of the common units, our General Partner did not make an additional capital contribution to us resulting in a reduction in their general partner interest in us to approximately 1.8%.
Results of Operations
Three Months Ended March 31, 2013 Compared with Three Months Ended March 31, 2012
The following table summarizes our results of operations (In thousands):
| | | | | | | | |
| | Three Months Ended March 31, | |
| | 2013 | | | 2012 | |
Total operating revenues | | $ | 72,416 | | | $ | 53,733 | |
Product purchases | | | 13,505 | | | | 8,973 | |
Operations and maintenance expense | | | 13,016 | | | | 9,711 | |
General and administrative expense | | | 7,789 | | | | 6,738 | |
Depreciation, amortization and accretion expense | | | 17,360 | | | | 10,646 | |
| | | | | | | | |
Operating income | | | 20,746 | | | | 17,665 | |
| | |
Interest and debt expense | | | 11,450 | | | | 7,557 | |
Income tax expense | | | 338 | | | | 303 | |
| | | | | | | | |
Net income | | $ | 8,958 | | | $ | 9,805 | |
Add: | | | | | | | | |
Interest and debt expense | | | 11,450 | | | | 7,557 | |
Income tax expense | | | 338 | | | | 303 | |
Depreciation, amortization and accretion expense | | | 17,360 | | | | 10,646 | |
| | | | | | | | |
EBITDA | | $ | 38,106 | | | $ | 28,311 | |
| | |
Expenses associated with significant items | | | 718 | | | | 51 | |
| | | | | | | | |
Adjusted EBITDA | | $ | 38,824 | | | $ | 28,362 | |
| | | | | | | | |
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EBITDA in the table above includes operating results from our Marcellus, Barnett, Fayetteville and Granite Wash segments and other operations, and general and administrative expenses. The following table summarizes the results of our Barnett, Marcellus, Fayetteville and Granite Wash segments and other operations (In thousands):
| | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three Months Ended March 31, 2013 | |
| | Marcellus | | | Barnett | | | Fayetteville | | | Granite Wash | | | Other | | | Total | |
Gathering revenues | | $ | 10,348 | | | $ | 24,342 | | | $ | 6,959 | | | $ | 514 | | | $ | 1,740 | | | $ | 43,903 | |
Processing revenues | | | — | | | | 9,728 | | | | — | | | | 2 | | | | — | | | | 9,730 | |
Compression revenues | | | 3,926 | | | | — | | | | — | | | | — | | | | | | | | 3,926 | |
Product sales | | | — | | | | 480 | | | | 294 | | | | 13,333 | | | | 750 | | | | 14,857 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total operating revenues | | $ | 14,274 | | | $ | 34,550 | | | $ | 7,253 | | | $ | 13,849 | | | $ | 2,490 | | | $ | 72,416 | |
Product purchases | | | — | | | | 255 | | | | 293 | | | | 12,207 | | | | 750 | | | | 13,505 | |
Operations and maintenance expense | | | 2,397 | | | | 7,255 | | | | 2,134 | | | | 608 | | | | 622 | | | | 13,016 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA | | $ | 11,877 | | | $ | 27,040 | | | $ | 4,826 | | | $ | 1,034 | | | $ | 1,118 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Gathering volumes (in MMcf) | | | 33,909 | | | | 40,373 | | | | 7,445 | | | | 2,035 | | | | 3,939 | | | | 87,701 | |
Processing volumes (in MMcf) | | | — | | | | 18,322 | | | | — | | | | 1,845 | | | | — | | | | 20,167 | |
Compression volumes (in MMcf) | | | 24,275 | | | | — | | | | — | | | | — | | | | — | | | | 24,275 | |
| |
| | For the Three Months Ended March 31, 2012 | |
| | Marcellus | | | Barnett | | | Fayetteville | | | Granite Wash | | | Other | | | Total | |
Gathering revenues | | $ | — | | | $ | 26,060 | | | $ | 6,766 | | | $ | 138 | | | $ | 2,719 | | | $ | 35,683 | |
Processing revenues | | | — | | | | 7,884 | | | | — | | | | 83 | | | | — | | | | 7,967 | |
Product sales | | | — | | | | — | | | | 98 | | | | 9,376 | | | | 609 | | | | 10,083 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total operating revenues | | $ | — | | | $ | 33,944 | | | $ | 6,864 | | | $ | 9,597 | | | $ | 3,328 | | | $ | 53,733 | |
Product purchases | | | — | | | | — | | | | 83 | | | | 8,300 | | | | 590 | | | | 8,973 | |
Operations and maintenance expense | | | — | | | | 6,131 | | | | 2,313 | | | | 517 | | | | 750 | | | | 9,711 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA | | $ | — | | | $ | 27,813 | | | $ | 4,468 | | | $ | 780 | | | $ | 1,988 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Gathering volumes (in MMcf) | | | — | | | | 40,654 | | | | 7,535 | | | | 1,352 | | | | 6,063 | | | | 55,604 | |
Processing volumes (in MMcf) | | | — | | | | 12,057 | | | | — | | | | 1,345 | | | | — | | | | 13,402 | |
EBITDA and Adjusted EBITDA —EBITDA for the three months ended March 31, 2013 was approximately $38 million, an increase of approximately $10 million compared to same period in 2012. In the same manner, Adjusted EBITDA for the three months ended was approximately $39 million, an increase of approximately $11 million compared to the same period in 2012. Adjusted EBITDA considers expenses for evaluating certain transaction opportunities, which were approximately $0.7 million and less than $0.1 million for the three months ended March 31, 2013 and 2012.
Below is a discussion of the factors that impacted EBITDA by segment for the three months ended March 31, 2013 compared to the same period in 2012. For our Marcellus segment, our discussion compares the three months ended March 31, 2013 to the three months ended December 31, 2012, as there were no material operations for the quarter ended March 31, 2012.
Marcellus:
EBITDA for our Marcellus segment was approximately $12 million for the three months ended March 31, 2013. On March 26, 2012, CMM acquired gathering assets from Antero. The impact of this acquisition was not material to our results of operations for the three months ended March 31, 2012.
Revenues and Volumes —Revenues in our Marcellus segment increased by approximately $4 million during the three months ended March 31, 2013 compared to the three months ended December 31, 2012, primarily due to the increase in compression volumes as a result of CMM’s acquisition of E. Marcellus Asset Company, LLC (EMAC) from Enerven in December 2012 for approximately $95 million. The acquisition of these natural gas compression and dehydration assets will expand the value chain and range of services we provide in the high growth Marcellus Shale. The acquisition included four compression stations connected to CMM’s low pressure gathering systems and a five-year minimum term compression services agreement with Antero which expires in 2018. During the three months ended March 31, 2013, our compression volumes under this agreement were 270 MMcf/d.
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In addition to the increase in compression revenues, for the three months ended March 31, 2013, we gathered 377 MMcf/d in our Marcellus segment compared to 360 MMcf/d for the three months ended December 31, 2012. During the three months ended March 31, 2013, we connected 15 new wells in our Marcellus segment which contributed to the increase in gathering volumes and revenues. Partially offsetting the increase in volumes were lower gathering volumes related to damage at our Tichenal unit which occurred in December 2012. The Tichenal unit was placed in service on March 18, 2013 and is expected to increase our gathering and compression volumes in our Marcellus segment for the remainder of 2013.
Operations and Maintenance Expense — Operations and maintenance expenses in our Marcellus segment increased by approximately $1 million for the three months ended March 31, 2013 when compared to the three months ended December 31, 2012. The increase in operations and maintenance expenses was primarily due to the acquisition of the Enerven assets discussed above.
Barnett:
For the three months ended March 31, 2013, our Barnett segment’s EBITDA was approximately $0.8 million lower than the same period in 2012, primarily due to lower gathering revenues.
Revenues and Volumes —Revenues in our Barnett segment decreased by approximately $0.6 million during the three months ended March 31, 2013 compared to the same period in 2012, primarily due to lower dry gas gathering volumes. The decrease in gathering volumes primarily related to reduced production from Quicksilver’s existing wells. In addition, Quicksilver did not connect any new wells during the three months ended March 31, 2013. Partially offsetting the decline in Quicksilver volumes were three new wells we connected from other producers during the three months ended March 31, 2013.
Also, partially offsetting the decline in gathering revenues and volumes discussed above was an increase in gathering and processing revenues due to the Devon Acquisition, which was completed on August 24, 2012. During the three months ended March 31, 2013, the acquired assets generated approximately $7 million of gathering and processing revenues for our Barnett segment.
Operations and Maintenance Expense — Operations and maintenance expenses in our Barnett segment increased by approximately $1 million for the three months ended March 31, 2013 when compared to the same period in 2012 primarily due to the operation of the West Johnson County system acquired in the Devon Acquisition during August 2012. During the three months ended March 31, 2013, operations and maintenance expenses related to the West Johnson County system were approximately $1 million, which reflects the full synergies of the integration of the system with our Cowtown system completed in December 2012. As a result of the integration, the West Johnson County plant that was acquired in the Devon Acquisition is now available for redeployment or sale.
Fayetteville:
Our Fayetteville segment EBITDA increased approximately $0.4 million during the three months ended March 31, 2013 compared with the same period in 2012, primarily due to higher revenues and volumes.
Revenues and Volumes —During the three months ended March 31, 2013, revenues in our Fayetteville segment increased by approximately $0.4 million compared to the same period in 2012 primarily due to an increase in volumes due to new wells connected during 2012. For the remainder of 2013, BHP Billiton Petroleum plans to connect additional wells to our system which will contribute to an increase in revenues and volumes in our Fayetteville segment.
Operations and Maintenance Expense –Operations and maintenance expenses in our Fayetteville segment for the three months ended March 31, 2013 were relatively flat compared to the same period in 2012.
Granite Wash:
During the three months ended March 31, 2013, our Granite Wash segment’s EBITDA was approximately $0.3 million higher than the same period in 2012 primarily due to higher product sales margin.
Revenues/Margin and Volumes—For the three months ended March 31, 2013, Granite Wash’s EBITDA increased compared to the same period in 2012, due to higher margins earned on our percent-of-proceeds contracts, which primarily resulted from higher NGL and natural gas prices experienced during the three months ended March 31, 2013. In addition, we also experienced higher gathering revenues due to a gathering and processing agreement entered during the third quarter of 2012 with Sabine Oil and Gas LLC and its affiliates, an affiliate of our General Partner.
Operations and Maintenance Expense—For the three months ended March 31, 2013 compared to the same period in 2012, operations and maintenance expenses in our Granite Wash segment were relatively flat compared to the same period in 2012.
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Other:
Our other operations include our assets in the Haynesville/Bossier Shale (Sabine System) and our assets in the Avalon Shale (Las Animas System). For the three months ended March 31, 2013, our other operations’ EBITDA decreased by approximately $1 million compared to the same period in 2012, which primarily relates to the operations of our Sabine System.
Revenues and Volumes—The Sabine System had 36 MMcf/d in gathered volumes for the three months ended March 31, 2013 compared to 58 MMcf/d during the same period in 2012. The decrease in volumes was primarily due to lower volumes transported below the minimum quantity under our gathering contract with a subsidiary of US Infrastructure Holdings, LLC (USI). Although we experienced a decrease in volumes under this contract, our EBITDA was not unfavorably impacted due to the minimum volume commitment under the contract. Our contract with USI expires in May 2013. Our gathering volumes from other producers on our Sabine System was lower for the three months ended March 31, 2013 compared to the same period in 2012, which also contributed to the $1 million decrease in revenues period over period. EBITDA related to our Las Animas System remained relatively unchanged for the three months ended March 31, 2013, compared to the same period in 2012.
Operations and Maintenance Expense —Operations and maintenance expenses remained relatively flat during the three months ended March 31, 2013 compared to the same period in 2012.
Below is a discussion of items impacting our EBITDA that are not allocated to our segments.
General and Administrative Expenses — During the three months ended March 31, 2013, general and administrative expenses increased by approximately $1 million when compared to the same period in 2012. General and administrative expenses include costs related to legal and other consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred approximately $0.7 million of these costs during the three months ended March 31, 2013 which was the primary driver for the increase in general and administrative expense compared to March 31, 2012.
Also impacting our general and administrative expenses for the three months ended March 31, 2013 were increases in payroll and related benefit costs, which reflects the increased scope of our business operations compared to the same period in 2012.
Items not affecting EBITDA include the following:
Depreciation, Amortization and Accretion Expense —We have experienced increases in our depreciation, amortization and accretion expense primarily due to assets acquired during 2012. For a further discussion of our asset acquisitions during 2012, see our 2012 Annual Report on Form 10-K.
Interest and Debt Expense— Interest and debt expense increased for the three months ended March 31, 2013 compared to the same period in 2012, primarily due to (i) higher outstanding balances on our credit facilities; and (ii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012.
The following table provides a summary of interest and debt expense (In thousands):
| | | | | | | | |
| | Three Months Ended March 31, | |
| | 2013 | | | 2012 | |
Interest cost: | | | | | | | | |
Credit Facilities | | $ | 6,990 | | | $ | 3,203 | |
Senior Notes | | | 4,390 | | | | 4,027 | |
Capital lease interest | | | 72 | | | | 49 | |
Other debt-related costs | | | (2 | ) | | | 369 | |
| | | | | | | | |
Total cost | | | 11,450 | | | | 7,648 | |
Less capitalized interest | | | — | | | | (91 | ) |
| | | | | | | | |
Interest and debt expense | | $ | 11,450 | | | $ | 7,557 | |
| | | | | | | | |
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Liquidity and Capital Resources
Our sources of liquidity include cash flows generated from operations, available borrowing capacity under each of the CMM and CMLP Credit Facilities, and issuances of additional debt and equity in the capital markets. We believe that our sources of liquidity will be sufficient to fund our short-term working capital requirements, capital expenditures and cash distributions for the remainder of 2012. The amount of distributions to unitholders is determined by the board of directors of our General Partner on a quarterly basis.
We regularly review opportunities for both acquisitions and greenfield growth projects that will enhance our financial performance. Since we distribute most of our available cash to our unitholders, we depend on a combination of borrowings under each of the CMM and CMLP Credit Facilities and debt or equity offerings to finance the majority of our long-term growth capital expenditures or acquisitions.
Management continuously monitors our leverage position and our anticipated capital expenditures relative to our expected cash flows. We continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or refinance outstanding debt balances with longer term notes.
Known Trends and Uncertainties Impacting Liquidity
Our financial condition and results of operations, including our liquidity and profitability, can be significantly affected by the following:
| • | | Concentration of Gathering Revenues from Quicksilver:We depend on Quicksilver for a substantial percentage of our current business. For the three months ended March 31, 2013, services to Quicksilver accounted for approximately 35% of our total revenues. In March 2013, Quicksilver announced the sale of approximately 25% of its interest in its Barnett Shale assets to TG Barnett Resources LP, a wholly-owned subsidiary U.S. subsidiary of Tokyo Gas Co., Ltd. Quicksilver will remain the operator of the assets. The risk of revenue fluctuations from Quicksilver in the near term is mitigated by the use of fixed-fee contracts for providing gathering, processing, treating and compression services; however, our revenues may be impacted by volume fluctuations. While our acquisitions reduce the concentration of risk associated with our dependency on one producer and one geographic area, we continue to regularly review opportunities for both acquisitions and greenfield growth projects in other producing basins and with other producers in the future. |
| • | | Access to Capital Markets: Our total borrowings under our credit facilities were $376 million as of March 31, 2013 and based on our results through March 31, 2013, our remaining available capacity under the CMLP Credit Facility and CMM Credit Facility was $179 million and $113 million, respectively. While we anticipate that our current available borrowing capacity under our credit facilities is sufficient to fund our planned level of growth capital spending for the remainder of 2013, additional debt and equity offerings may be necessary to fund additional acquisitions or other growth capital projects. During 2013, we have raised approximately $119 million through equity offerings to reduce indebtedness under each of the CMM and CMLP Credit Facilities and for general partnership purposes. |
| • | | Natural Gas Prices: Adding new volumes through our gathering systems is dependent on the drilling and completion activities of natural gas producers in our areas of operations. Although investment returns differ between natural gas basins, rich gas and dry gas reservoirs in certain natural gas basins and between various production companies, low natural gas prices may reduce the levels of drilling activity in areas around certain of our assets, particularly those that concentrate on gathering from dry gas reservoirs. We seek to mitigate this risk by diversifying into various geographical production basins with predominately rich gas natural gas reservoirs. We have observed that largely due to superior prices for crude oil and NGLs compared to natural gas, producers are shifting their drilling and development plans to focus on increasing production from rich gas basins or shale plays which offer better drilling economics as compared to production from dry gas basins. We have five systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems in the Avalon Shale; and (iv) two systems in the Marcellus segment. For three months ended March 31, 2013, these rich gas systems accounted for approximately 70% of our total revenues. We will continue to focus on expanding our business activities and opportunities in rich gas basins or rich gas shale plays due to the current trend of increased drilling and producer activities in these areas. |
| • | | Regulatory Requirements: Our operations and the operations of our customers are subject to complex and evolving federal, state, local and other laws and regulations. In April 2012, the United States Environmental Protection Agency issued a final rule establishing new emission limitations for certain oil and gas facilities. These rules establish emission standards for gas wells that are hydraulically fractured (or re-fractured). These rules also establish emissions standards for natural gas processing equipment, including compressors, controllers, storage tanks, and gas processing plants. These or other federal or state initiatives relating to hydraulic fracturing or other environmental matters could impact the extent of our operations and/or give rise to or accelerate the need for additional capital projects. In addition, any further changes in laws or regulations, or delays in the issuance of required permits, may further impact the volumes on our systems. |
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| • | | Impact of Inflation and Interest Rates: Although inflation in the United States has been relatively low in recent years, the United States economy may experience a significant inflationary effect in the future. Although inflation would negatively impact the cost of our operations and cash flows through services provided to us, the majority of our gathering and processing agreements allow us to charge increased rates based on indices expected to track such inflationary trends. Interest rates have also remained low in recent years, as compared with historical averages. Should interest rates rise, our financing costs would increase accordingly. In addition, as with other yield-oriented securities, our unit price would also be negatively impacted by higher interest rates. Higher interest rates would increase the costs of issuing debt or equity necessary to finance potential future acquisitions. However, our competitors would face similar circumstances and we expect our cost of capital to remain competitive. |
Cash Flows
The following table provides a summary of our cash flows by category (In thousands):
| | | | | | | | |
| | Three Months Ended March 31, | |
| | 2013 | | | 2012 | |
Net cash provided by operating activities | | $ | 34,034 | | | $ | 22,153 | |
Net cash used in investing activities | | | (24,273 | ) | | | (389,694 | ) |
Net cash provided by (used in) financing activities | | | (9,837 | ) | | | 369,439 | |
Operating Activities
During the three months ended March 31, 2013, we experienced an increase in our operating cash flows compared to the same period in 2012 primarily due to higher operating revenues as a result of our asset acquisitions during 2012 partially offset by higher operations and maintenances expenses on the acquired assets. In addition, our interest costs increased due to higher outstanding balances on our credit facilities and Senior Notes.
Investing Activities
The midstream energy business is capital intensive, requiring significant investments for the acquisition or development of new facilities. We categorize our capital expenditures as either:
| • | | expansion capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or |
| • | | maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets, extend their useful lives or comply with regulatory requirements. |
The following table summarizes our capital expenditures for the three months ended March 31, 2013. We anticipate that our expansion capital expenditures during 2013 will expand our gathering systems through additional pipelines to connect to new wells, purchase additional compression equipment and generally increase the capacity of our systems in each of our operating segments, primarily in the Marcellus segment.
| | | | |
| | (In millions) | |
Expansion capital | | $ | 22,382 | |
Maintenance capital | | | 921 | |
Other(1) | | | 970 | |
| | | | |
Total | | $ | 24,273 | |
| | | | |
(1) | Represents capital expenditures that are reimbursable from our insurers. |
In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for $258 million, which was funded through $129 million of borrowings under the CMLP Credit Facility and the issuance of approximately $129 million of equity to Crestwood Holdings. We believe this acquisition will increase our potential for long-term organic growth opportunities in the Marcellus Shale region.
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Financing Activities
Significant items impacting our financing activities during the three months ended March 31, 2013 included the following:
| • | | Net borrowings under our credit facilities of approximately $43 million; and |
| • | | $103.5 million in proceeds from the issuance of 4,500,000 common units in March 2013. |
During the three months ended March 31, 2013, we paid distributions to our unitholders of approximately $25 million, which increased by $4 million when compared to the same period in 2012. On April 1, 2013, all of the Class C units representing limited partner interests in us automatically converted into common units on a one-for-one basis. Quarterly distributions on these converted units will be paid in cash.
In April 2013, we issued an additional 675,000 common units pursuant to an underwriter’s option to purchase additional units in connection with the March 2013 public offering of 4,500,000 common units, and received net proceeds of approximately $15.5 million, which was used to reduce our indebtedness under each of the CMM and CMLP Credit Facilities.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2012 Annual Report on Form 10-K.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
As of March 31, 2013, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Interim Chief Financial Officer of our General Partner, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including the Chief Executive Officer and Interim Chief Financial Officer of our General Partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our Chief Executive Officer and Interim Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2013.
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 three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.
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PART II — OTHER INFORMATION
Item 1. Legal Proceedings
See Part I, Item 1. Financial Statements, Note 7, which is incorporated herein by reference.
Item 1A. Risk Factors
Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2012 Annual Report on Form 10-K under Part I, Item 1A. Risk Factors. There have been no material changes in our risk factors since that report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not Applicable.
Item 5. Other Information
On May 3, 2013, Crestwood Holdings Partners, LLC and Mr. Steven M. Dougherty entered into a letter agreement setting forth the compensation arrangements related to Mr. Dougherty’s appointment as the Company’s Senior Vice President and Interim Chief Financial Officer. Pursuant to the letter agreement, Mr. Dougherty’s annual base salary has been set at $275,000 and he is eligible to receive a bonus that will be paid annually in cash up to a target bonus amount of 60% of his base salary.
The foregoing description about the letter arrangement is qualified in its entirety by reference to the letter arrangement, a copy of which is filed as Exhibit 10.2 to this Form 10-Q.
Item 6. Exhibits:
The exhibit index is incorporated herein by reference into this Quarterly Report on Form 10-Q.
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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.
| | | | | | |
| | | | CRESTWOOD MIDSTREAM PARTNERS LP |
| | |
| | | | By: CRESTWOOD GAS SERVICES GP LLC, its General Partner |
| | | |
Date: May 7, 2013 | | | | By: | | /s/ Steven M. Dougherty |
| | | | | | Steven M. Dougherty |
| | | | | | Senior Vice President – Interim Chief Financial Officer and Chief Accounting Officer |
| | | | | | (Principal Financial and Accounting Officer) |
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EXHIBIT INDEX
Exhibits designated by an asterisk (*) are filed herewith and those with (**) are furnished and not filed herewith. Exhibits designated by a plus (+) represent a management contract or compensatory plan or arrangement.
| | |
Exhibit No. | | Description |
| |
2.1 | | Contribution, Conveyance and Assumption Agreement, dated January 8, 2013, by and among Crestwood Midstream Partners, LP, Crestwood Marcellus Holdings LLC, Crestwood Gas Services GP LLC, Crestwood Holdings LLC, Crestwood Gas Services Holdings LLC, and Crestwood Marcellus Pipeline LLC (filed as Exhibit 2.1 to Crestwood Midstream Partners LP’s Form 8-K filed January 8, 2013, and included herein by reference). |
| |
3.1 | | Third Amendment to Second Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP, effective January 8, 2013 (filed as Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed January 8, 2013, and included herein by reference). |
| |
+10.1 | | Separation Agreement and Release, dated February 5, 2013, by and among Crestwood Midstream Partners LP, Crestwood Gas Services GP LLC and Crestwood Holdings Partners, LLC and William G. Manias (filed as Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed February 8, 2013, and included herein by reference). |
| |
+10.2 | | Letter Agreement dated May 3, 2013, between Crestwood Holdings Partners, LLC and Steven M. Dougherty. |
| |
*12.1 | | Computation of Ratio of Earnings to Fixed Charges |
| |
*31.1 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
*31.2 | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
*32.1 | | Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
**101.INS | | XBRL Instance Document |
| |
**101.SCH | | XBRL Taxonomy Extension Schema Linkbase Document |
| |
**101.CAL | | XBRL Taxonomy Extension Calculation Linkbase Document |
| |
**101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document |
| |
**101.LAB | | XBRL Taxonomy Extension Labels Linkbase Document |
| |
**101.PRE | | XBRL Taxonomy Extension Presentation Linkbase Document |
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